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

OKLAHOMA CITY, March 1, 2012 (GLOBE NEWSWIRE) -- GMX RESOURCES INC., (NYSE:GMX) (the "Company" or "GMXR"), reports today on the Company's financial and operating results for the fourth quarter and full year ended December 31, 2011.

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

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

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

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

Transition to Liquids

• Oil production for the fourth quarter 2011 was 28,171 BBLs, representing a 50% increase over the third quarter 2011 production of 18,729 BBLs. NGL production for the fourth quarter 2011 was 109,902 BBLs, representing a 43% increase over the third quarter 2011 production of 76,997 BBLs. Crude and NGLs as a percentage of revenues, excluding hedges, during the fourth quarter 2011 were 39% compared to 19% in the third quarter of 2011.
   
• The Company expects that oil production will grow from full year 2011 to full year 2012 by approximately 300%, while NGL production will increase approximately 10% during the same time period. In the fourth quarter of 2012, oil and NGLs together are expected to be 35-40% of production and 65-70% of revenues.

Management Comments

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

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

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

2012 Capital Expenditure Plan

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

Production Guidance for 2012

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

Operations Recap

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

Bakken

• The Company has successfully drilled or participated in six Bakken Petroleum System wells, all in North Dakota. The Wock 21-2-1H, the Frank 31-4-1H and the Marsh 21-16 TFH are located in Stark County, the Taboo 1-25-36H and the Lange 11-30-1H are located in McKenzie County, and the Evoniuk 21-2-1H is located in Billings County, North Dakota. 
   
• The Company has successfully drilled its fourth operated well, the Lange 11-30-1H, located in Sections 30 & 31 Township 147N Range 99W in McKenzie County, North Dakota. The Lange 11-30-1H was drilled to a true horizontal measured depth of 20,519' with a lateral length of 8,958'. The Lange 11-30-1H will be completed in the Middle Bakken, significant oil shows were demonstrated while drilling the lateral. The Company anticipates fracture stimulating this well in March of 2012.
   
• The Company's fifth operated well, the Akovenko 24-34-1H, was spud on February 28, 2012. The Akovenko 24-34-1H is located in Sections 3&10 Township 145N Range 95W of McKenzie County, North Dakota, and we plan to drill this well as a Middle Bakken test with a true horizontal measured depth of 21,646' with a planned lateral length of 10,110'. The Company projects a 49% working interest in the well.
   
• The Company has received the state and federal permits for our sixth operated well, which will be located in McKenzie County, North Dakota. We plan to spud the well in the second quarter.
   
• The Neil 24-19MBH well located in Sections 18&19 Township 148N Range 98W in McKenzie County, North Dakota has been successfully drilled by Burlington Resources and is currently in the process of being fracture stimulated. The Company has a 4% working interest in the well. 
   
• We have elected to participate with Continental Resources in the drilling of the Pojorlie #21-2-1H well, in Section 2 & 11 Township 146N Range 98W in McKenzie County, North Dakota. The Pojorlie 21-2-1H will be drilled as a test of the Three Forks formation at an approximate horizontal depth of 21,208' and an approximate lateral length of 9,638'. Plans call for this well to be cored from the Middle Bakken into the Three Forks. GMXR has a 34% working interest in the well which is expected to spud in March of 2012.  
   
• Additionally, we have elected to participate with Continental Resources in the drilling of the GCR 1-25H well located in Sections 24 & 25 Township 141N Range 101W in Billings County, North Dakota. The well is a planned Three Forks test with a true horizontal measured depth of 20,324' and is estimated to spud in March of 2012. GMXR projects to have a 9.4% working interest in the well. 
   
• The Company has signed a long-term new build contract for a dedicated fit-for-purpose workover rig and crew, with expected arrival to be the first week in March 2012. Our current plans call for the workover rig to begin cleanup and removal of restrictions, including frac balls, on the Company's first three operated wells. We expect that this work can be accomplished within a few weeks, once work commences. 
   
