OKLAHOMA CITY, March 11, 2010 (GLOBE NEWSWIRE) -- GMX Resources Inc., (NYSE

:GMXR - News) (visit www.gmxresources.com to view the most recent Company presentation and for more information on the Company) today announces restatement of year end 2008 and quarterly 2009 earnings, reports financial and operating results for the quarter and year ended December 31, 2009, and declares quarterly cash dividend on its 9.25% Series B Cumulative Preferred Stock.

Restatement of Year End 2008 and Quarterly 2009 Earnings

GMXR

is correcting a non-cash charge for the method used to record its previous full cost pool impairment charges, other impairment charges and related deferred income taxes that adjusts the Company's earnings under Generally Accepted Accounting Principles (GAAP) for the year ended 2008 and for the first three quarters of 2009. In addition, the Company has adjusted its previously reported GAAP diluted loss per share for such periods to remove the effects of dilutive securities in calculating diluted loss per share. As a result of these adjustments, the Company's restated net loss for the year ended December 31, 2008 was $124.6 million as compared to the originally reported $81.7 million (net loss of $83.0 as adjusted for the retrospective adoption of a change in accounting for the Company's 5.00% Convertible Notes). The restatement changes are reflected in the amounts and financial statements included in this press release. The prior errors were determined during the preparation and independent audit of the Company's December 31, 2009 financial statements. Based on the errors in the 2008 year-end and 2009 quarterly financial statements, the Company's Audit Committee concluded on March 10, 2010, that such financial statements should no longer be relied upon. The Company will reflect all of the corrections in its forth coming Form 10-K for the year ended December 31, 2009 to be filed with the Securities and Exchange Commission ("SEC") on or about March 16, 2009, based on informal advice the Company has received from the SEC.

These non-cash charges have no impact on the Company's SEC PV-10 values at either December 31, 2008 or in any of the previously reported quarters in 2009. The resource potential of the Company's high-quality asset base in both the Haynesville Shale and Cotton Valley intervals remains technically and economically recoverable.

Financial Results for the Three Months and Year Ended December 31, 2009

GMXR

reported a net loss applicable to GMXR shareholders of $49.3 million for the three months ended December 31, 2009 as compared to 2008's fourth quarter net loss applicable to GMXR shareholders of $154.0 million. Diluted loss per share for the three months ended December 31, 2009 was $1.90 per share compared to $10.04 per share for the fourth quarter of 2008. Adjusted net income (loss) available to GMXR shareholders for the three months ended December 31, 2008 and 2009, a non-GAAP measure adjusting for such items as unrealized derivative gains and losses, impairment charges on oil and natural gas properties and a loss on extinguishment of debt for the fourth quarter of 2009 on oil and natural gas properties is broken out as follows:

	Three Months Ended December 31,
	2009	2008 (as adjusted and restated)
	(unaudited)
(in thousands, except for per share amounts)	Amount	Per share(1)	Amount	Per share(1)
Net loss applicable to GMXR shareholders	$(49,311)	$(1.90)	$(153,978)	$(10.04)
Adjustments:
Impairment of oil and natural gas properties, net of taxes of $65,501 for 2008	50,072	1.87	127,149	8.28
Deferred income tax valuation allowance	--	--	26,075	1.70
Unrealized (gain) loss derivatives net of taxes of $120 for 2008	(457)	(0.02)	234	0.01
Loss on extinguishment of debt	4,976	0.19	--	--
Adjusted net income (loss) applicable to GMXR shareholders	$5,280	$0.20	$(520)	$(0.04)

^{(1) Per share amounts are calculated on a fully dilutive basis. The net loss applicable to GMXR shareholders does not include the effects of convertible securities, restricted stock or stock options due to the net loss position as the effects of these would be antidilutive. The per share amounts for the adjustments are calculated including the effects of convertible securities, restricted stock and stock options assuming a net income position where the cumulative effect of the adjustments would have resulted in a net income from continuing operations.}

The Company's fourth quarter results were positively impacted by increased production from the Haynesville/Bossier ("H/B") horizontal ("Hz") drilling program which began to replace the Cotton Valley Sand ("CVS") vertical drilling program in the third quarter of 2008. These results were offset in part by lower prices for crude oil and natural gas. GMXR's production from its East Texas operations in the fourth quarter of 2009 increased 9% to 3.6 billion cubic feet equivalent of natural gas ("Bcfe") as compared to production of 3.3 Bcfe in the fourth quarter of 2008. The fourth quarter average daily production rate of 39.1 million cubic feet of natural gas equivalent ("Mmcfe") was 3% more than the third quarter 2009 production rate of 37.9 Mmcfe per day. The increase is due to the production from three new H/B Hz wells coming on line, one in late October and two in December, and the addition of a second rig beginning in mid October, 2009. GMXR's average realized oil prices in the fourth quarter of 2009 increased to $88.27 per barrel, 70% higher than the $52.03 per barrel average realized price in 2008's fourth quarter. Oil prices in the fourth quarter of 2009 were higher than the average price of $80.82 per barrel realized during the third quarter of 2009. Natural gas prices realized in the fourth quarter of 2009 averaged $6.74 per thousand cubic feet ("Mcf"), 7% lower than the $7.22 per Mcf realized in fourth quarter of 2008. Natural gas prices in the fourth quarter of 2009 were higher than the average price of $6.26 per Mcf realized during the third quarter of 2009. Oil and natural gas sales in the fourth quarter of 2009 of $25.6 million increased 6% from 2008's fourth quarter sales of $24.1 million as the production increase was largely offset by lower natural gas prices.

Among non-GAAP measures, discretionary cash flow generated by GMXR in the fourth quarter of 2009 was $11.5 million, an increase of 18% over 2008's fourth quarter non-GAAP discretionary cash flow of $9.6 million. EBITDA, or earnings before interest, taxes, depreciation, depletion, amortization (including the impairment charge to oil and natural gas properties) was $16.1 million in the fourth quarter of 2009 compared to 2008's fourth quarter EBITDA of $13.6 million.

GMXR reported net loss applicable to GMXR shareholders of $185.3 million for the year ended December 31, 2009 as compared to 2008's annual net loss applicable to GMXR shareholders of $129.3 million. Results for 2009 and 2008 included impairment charges of $188.1 million and $192.7 million, respectively, related to the Company's oil and natural gas properties. Non-GAAP adjusted net income (loss) available to GMXR shareholders for the year ended December 31, 2008 and 2009, adjusting for such items as unrealized derivative gains and losses, impairment charges on oil and natural gas properties and a loss on extinguishment of debt is as follows:

	Year Ended December 31,
	2009	2008 (as adjusted and restated)
	(unaudited)
(in thousands, except for per share amounts)	Amount	Per share(1)	Amount	Per share(1)
Net loss applicable to GMXR shareholders	$(185,264)	(9.17)	$(129,262)	(9.09)
Adjustments:
Impairment on oil and natural gas properties, net of taxes of $65,501 for 2008	188,150	8.96	127,149	8.36
Deferred income tax valuation allowance	--	--	26,075	1.71
Unrealized (gain) loss on derivatives net of taxes of $120 for 2008	2,370	0.11	234	0.02
Loss on extinguishment of debt	4,976	0.24	--	--
Bad debt expense, net of taxes of $254 in 2008	486	0.02	494	0.03
Adjusted net income (loss) applicable to GMXR shareholders	$10,718	0.53	$24,690	1.62

^{(1) Per share amounts are calculated on a fully dilutive basis. The net loss applicable to GMXR shareholders does not include the effects of convertible securities, restricted stock or stock options due to the net loss position as the effects of these would be antidilutive. The per share amounts for the adjustments are calculated including the effects of convertible securities, restricted stock and stock options assuming a net income position where the cumulative effect of the adjustments would have resulted in a net income from continuing operations.}

The full year 2009 financial results reflect lower overall oil and natural gas prices, offset in part by a small production growth. Though fewer drilling rigs were used, and the CAPEX was much lower than in 2008, GMXR was able to increase production in 2009 by 5% to 13.6 Bcfe as compared to production of 12.9 Bcfe in 2008. Realized oil prices in 2009 averaged $76.02 per barrel, 15% lower than the $88.97 per barrel realized in 2008. Natural gas prices in 2009 averaged $6.61 per Mcf, 28% lower than the $9.24 per Mcf realized in 2008. Oil and natural gas sales of $94.3 million during 2009 decreased 25% from sales in 2008 of $125.7 million. Among non-GAAP measures, discretionary cash flow generated by GMXR in 2009 of $50.3 million decreased 32% from 2008's non-GAAP discretionary cash flow of $73.7 million, and EBITDA of $66.0 million in 2009 decreased 27% from EBITDA in 2008 of $90.3 million.

2009 4th Quarter and Full Year Operational Results

GMXR completed and brought online 11 H/B Hz wells in 2009, two of which had previously reached total depth ("TD") in late 2008. One other well was a partial completion in 2009. The casing failed during the second frac stage and a decision was made to shut the well in and wait on an economic pipeline connection. Additionally, GMXR drilled a vertical H/B well in 2009 and is awaiting final core analysis before drilling the lateral. Two other H/B Hz wells reached TD in 2009 but not in time for completion in 2009.

GMXR spud 5 H/B Hz wells during the 4^th quarter, and three H/B Hz wells were completed.

On average the 2009 completed wells produced 5,136 Mcf per day in the first 30 days of production; all of the wells were produced on a restricted choke to avoid excessive closure pressure during early flow time. During the 4th quarter, GMXR completed three wells that averaged 4,747 Mcf per day for the first 30 days.

The Company made considerable progress in reducing drilling days (spud to TD) over the year and especially during the 4^th quarter. The most recent four wells using the 4 1/2" production casing have been drilled in 37, 32, 26 and 30 days.

2009 Production and Year End Proved Reserves

GMXR produced 13.6 Bcfe in 2009 as compared to 12.9 Bcfe in 2008, a 5% increase. Fourth quarter production was approximately 3.6 Bcfe compared to 3.3 Bcfe in the same quarter of 2008, a 9% increase. Production from the Company's H/B Hz wells comprised 16.1 MMcfe per day of the total 39.1 MMcfe per day production rate in the fourth quarter of 2009. The H/B Hz wells comprised only 1.7 MMcfe per day of the Company's production during the fourth quarter of 2008.

GMXR grew production 5% in 2009 while spending only $178 million in CAPEX, a 46% reduction compared to 2008; this production increase in spite of the CAPEX reduction was due mainly to the combination of three factors: (a) the higher production associated with each H/B HZ well compared to CVS vertical wells, (b) the Company's completing of 11 H/B HZ wells in 2009 compared to completing one H/B HZ well and 89 CVS vertical wells in 2008, and (c) the reduction in active drilling rigs from seven to one in response to the rapid decline in natural gas prices and difficult credit markets.

For year-end 2009, new SEC rules were implemented requiring that the reserve calculations be based on the average prices throughout the year, versus the previous method which required year-end prices. The benchmark cash prices under the new method were $3.87 per Mmbtu for natural gas, and $61.19 per barrel of oil, representing the simple average of the prices for the first day for each month of 2009.

Below is a roll forward of our year end proved reserves. We have shown both the changes under the new SEC rules, as well as what the changes would have been using the year end natural gas and oil prices, which was the requirement of the SEC in 2008.

	Proved Reserves	Proved Reserves
	Using New SEC	Using Year End
	2009 Prices	Market Prices
	(Bcfe)	(Bcfe)
Proved Reserves at December 31, 2008	465.3	465.3
2009 Production (wellhead)	(13.7)	(13.7)
2009 Acquisitions / Divestitures	0.0	0.0
2009 Elimination of Non-Op PUDs	(53.0)	(53.0)
2009 Price Based Revisions	(15.6)	2.5
2009 Non-Price Based Revisions	(53.6)	(55.8)
2009 Reserve Additions & Extensions	25.9	108.6
Proved Reserves at December 31, 2009	355.3	453.9
2009 Reserve Replacement Ratio (%)	189%	792%
2009 Oil and Gas Expenditures (million $)	$151.0	$151.0
2009 Finding Costs ($ per Mcfe)	$5.83	$1.39

Under the new SEC rules, 2009 proved reserves for the Company are estimated at 355.3 Bcfe and the pre-tax discounted, at 10%, present value (PV10) of the year-end 2009 reserves was $189 million. Using the previous SEC pricing method (year-end benchmark prices of $5.79 per Mmbtu and $79.39 per barrel of oil), 2009 proved reserves would have been 453.9 Bcfe and the PV10 value would have been $527 million. Using the three-year futures strip prices at December 31, 2009, plus the impact of the Company's natural gas price revenue floors, 2009 proved reserves would have been 454.2 Bcfe and the PV10 value would have been $548 million.