• The Company currently plans to focus its drilling operations in McKenzie and Billings Counties, where we expect to operate 31 units representing 172 possible locations within these two counties.

Niobrara

• The Company is a non-operating participant in the Devon Energy Newton Ranches 14-3444H well located in Section 34-T24N-R64W in Goshen County, Wyoming. This well is within the North Mustang seismic project area and tested the Niobrara Formation. GMXR has a 29.2% working interest. The well reached a total depth of 12,045' with a horizontal lateral length of 4,000' and was successfully fracture stimulated and is currently producing on pump. 
   
• The Northern DJ Basin continues to exhibit considerable activity with other operators beginning to establish meaningful operations in Goshen, Laramie and Platte County, Wyoming, which includes the following information reported by other operators: 

• Devon Energy has permitted and plans to drill the Newton Ranches #3-2635H to a vertical depth of 8,934' and obtain cores in the Niobrara, Codell and Dakota before completing the well as a Niobrara test. GMXR has elected to participate in the well and projects a 5.9% working interest; this well is estimated to spud later this summer. 
   
• Devon Energy has 6 additional wells permitted within the Doty Hill / North Mustang 3D seismic shoot area that the Company would have a range of working interest in the wells should we elect to participate. 

• Devon has also permitted the Kepford #14-1405H in Township 20N Range 66W. This location is to the immediate east of the Company's Chugwater leasehold in Platte County, Wyoming. 
   
• Fidelity Exploration & Production Company, an MDU Resources Group Company, has an active drilling program in Southern Goshen County and to date has one well undergoing post-frac testing, a well currently drilling and one location that is currently under development. 
   
• Samson Oil & Gas Limited USA has recently reported a successful Niobrara test with the drilling of the Defender US 33 #3-29H. The well is currently on pump and producing between 300-400 BBLs per day with a 60-65% oil cut. Recent management comments indicate optimism for improved performance.
   
• Marathon Oil Corporation, with approximately 144,000 net acres in the DJ Basin, has successfully drilled the Corn Creek #1 well in Goshen County, Wyoming. The well is waiting on completion services. In addition they have a drilling rig on location in Laramie County, Wyoming and 2012 plans call for continued delineation of the play boundaries. 
   
• Noble Energy has over 440,000 net acres in the Central DJ Basin including over 1,000 square miles of 3D seismic. Their plans call for a one rig program to alternate between N. Colorado and S. Wyoming to appraise and test fractures, matrix, lateral geometry and completion designs. 
   
• Recovery Energy has initiated a horizontal Niobrara drilling program on its 14,400 acre contiguous block in the Chugwater area of Laramie County, Wyoming. The Company's first initial horizontal test is underway and additional drilling locations are being permitted.  

Significant Accomplishments in 2011

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

• In February of 2011, we issued $200 million in aggregate principal amount of senior notes due 2019 in a private placement and concurrently sold shares of our common stock for the proceeds after underwriters fees but before expenses of $98 million. These capital raises allowed the Company to reduce a portion of its convertible notes due in 2013, repay the secured credit facility, fund the purchase of undeveloped oil acreage, contract for a drilling rig, and begin drilling in the Williston Basin. It also allowed us to begin the seismic study in the DJ Basin. 
   
• In the first half of 2011, the Company acquired core positions in over 75,000 net acres in two of the leading oil resource plays in the U.S.: the Williston Basin of North Dakota/Montana, targeting the Bakken/Three Forks Formations, and in the oil window of the Denver Julesburg Basin (the "DJ Basin") of Wyoming targeting the emerging Niobrara Formation. 
   
• Based on market conditions for natural gas and the cost to develop this acreage remaining at higher than economically viable levels, we decided in mid-2011 to temporarily suspend continued development of our East Texas H/B acreage and to focus our capital and resources on our newly acquired Bakken and Niobrara oil-focused acreage. Our last H/B well was drilled, completed and brought on line in August 2011.
   