In addition to the new SEC rules regarding prices, the SEC also implemented new rules regarding proved undeveloped reserves. The rule change allows for additional drilling locations to be classified as proved undeveloped reserves assuming such locations are supported by reasonable technical criteria. In 2009, the Company elected to reduce its CVS proved undeveloped reserves (PUDs) and transfer certain PUDs associated with its non-operated acreage, to another internal reserve category. One of our internal objectives was to reduce our PUD percentage from 65% down to 63% in 2009, with a target of 50% over the next few years. Also we wanted to continue to increase our proved developed reserve (PD) percentage of proved reserves from 35% to 37% with a target of 50% over the next few years as well. Transition from drilling CVS PUDs to drilling the H/B Hz PUDs in the future, utilizing three Helmerich and Payne FlexRig 3(TM) rigs in 2010 compared to one Helmerich and Payne FlexRig 3(TM) for most of 2009, should grow our proved reserves. Our current ratio of PUD to PD is only 1:1.

Under the new SEC rules, GMXR's finding and development costs averaged $5.83 per Mcfe due largely to the exclusion of any H/B Hz PUDs other than the Mia Austin #1H. Using the previous SEC rules, GMXR's finding and development costs would have been $1.39 per Mcfe.

Under the new SEC rules, GMXR replaced 189% of production in 2009 with all the reserve replacement occurring through the drill bit. Using the previous SEC rules, GMXR would have replaced 792% of production in 2009 with all the reserve replacement occurring through the drill bit.

GMXR's H/B Hz drilling program was the primary driver of the growth in production and reserve discoveries. These additions were offset by downward revisions primarily attributable to the new SEC pricing rules and the Company's decision to transfer certain proved undeveloped reserves related to both non-operated CVS locations, and operated locations that are not expected to be drilled within the prescribed five year period required by the new SEC rules.

Under the new SEC rules, at the end of 2009, 37% of the Company's proved reserves were classified as proved developed, compared with 35% at the end of 2008. At the end of 2009, the Company had 331 CVS locations classified as PUDs and 335 producing CVS wells. Additionally, although we have 12 producing H/B Hz wells, we booked only one H/B Hz PUD. Our ratio of PUDs to PDP is 1:1 which is very conservative compared to some companies. Natural gas accounts for 94% of the 2009 year end reserves. GMXR operates 84% of its developed and undeveloped reserve base.

The Company has natural gas revenue floors on 77%, 62%, and 58% of expected production under a three rig drilling program at weighted average prices of $6.43, $6.14, and $6.08 for 2010, 2011, and 2012 respectively. The Company does not anticipate the reduction in proved reserves due to the new SEC rules will impact the Company's borrowing base under its revolving line of credit since the borrowing base is determined based on proved developed reserves. Also, the current borrowing base methodology for reserve loan value includes the impact of the revenue floors, and uses gas prices that are higher than the $3.86 SEC price.

2010 Budget and Guidance and Update

GMXR's 2010 CAPEX budget is forecasted at $175 million, the substantial majority of which will be used to drill approximately 22 wells of which 20 will be H/B Hz wells and 2 will be CVS Hz wells. The Company is negotiating with third parties on participation, farm-ins and acreage exchange agreements. Execution of these agreements throughout the year could allow us to reduce our CAPEX further. Our YE2010 production guidance is 17.5 Bcfe, a 30% increase over YE2009. Forecast production for Q1 2010 is estimated between 3.2 Bcfe and 3.3 Bcfe. The first quarter of 2010 will see some increase from deployment of a second rig and the second quarter 2010 will see all three H/B Hz rigs deployed and growing production.

The Mia Austin #1H (4 1/2" casing) was completed in February. The well had an Initial Production ("IP") rate, during a 24 hour test, of 14.1 Mmcfe per day on a choke size of 20/64" with flowing tubing pressure of 5,492 psi ("Pounds Per Square Inch") into a sales line which had 850 psig. We project this well will average over 7.5 Mmcfe per day for its first 30 days. The Verhalen E#1H (4 1/2" casing) was recently completed and had an IP during a 24 hour test of 8.3 Mmcf per day with 3,870 psi of tubing pressure on a 18/64" choke into a 640 psig sales line. We expect two additional completions during March and April, 2010.

The Company is currently drilling with three Helmerich and Payne FlexRig 3(TM) rigs and is scheduled to take delivery of a fourth FlexRig 3(TM) on March 25, 2010. The Company expects to defer the activation of the fourth rig by entering into a sublease agreement with another operator; this will allow us to begin the official contract period and defray the majority of the contracted day rate until the expiration of the sublease or such time as we call back the rig from the sub-lessee and choose to expand our drilling program to four rigs.

During 2009 the Company reduced its average spud to TD from 70 days to 30 days by utilizing the H & P FlexRig 3(TM) and improving other efficiencies. Completed well costs dropped precipitously from $10 million per well to $6.2 million per well. We expect to continue in 2010 to maintain and improve cost saving measures though out the program.

Move to Drilling Larger Well Bores

On December 28, 2009, the Company spud its first larger diameter wellbore designed to accommodate 5 1/2" production casing. The larger 5 1/2" casing facilitates a reduction in perforation cluster spacing which will improve the capability of stimulating the entire lateral length, all the while keeping the total number of frac stages at current levels. Data suggests that improved well performance is related to the reduction in perforation cluster spacing and with the larger casing, improved well performance is anticipated without an increase in stimulation cost. The first wells in this program, the Verhalen D#3H, and the Bosh 19H should have results in April 2010. The Blocker Heirs #20H, and the Verhalen E#6H, and the Blocker Ware 8H are currently drilling. Our current estimate for spud to TD of the larger diameter wells is approximately 44 days. However, we believe that we will gain efficiencies with additional drilling (similar to efficiencies we achieved in 2009 under the 4 1/2" casing program) and will reduce the spud to TD time down to approximately 35 days. The reduction in drilling days will lower our completed well costs by approximately $75,000/day.

Cash Dividend on Its 9.25% Series B Cumulative Preferred Stock

GMXR will pay a regular quarterly dividend of $0.578125 per share on March 31, 2010 to holders of record as of March 19, 2010 on the 2,000,000 outstanding shares of its 9.25% Series B Cumulative Preferred Stock.

Derivative Update

Since September

30, 2009, the Company has taken additional measures to protect against future declines in natural gas prices during 2010, 2011, and 2012, as listed below.

• The Company purchased $6.00 NYMEX natural gas put options totaling 1.9 Bcf for the months of May through December 2010. To minimize cash outflow associated with buying the natural gas put option, the Company sold natural gas put options at $4.00 NYMEX.
  
• The Company purchased a $6.00 NYMEX natural gas put option for 11.0 Bcf spread evenly across 2011. To minimize cash outflow associated with buying the natural gas put option, the Company sold 6.43 Bcf of 2011 natural gas put options at $4.00 NYMEX.
  
• In January 2010, the Company purchased a natural gas put spread option for 1.40 Bcf spread evenly across in 2011. The bought put option has a $6.25 NYMEX strike price, and the sold put option has a $4.50 NYMEX strike price.
  
• The Company purchased a $6.00 NYMEX natural gas put option for 13.44 Bcf spread evenly across 2012. To minimize cash outflow associated with buying the natural gas put option, the Company sold 7.8 Bcf of 2012 natural gas put options at $4.00 NYMEX.
  
• In January 2010, the Company purchased natural gas put spread option for 2.62 Bcf spread evenly across in 2012. The bought put option has a $6.25 NYMEX strike price, and the sold put option has a $4.50 NYMEX strike price.

Based on the recent trades listed above, other trades previously executed, and our internal forecasts, 77% of our 2010 estimated production of 17.5 Bcfe is protected at an average price of $6.43; 62% of our 2011 estimated production of 24.1 Bcfe is protected at an average price of $6.14; and 58% of our 2012 estimated production of 29.0 Bcfe is protected at an average price of $6.08.

We will continue to look for opportunities to reduce price risk in 2011 and 2012 as we add production through our H/B Hz drilling program. In addition, as we increase our production from the drilling of new wells, we anticipate selling natural gas calls on the put volumes we have purchased in years 2010 through 2012 to recover the cost of these puts. The cost of purchasing these puts have been deferred until the month the contract is settled.

Management Comment

Ken L. Kenworthy, Jr. Chairman and Chief Executive Officer, said "2009 was an anomalous year in many respects for GMXR. Unfortunately, we needed to re-state several earlier periods and had mixed financial results for 2009. We had the good fortune of being in the right play and capably transitioning from a vertical CVS developer to H/B Hz developer. Our hedges allowed us to achieve a $6.61 per Mcf sales price, and reduce the economic impact of falling prices. The potential of the H/B play was confirmed in the form of growing production with only 1 rig, drilling 12 H/B Hz wells in 2009 at a CAPEX of $178 million vs. 7 rigs and drilling 89 CVS wells at a CAPEX of $323 million in 2008. By reducing our drilling and completion costs 54% during the year we also managed to deliver best results with our most successful well, the Mia Austin #1H. The well began production in early February and will produce 0.23 Bcf in its 1^st month, a 40% improvement when compared to our best completions. It is one of the highest producing wells in East Texas and it along with the surrounding successful wells confirms the opportunity we have on our property base.

In 2009, we accessed the most difficult capital markets in the last 75 years and successfully raised enough capital to fund the Company's current drilling plan. Additionally we sold a 40% interest in our pipeline LLC to a solid pipeline company. Our liquidity has never been better in our company's history. We are scheduled to drill and complete 20 H/B Hz wells in 2010 and 2 CVS Hz wells which will continue to highlight the multi-tier value of our property base. Our Audit Committee hired a national accounting firm as our independent auditors and we became a NYSE

Listed Company. We have added several key employees with extensive Haynesville Bossier and gas shale experience. Our property base is held by production, our improved drilling, completion, operational and reservoir expertise, our strong liquidity position, our $6 plus revenue floors, our financial discipline and company-wide focus on cost control are all factors that will contribute to our ability to drill and produce economically attractive wells that will increase shareholder value. We should produce 29% more natural gas in 2010 than we did in 2009 with no increase in CAPEX. This is the great multiplying effect of drilling horizontal wells particularly, producing from the H/B Formation."

GMXR Fourth Quarter and Annual 2009 Earnings Conference Call

GMXR has scheduled a conference call for Friday, March 12, 2010 at 10:00 a.m. CST (11:00 a.m. EST) to discuss fourth quarter and annual 2009 financial and operating results. To access the call, dial (877) 303-9132 or (408) 337-0136 before the call begins. Please reference Passcode 58696006. A replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until March 18, 2010. To access the replay, please dial (800) 642-1687 or (706) 645-9291 and reference passcode 58696006. The corporate presentation being used for this call is available for download at http://www.gmxresources.com under the Events and Presentation tab.

Full Year and Fourth Quarter 2009 Highlights

Operational results for the year ended December 31, 2009 included the following:

Recorded oil and natural gas production of 13.6 Bcfe, or 37.3 Mmcfe per day, an increase of five percent over 12.9 Bcfe, or 35.3 Mmcfe per day, in 2008, while spending substantially less capital expenditures in 2009 compared to 2008;

Achieved a reserve replacement ratio of 189% under the new SEC rules, or 792% under the prior rules. Finding and development costs are $1.39 based on the SEC's previous end of year price rules, which allowed our H/B proved undeveloped reserves to be economic;

Spud 13 Haynesville/Bossier ("H/B") horizontal shale wells, hit TD on 13 H/B Hz wells, and brought online 11 H/B Hz wells.

Operational results for the fourth quarter of 2009 include the following:

Quarterly oil and natural gas production in the fourth quarter of 2009 was 3.6 Bcfe or 39.1 Mcfe per day representing production growth of 3% from 3.3 Bcfe, or 35.7 Mcfe per day, in the fourth quarter of 2008.

Hit total depth on the Mia Austin #1H which was completed in early 2010, which is one of the largest wells in east Texas;

Spud four H/B Hz wells, hit TD on four H/B Hz wells, and brought online three H/B Hz wells, with remaining well brought online in the first quarter of 2010.

GMXR

Summary Operating Data for the Three and Twelve Months Ended December 31, 2009

	Three Months Ended December 31,	Twelve Months Ended December 31,
	2008	2009	2008	2009
	(unaudited)	(unaudited)
Production:
Oil (MBbls)	40	28	190	119
Natural gas (Mmcf)	3,044	3,430	11,777	12,908
Gas equivalent production (MMcfe)	3,286	3,597	12,918	13,620
Average daily (MMcfe)	35.7	39.1	35.3	37.3
Average Sales Price:
Oil (per Bbl)
Wellhead price	$55.60	$74.45	$99.16	$56.61
Effect of hedges	(3.57)	13.82	(10.19)	19.41
Total	$52.03	$88.27	$88.97	$76.02
Natural gas (per Mcf)
Wellhead price	$6.34	$4.45	$9.50	$3.85
Effect of hedges	0.88	2.29	(0.26)	2.76
Total	$7.22	$6.74	$9.24	$6.61
Average sales price (per Mcfe)	$7.33	$7.11	$9.73	$6.92
Operating and Overhead Costs (per Mcfe):
Lease operating	$1.35	$0.89	$1.17	$0.86
Production and severance taxes	0.18	0.04	0.41	(0.07)
General and administrative	1.50	1.89	1.31	1.57
Total	$3.03	$2.82	$2.89	$2.36
Cash Operating Margin (per Mcfe)	$4.30	$4.28	$6.84	$4.56
Other (per Mcfe):
Depreciation, depletion and amortization - oil and natural gas properties	$2.29	$1.77	$2.08	$1.76

Results of Operations -- Three Months Ended December 31, 2009 Compared to Three Months Ended December 31, 2008

Oil and Natural Gas Sales.