• During 2011, we sold three drilling rigs owned by GMXR's wholly owned subsidiary, Diamond Blue Drilling, which were previously classified as assets held for sale, in three separate transactions. Also, Endeavor Gathering LLC (owned 60% by the Company) was also successful in selling an excess inventory of large diameter pipe and compressors during the course of the year. Total proceeds received on the sales were $10.2 million, net of selling commissions paid by the Company and distributions to noncontrolling interest.  
   
• The Company accelerated its entry into the Williston Basin in July of 2011, a full three months sooner than originally planned, by signing a one-year contract with Paramount Drilling Co. and spudding the Wock 21-2-1H well on July 7, 2011, and completing the Wock 21-2-1H and the Frank 31-4-1H in 2011. 
   
• During 2011, we subleased our fourth H&P Flex rig and also extended two prior subleases for the remainder of the lease term for a total reduction in rig lease fees of $24.4 million dollars. All four of our H&P Flex Rigs are now subleased for remainder of the lease terms. 
   
• In December 2011, the Company sold a term overriding royalty interest in twenty-one wells in the H/B layer in Harrison County, Texas to EDF Trading North America, LLC. The VPP is for approximately 14.8 Bcf to be produced over ninety-five months, commencing December 1, 2011. The VPP generated $49.7 million in cash proceeds. The VPP does not restrict the Company's future development of the H/B. 
   
• In December 2011, the Company terminated its bank credit facility and removed related financial maintenance covenants and is no longer dependent on reserve-based commercial lending. 
   
• In December 2011, the Company monetized its entire remaining portfolio of hedges, which provided to us approximately $18.1 million, net of deferred premiums paid and commissions. 
   
• On December 19, 2011, GMXR accepted tenders and consents from the holders of approximately $198 million of its outstanding $200 million 11.375% senior notes due 2019 ("Senior Notes due 2019") for new 11% senior secured notes due 2017 ("Senior Secured Notes due 2017"). This exchange offer termed "Bond Exchange" also generated approximately $100 million in gross cash proceeds. In addition, the Company's principal amount of debt was reduced by approximately $17.5 million as a result of the exchanging each $1,000 principal amount of the Senior Secured Notes due 2019 for either $750 or $971.40 of the new Senior Secured Notes due 2017. 
   
• In December, the Company undertook a thorough review of its general and administrative expenses and as a result expects to reduce 2012 costs by 21% compared to 2011 expenses. The total 2011 cash compensation awarded to the top three executive officers is estimated to be approximately 36% less than they received in 2010.
   
• The Company established an operational footprint in one of the most competitive oil plays in North America and successfully completed three Williston Basin wells during 2011. 

Operational

• Production for fourth quarter of 2011 was 5.3 Bcfe, before adjusting for December 2011 VPP volumes of 0.45 Bcfe, was consistent with the 5.3 Bcfe of production in the fourth quarter of 2010. After adjusting for the December 2011 VPP, fourth quarter 2011 production was 4.8 Bcfe.
   
• Including the 0.45 Bcfe in VPP volumes, total production increased by 37.2% to 24.0 Bcfe in 2011 compared to 17.5 Bcfe in 2010.
   
• Including VPP volumes, daily production for 2011 averaged 65.7 Mcfe, an increase of 17.7 Mcfe or 37%, over the 47.9 Mcfe of daily production for 2010.
   
• The Company's 2012 full year production guidance is expected to be approximately 2,311,000 BOE with oil production to be approximately 373,000 BBLs. First quarter 2012 guidance is 587,000 BOE and 37,000 BBLs of oil respectively. This guidance includes a reduction of approximately 196,000 BOE and approximately 654,000 BOE related to the VPP for the first quarter 2012 and the full year 2012, respectively.
   