Oil and natural gas sales in the three months ended December 31, 2009 increased 6% to $25.6 million compared to the three months ended December 31, 2008. This was due to an increase in oil and natural gas production of 9%, offset by a 3% reduction in prices. The average price per barrel of oil and Mcf of natural gas received in the three months ended December 31, 2009 was $88.27 and $6.74, respectively, compared to $52.03 and $7.22, respectively, in the three months ended December 31, 2008. Production of oil for the three months ended December 31, 2009 decreased to 28 MBbls from 40 MBbls for the three months ended December 31, 2008. Natural gas production for the three months ended December 31, 2009 increased to 3,430 Mmcf compared to 3,044 Mmcf for the three months ended December 31, 2008, an increase of 13%. Greater production of natural gas in the three months ended December 31, 2009 was the result of the transition from vertical drilling in the Cotton Valley Sands formation to drilling H/B Hz wells, which began in the third quarter of 2008. We expect continued increases in production as we expand our H/B Hz drilling program in 2010.

In the three months ended December 31, 2009, as a result of hedging activities, we recognized an increase in oil sales of $383,000 and an increase in natural gas sales of $7.8 million, compared to a decrease in oil sales of $144,000 and an increase in natural gas sales of $2.7 million in the three months ended December 31, 2008. In the fourth quarter of 2009, hedging increased the average oil sales price by $13.82 per Bbl and increased natural gas sales price by $2.29 per Mcf compared to a decrease in the average oil sales price by $3.57 and an increase in natural gas sales price of $0.88 per Mcf in the fourth quarter of 2008.

Lease Operations.

Lease operations expense decreased $1.3 million, or 28%, for the three months ended December 31, 2009 to $3.2 million, compared to the three months ended December 31, 2008. The decrease in lease operating expenses resulted from cost control measures implemented during 2009. Lease operations expense on an equivalent unit of production basis was $0.89 per Mcfe in the three months ended December 31, 2009 compared to $1.35 per Mcfe for the three months ended December 31, 2008. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in H/B Hz well production and cost control measures implemented in 2009. With little to no incremental increase in lease operating costs from a typical Cotton Valley vertical well, the significantly larger amount of production from a typical H/B Hz well results in lower per unit lease operating costs. Lease operations expense will continue to grow throughout 2010 as the number of producing wells increase. However, we expect lease operations expense on a per unit basis to decline during 2010 as production comes on line from our H/B Hz drilling program.

Production and Severance Taxes.

Production and severance taxes decreased 76% to $144,000 in the three months ended December 31, 2009 compared to $597,000 in the three months ended December 31, 2008. Production and severance taxes are assessed on the value of the oil and natural gas produced. The decrease resulted from lower oil and natural gas sales prices. Additionally, a growing number of wells with natural gas production are exempt from severance taxes or have reduced severance tax rates. Upon approval from the State of Texas, certain wells are exempt from severance taxes or eligible for a reduced severance tax rate for a period of ten years.

General and Administrative Expense.

General and administrative expense for the three months ended December 31, 2009 was $6.8 million compared to $4.9 million for the three months ended December 31, 2008. The increase of $1.9 million, or 39%, was due to an increase in administrative and supervisory personnel, discretionary bonuses paid in the fourth quarter of 2009, as well as in an increase in corporate operating expenses due to our expected growth. General and administrative expense per equivalent unit of production was $1.89 per Mcfe for the three months ended December 31, 2009 compared to $1.50 per Mcfe for the comparable period in 2008. We do not expect general and administrative expense to increase significantly in 2010 on a per unit basis.

Depreciation, Depletion and Amortization.

Depreciation, depletion and amortization expense decreased $1.2 million, or 14%, to $7.8 million in the three months ended December 31, 2009. The oil and natural gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.77 per Mcfe in the three months ended December 31, 2009 compared to $2.29 per Mcfe in the three months ended December 31, 2008. The decrease is due to a lower depreciable base as a result of impairment charges recorded against the full-cost pool at year end 2008 and during 2009.

Impairment of Oil and Natural Gas Properties.

As a result of lower oil and natural gas prices, we recognized an impairment charge on oil and natural gas properties of $50.1 million in the three months ended December 31, 2009 compared to $192.7 million in the three months ended December 31, 2008. We may be required to recognize additional impairment charges in future reporting periods if the market prices for oil and natural gas continue to decline.

Interest.

Interest expense for the three months ended December 31, 2009 was $4.0 million compared to $3.3 million for the three months ended December 31, 2008. This increase is due to a greater amount of outstanding debt during the three months ended December 31, 2009.

Loss on Extinguishment of Debt.

In October 2009, we entered into an amendment with the Prudential Insurance Company of America ("Prudential"), pursuant to which Prudential agreed to accept repayment of its senior secured subordinated notes with the proceeds of our offering of 4.50% convertible notes. We repaid all the senior secured subordinated notes on October 29, 2009. As a result of prepaying the senior secured subordinated notes, we recognized a charge of approximately $5.0 million related to the early pay-off of the notes.

Results of Operations -- Year ended December 31, 2009 Compared to Year ended December 31, 2008

Oil and Natural Gas Sales.

Oil and natural gas sales in the year ended December 31, 2009 decreased 25% to $94.3 million compared to the year ended December 31, 2008. This decrease is due to lower natural gas and oil prices of 29%, offset by a 5% increase in natural gas and oil production. The average prices per barrel of oil and Mcf of natural gas received in the year ended December 31, 2009 were $76.02 and $6.61, respectively, compared to $88.97 and $9.24, respectively, in the year ended December 31, 2008. Production of oil decreased to 119 MBbls compared to 190 MBbls for 2008. The decrease in oil production is due to the natural decline in our Cotton Valley Sand vertical well production which has historically provided most of the our oil production. H/B Hz wells typically do not have oil production. Natural gas production increased to 12,908 MMcf for 2009 compared to 11,777 MMcf for the year ended December 31, 2008, an increase of 10%. The increase in natural gas production resulted from production related to 12 producing H/B Hz wells that were on-line during 2009. Production from H/B Hz wells accounted for 33% of total production for 2009 compared to 1% for 2008.

In the year ended December 31, 2009, as a result of hedging activities, we recognized an increase in oil and natural gas sales of $37.9 million, compared to a decrease in oil and natural gas sales of $5.0 million in the year ended December 31, 2008. In the year ended December 31, 2009, hedging increased the average natural gas and oil sales price by $2.76 per Mcf and $19.41 per Bbl compared to a reduction of the average natural gas and oil sales price by $0.26 per Mcf and $10.19 per Bbl in the year ended December 31, 2008.

Lease Operations.

Lease operations expense decreased $3.3 million in the year ended December 31, 2009 to $11.8 million, a 22% decrease compared to the year ended December 31, 2008. Lease operations expense on an equivalent unit of production basis was $0.86 per Mcfe in the year ended December 31, 2009 compared to $1.17 per Mcfe for the year ended December 31, 2008. The decrease in lease operating expenses resulted from cost control measures implemented during 2009. With little to no incremental increase in lease operating costs from a typical Cotton Valley vertical well, the significantly larger amount of production from a typical H/B Hz well results in lower per unit lease operating costs.

Production and Severance Taxes.

As a result of the recognition of severance tax refunds of approximately $2.9 million in 2009, production and severance taxes decreased 118% from an expense of $5.3 million in the year ended December 31, 2008 to income of $0.9 million in the year ended December 31, 2009. Upon approval by the State of Texas, certain high cost wells, including our H/B Hz wells, are exempt from severance taxes for a period of ten years and we expect this to reduce our expense going forward. Excluding the production and severance tax refunds received in 2009, production and severance tax expense decreased in comparison to 2008 due to a decrease in oil and natural gas prices between the two periods and the fact that more producing wells in 2009 have received the production and severance tax exemptions.

General and Administrative Expense.

General and administrative expense for the year ended December 31, 2009 was $21.4 million compared to $16.9 million for the year ended December 31, 2008, an increase of 27%. The increase of $4.5 million was due to an increase in administrative and supervisory personnel. General and administrative expense per equivalent unit of production was $1.57 per Mcfe for the year ended December 31, 2009 compared to $1.31 per Mcfe for the comparable period in 2008. Approximately $4.6 million or 22% of the general and administrative expenses in 2009 was related to non-cash compensation expense compared to $3.1 million or 18% in 2008. A significant portion of our general and administrative expense is related to non-cash compensation expense. 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. We expect general and administrative expenses on a per Mcfe basis to decrease as production increases.

Depreciation, Depletion and Amortization.

Depreciation, depletion and amortization expense decreased $0.7 million to $31.0 million in the year ended December 31, 2009, down 2% from the year ended December 31, 2008. The oil and natural gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.76 per Mcfe in the year ended December 31, 2009 compared to $2.08 per Mcfe in the year ended December 31, 2008. The depletion rate decrease was due to a lower cost basis in oil and natural gas properties subject to amortization due to previously recorded impairment charges as a result of lower crude oil and natural gas prices at year end 2008 and 2009.

Impairment of Oil and Natural Gas Properties.

As a result of lower oil and natural gas prices from year-end 2008, we recognized an impairment charge on oil and natural gas properties of $188.2 million in the year ended December 31, 2009 compared to an impairment charge of $192.7 million for the year ended December 31, 2008. The Company may be required to recognize additional impairment charges or writedowns in future reporting periods if market prices for oil or natural gas continue to decline.

Interest.

Interest expense for the year ended December 31, 2009 was $16.1 million compared to $13.6 million for the year ended December 31, 2008. This increase is due to a greater amount of outstanding debt during 2009 and an increase in non-cash interest expense related to our convertible notes. Interest expense for the years ended December 31, 2008 and 2009 includes non-cash interest expense of $1.9 million and $3.9 million, respectively related to the amortization of the 5.00% convertible notes and the 4.50% convertible notes.

Loss on Extinguishment of Debt

. In October 2009, we entered into an amendment with Prudential, pursuant to which Prudential agreed to accept repayment of its senior secured subordinated notes with the proceeds of our offering of 4.50% convertible notes. We repaid all the senior secured subordinated notes on October 29, 2009. As a result of prepaying the senior secured subordinated notes, we recognized a charge of approximately $5.0 million related to the early pay-off of such notes.

Income Taxes.

Income tax for 2009 was a benefit of $33,000 as compared to a benefit of $25.0 million in 2008. The effective tax rates for 2008 and 2009 were 17% and 0%, respectively. The valuation allowance for deferred tax assets was increased by $53.9 million in 2009 in order to provide a full valuation allowance on our net deferred tax assets. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2009 and prior years, relevant accounting guidance suggests that cumulative losses in recent years constitutes significant negative evidence and future expectations about income are insufficient to overcome a history of such losses. Therefore, with the valuation allowance of $53.9 million, we have reduced the carrying value of our net deferred tax asset to zero. The valuation allowance has no impact on our net operating loss ("NOL") position for tax purposes, and if we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that time. We will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

Net Income (Loss) and Net Income (Loss) Per Share

Net Income (Loss) and Net Income (Loss) Per Share --Three Months Ended December 31, 2009 Compared to Three Months Ended December 31, 2008.

For the three months ended December 31, 2009 we reported a net loss applicable to GMXR shareholders of $49.3 million and for the three months ended December 31, 2008, we reported net loss of $153.7 million applicable to GMXR shareholders. Net loss per basic and fully diluted share was $1.90 for the fourth quarter of 2009 compared to net loss per basic and fully diluted share $10.04 for the fourth quarter of 2008. Weighted average fully-diluted shares outstanding increased by 70% from 15,341,546 shares in the fourth quarter of 2008 to 26,010,528 shares in the fourth quarter of 2009.

Results for the fourth quarter of 2009 and 2008 included impairment charges of $50.1 million and $192.7 million, respectively, related to oil and natural gas properties and a non-cash charge to deferred income taxes in 2008 for a valuation allowance on GMXR's net deferred tax assets of $26.1 million. Excluding these non-cash charges, net income (loss) applicable to GMXR shareholders for the fourth quarter of 2009 and 2008 would have been $5.3 million and ($0.3) million, respectively, and diluted earnings (loss) per share would have been $0.20 and ($0.02).

Net Income (Loss) and Net Income (Loss) Per Share -- Year Ended December 31, 2009 Compared to Year Ended December 31, 2008.

For the year ended December 31, 2009 and 2008, we reported net loss applicable to GMXR shareholders of $185.3 million and $129.3 million, respectively. Net loss per basic and fully diluted share was $9.17 for the year ended 2009 compared to net loss per basic and fully diluted share of $9.09 for the year ended 2008. Weighted average fully-diluted shares outstanding increased by 42% from 14,216,466 shares in 2008 to 20,210,400 shares in 2009.

Results for the year ended December 31, 2009 and 2008 included impairment charges of $188.2 million and $192.7 million, respectively related to oil and natural gas properties and a non-cash charge in the fourth quarter of 2008 to deferred income taxes for a valuation allowance on GMXR's net deferred tax assets of $26.1 million. Excluding these non-cash charges and other charges described above, net income applicable to GMXR shareholders for the year ended 2009 and 2008 would have been $10.7 million and $24.7 million, respectively, and diluted earnings per share would have been $0.53 and $1.62, respectively.

Net income (loss) applicable to GMXR shareholders was used as the numerator in computing basic and diluted income per common share for the three and twelve months ended December 31, 2008 and 2009. The following table shows the weighted average shares outstanding for the:

	Three Months Ended December 31,	Twelve Months Ended December 31,
	2008	2009	2008	2009
Weighted average shares outstanding	15,341,546	26,010,528	14,216,466	20,210,400

Due to our net loss from operations for the three and twelve months ended December 31, 2008 and 2009, we did not include the effects of convertible notes, restricted stock or stock options in the computation of loss per share -- dilutive, because it would have been antidilutive.

Common shares loaned in connection with the February 2008 convertible debt offering in the amount of 3,140,000 and 3,440,000 shares for the periods ended December 31, 2009 and 2008 respectively were not included in the computation of earnings (loss) per common share. While the borrowed shares are considered issued and outstanding for corporate law purposes, we believe that the borrowed shares are not considered outstanding for the purposes of computing and reporting earnings per share under GAAP currently in effect because the shares lent pursuant to the share lending agreement are required to be returned to us.

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 commodity prices, we enter into crude oil and natural gas swaps, collars, three-way collars, and put spreads.

For the year ended December 31, 2009, our capital expenditures were $178.0 million. Anticipated 2010 capital expenditure guidance is $175 million for a three rig H/B Hz drilling program. We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry conditions and the availability of capital. We believe our cash on hand, cash flow from operating activities and our availability under our revolving bank credit facility ($130 million at December 31, 2009) is sufficient to fund our 2010 planned oil and natural gas capital expenditure program.

During 2009, we accessed the capital markets and sold non-core assets to fund our H/B horizontal drilling program. In May 2009, we were successful in raising $65 million, net of expenses, from the sale of 5.75 million shares of common stock. In October 2009, we were again successful in raising $190 million, before estimated expenses of $9 million, from the sale of 6.95 million shares of common stock and the issuance of $86 million aggregate principal amount of 4.50% convertible notes. In addition to these capital market transactions, we received $36 million in November 2009 from the partial monetization of our mid-stream assets in the Endeavor Gathering transactions. We expect that this capital raised during 2009, plus availability under our revolving bank credit facility will be sufficient to fund a three rig drilling program through the point at which our discretionary cash flows will exceed our capital expenditures. We will continually adjust our capital expenditures based on the current commodity price environment to ensure that we have adequate liquidity in cash and/or with availability under our revolving bank credit facility. We anticipate using various derivative contracts such as puts, put spreads, and collars to mitigate natural gas and crude oil price risk on 60% to 80% of our expected production over a rolling 36 month period.

Cash Flow -- Twelve Months Ended December 31, 2009 Compared to Twelve Months Ended December 31, 2008

Cash Flow -- Year Ended December 31, 2009 Compared to Year Ended December 31, 2008.

In 2009, we had a positive cash flow from operating activities of $49.5 million. Our cash flow from operating activities in 2008 was $83.2 million. Cash flow from operating activities before changes in operating assets and liabilities and after preferred stock dividends was $50.4 million compared to $73.7 million in 2008. This resulted from a 25% decrease in oil and natural gas sales in 2009. We received a net $124.8 million in cash from financing activities in 2009 compared to 2008 amounts of $235.9 million. The cash flow from financing activities in 2009 was primarily from the sale of common stock of $164.1 million, issuance of 4.50% convertible senior notes of $86.3 million offset by paydowns of debt under our revolving bank credit facility and senior secured notes. The cash flow from financing activities in 2008 was primarily from the sale of common stock of $134.7 million, issuance of 5.00% convertible senior notes of $125.0 million and additional debt under our revolving bank credit facility.

GMX Resources Inc. and Subsidiaries Consolidated Balance Sheets (dollars in thousands, except share data)
	December 31,
	2008	2009
	(as adjusted and restated)
ASSETS	(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$ 6,716	$ 35,554
Accounts receivable--interest owners	576	1,233
Accounts receivable--oil and natural gas revenues, net	9,145	9,340
Derivative instruments	21,325	12,252
Inventories	691	326
Prepaid expenses and deposits	2,040	3,809
Total current assets	40,493	62,514
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD
Properties being amortized	600,662	756,412
Properties not subject to amortization	36,034	39,789
Less accumulated depreciation, depletion, and amortization	(252,806 )	(464,872)
	383,890	331,329
PROPERTY AND EQUIPMENT, AT COST, NET	93,486	101,755
DERIVATIVE INSTRUMENTS	3,751	17,292
OTHER ASSETS	3,380	6,748
TOTAL ASSETS	$ 525,000	$ 519,638
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$ 35,599	$ 19,180
Accrued expenses	6,089	12,907
Accrued interest	3,290	3,361
Revenue distributions payable	5,293	4,434
Current maturities of long-term debt	61	48
Total current liabilities	50,332	39,930
LONG-TERM DEBT, LESS CURRENT MATURITIES	224,281	190,230
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS	--	16,299
OTHER LIABILITIES	6,645	7,152
SHAREHOLDERS' EQUITY:
Preferred stock, par value $.001 per share, 10,000,000 shares authorized: Series A Junior Participating Preferred Stock 25,000 shares authorized, none issued and outstanding	--	--
9.25% Series B Cumulative Preferred Stock, 3,000,000 Shares authorized, 2,000,000 shares issued and outstanding (aggregate liquidation preference $50,000,000)	2	2
Common stock, par value $.001 per share--authorized 50,000,000 shares issued and outstanding 18,794,691 shares in 2008 and 31,214,968 shares in 2009	19	31
Additional paid-in capital	328,002	520,307
Retained earnings	(99,577)	(284,841)
Accumulated other comprehensive income, net of taxes	15,296	8,447
Total shareholders' equity	243,742	243,946
Noncontrolling interest	--	22,081
Total equity	243,742	266,027
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 525,000	$ 519,638

GMX Resources Inc. and Subsidiaries
Consolidated Statements of Operations
(dollars in thousands, except share and per share data)
	Three Months Ended	Year Ended
	December 31,	December 31,
	2008	2009	2008	2009
	(as adjusted and restated)		(as adjusted and restated)
	(unaudited)	(unaudited)
OIL AND NATURAL GAS SALES	$24,089	$25,556	$125,736	$94,294
EXPENSES:
Lease operations	4,450	3,195	15,101	11,776
Production and severance taxes	597	144	5,306	-930
Depreciation, depletion, and amortization	9,001	7,753	31,744	31,006
Impairment of oil and natural gas properties	192,650	50,072	192,650	188,150
General and administrative	4,941	6,811	16,899	21,390
Total expenses	211,639	67,975	261,700	251,392
Loss from operations	(187,550)	(42,419)	(135,964)	(157,098)
NON-OPERATING INCOME (EXPENSES):
Interest expense	(3,279)	(4,047)	(13,618)	(16,127)
Loss on extinguishment of debt	--	(4,976)	--	(4,976)
Interest and other income	139	31	285	72
Unrealized loss on derivatives	(354)	457	(354)	(2,370)
Total non-operating expense	(3,494)	(8,538)	(13,687)	(23,401)
Loss before income taxes	(191,044)	(50,957)	(149,651)	(180,499)
BENEFIT FOR INCOME TAXES	38,222	2,975	25,014	33
NET LOSS	(152,822)	(47,982)	(124,637)	(180,466)
Preferred stock dividends	1,156	1,156	4,625	4,625
Net income attributable to noncontrolling interest	--	173	--	173
NET LOSS ATTRIBUTABLE TO GMX RESOURCES SHAREHOLDERS	$(153,978)	$(49,311)	$(129,262)	$(185,264)
LOSS PER SHARE -- Basic	$(10.04)	$(1.90)	$(9.09)	$(9.17)
LOSS PER SHARE -- Diluted	$(10.04)	$(1.90)	$(9.09)	$(9.17)
WEIGHTED AVERAGE COMMON SHARES -- Basic	15,341,546	26,010,528	14,216,466	20,210,400
WEIGHTED AVERAGE COMMON SHARES -- Diluted	15,341,546	26,010,528	14,216,466	20,210,400

GMX Resources Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(dollars in thousands)
	Year Ended December 31,
	2008	2009
	(as adjusted and restated)
CASH FLOWS DUE TO OPERATING ACTIVITIES	(unaudited)
Net loss	$(124,637)	$(180,466)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	31,744	31,006
Impairment of oil and natural gas properties	192,650	188,150
Deferred income taxes	(25,040)	--
Non-cash compensation expense	3,085	4,635
Loss on extinguishment of debt	--	4,975
Other	521	6,868
Decrease (increase) in:
Accounts receivable	717	(1,338)
Prepaid expenses and other assets	(1,089)	(71)
Increase (decrease) in:
Accounts payable and accrued expenses	3,558	(2,852)
Revenue distributions payable	1,728	(1,417)
Net cash provided by operating activities	83,237	49,490
CASH FLOWS DUE TO INVESTING ACTIVITIES
Additions to oil and natural gas properties	(281,447)	(162,076)
Purchase of property and equipment	(36,913)	(19,248)
Sale of equity interest and equipment	--	36,000
Other	--	(108)
Net cash used in investing activities	(318,360)	(145,432)
CASH FLOW DUE TO FINANCING ACTIVITIES
Advance on borrowings	190,000	99,000
Payments on debt	(204,210)	(179,079)
Proceeds from sale of common stock	134,681	164,051
Issuance of 5.00% Convertible Senior Notes	125,000	--
Issuance of 4.50% Convertible Senior Notes	--	86,250
Dividends paid on Series B preferred stock	(4,625)	(4,625)
Proceeds from issuance of Senior Secured Notes	--	(34,590)
Fees paid relating to financing activities	(4,914)	(6,959)
Other	--	732
Net cash provided by financing activities	235,932	124,780
NET INCREASE IN CASH	809	28,838
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,907	6,716
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$6,716	$35,554
SUPPLEMENTAL CASH FLOW DISCLOSURE CASH PAID (RECEIVED) DURING THE PERIOD FOR:
INTEREST	$10,343	$15,611
TAXES	$26	$(33)

GMX Resources Inc. and Subsidiaries
Non-GAAP Supplemental Information - Discretionary Cash Flows(1)
	Three Months Ended December 31,	Year Ended December 31,
	2008	2009	2008	2009
	(unaudited)	(unaudited)
	(in thousands)
Net loss	$(152,822)	$(47,981)	$(124,637)	$(180,466)
Non-cash charges:
Depreciation, depletion, and amortization	9,001	7,753	31,744	31,006
Impairment of oil and natural gas properties	192,650	50,072	192,650	188,150
Deferred income taxes	(38,117)	(2,944)	(25,040)	--
Non cash compensation expense	1,026	977	3,085	4,635
Deferred income taxes	--	4,976	--	4,976
Other	(939)	1,088	521	6,868
Preferred stock dividends	(1,156)	(2,313)	(4,625)	(4,625)
Net income attributable to noncontrolling interest	--	(173)	--	(173)
Non-GAAP discretionary cash flow	$9,643	$11,455	$73,698	$50,371
Reconciliation of GAAP "Net cash provided by operating activities" to Non-GAAP "discretionary cash flow"
Net cash provided by operating activities	$28,971	$5,507	$83,237	$49,490
Adjustments:
Changes in operating assets and liabilities	(18,172)	8,434	(4,914)	5,679
Preferred stock dividends	(1,156)	(2,313)	(4,625)	(4,625)
Net income attributable to noncontrolling interest	--	(173)	--	(173)
Non-GAAP discretionary cash flow	$9,643	$11,455	$73,698	$50,371

⁽¹⁾ Discretionary cash flow represents net cash provided by operating activities before changes in assets and liabilities less preferred dividends. Discretionary cash flow is presented because management believes it is a useful financial measure in addition to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Management believes that discretionary cash flow is widely accepted as a financial indicator of an oil and gas company's ability to generate cash which is used to internally fund exploration and development activities. Discretionary cash flow is widely used by professional research analysts and investors in the comparison, valuation, rating and investment recommendations of companies within the oil and gas exploration and production industry. Discretionary cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity, or as an alternative to net income.

GMX Resources Inc. is a 'Pure Play', E & P Company with one of the most concentrated Haynesville/Bossier (H/B) Horizontal Shale Operations in East Texas. The Company has 355 Bcfe in proved reserves (YE2009), 94% of which are natural gas. The Company's proved reserves are 81% operated and consist of 279 net "Capital Core" H/B Hz un-drilled locations; 14 gross /13.9 net H/B producers, and 324 gross / 186.9 net Cotton Valley Sand ("CVS") producers; 1,382 net CVS acre un-drilled locations; and 47 net Travis Peak / Hosston Sands & Pettit producers. These multiple resource layers provide high probability and the potential for repeatable, organic growth.

The GMX Resources Inc. logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=5158

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 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.