• The Company has completed a 3D seismic shoot ("Crossroads") of 33 square miles, covering almost all of the Company's contiguous operated acreage in Harrison County, Texas. The Crossroads shoot is currently being evaluated by the Company to aid it in a more complete assessment of several oil targets and future natural gas development.

 Financial

• Net loss applicable to common shareholders was $79.8 million, or $1.39 per share, and $218.6 million, or $4.12 per share, for the fourth quarter and full year ended December 31, 2011, respectively.
   
• As detailed below, non-GAAP adjusted net loss applicable to common shareholders⁽¹⁾ was $6.6 million and $15.0 million for the fourth quarter and full year ended December 31, 2011, respectively.
   
• Lease operating expenses were $0.85 and $0.56 per Mcfe, including 0.45 Bcfe in VPP volumes, for the fourth quarter and full year ended December 31, 2011, respectively, compared to $0.47 and $0.61 per Mcfe for the fourth quarter and full year ended December 31, 2010, respectively, or an increase of $0.38 and a decrease of $0.05 per Mcfe, respectively.
   
• General and administrative expenses were $1.25 and $1.20 per Mcfe, including 0.45 Bcfe in VPP volumes, for the fourth quarter and full year ended December 31, 2011, respectively, compared to $1.36 and $1.56 per Mcfe for the fourth quarter and full year ended December 31, 2010, respectively or an decrease of $0.11 and a decrease of $0.36, respectively.
   
• Adjusted EBITDA⁽¹⁾ was $12.9 million and $71.2 million for the fourth quarter and full year ended December 31, 2011, respectively, compared to $16.9 million and $61.9 million for the fourth quarter and full year ended December 31, 2010, respectively.
   
• Discretionary cash flow⁽¹⁾ was $4.0 million and $41.2 million for the fourth quarter and full year ended December 31, 2011, respectively, compared to $13.1 million and $47.6 million for the fourth quarter and full year ended December 31, 2010, respectively.
   
• For 2011, our cash outlays for capital expenditures were $272 million of which $126 million was the cash portion of acreage acquisitions and seismic in the Williston Basin, DJ Basin-Niobrara and East Texas, $124 million was for drilling operations, and $22 million related to capitalized interest, corporate expenditures and rig sub-lease fees.

(1)    Adjusted net loss available to common shareholders, adjusted EBITDA and discretionary cash flow are non-GAAP measures that are further described and reconciled below in this press release.

Oil and Natural Gas Reserves

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

(1)  For 2011, 2010 and 2009, prices used for Estimated Future Net Revenues and the Present Value are an average first-day of the month price for the last 12 months in accordance with recent amendments to Regulations S-K and S-X of the SEC. Estimated Future Net Revenues and the Present Value give no effect to federal or state income taxes attributable to estimated future net revenues. The Present Value, or PV-10, represents the estimated future net cash flows attributable to our estimated proved oil and gas reserves before income tax, discounted at 10%. PV-10 may be considered a non-GAAP financial measure as defined by the SEC. We believe that the Estimated Future Net Revenue and Present Value are useful measures in addition to the standardized measure as it assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies.

 (2) The proved reserves as of December 31, 2011 include a reduction to both volumes and revenues to reflect committed VPP volumes due for approximately 93 months. The effect of the VPP reduction to reserves and PV-10 is 14.3 Bcfe and $45.5 million, respectively.

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

(1) PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue before income tax of the Company's estimated proved reserves. The PV-10 value is different than the standardized measure of discounted estimated future net cash flows, which is calculated after income taxes. The Company believes the PV-10 is a useful measure for evaluating the relative monetary significance of their proved reserves. Investors may use the PV-10 as a basis for comparison of the relative size and value of the Company's reserves to its peers. 

(2) The proved reserves as of December 31, 2011 are calculated based on current SEC guidelines. The commodity prices used in the estimate were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price during the period from January 2011 through December 2011. For natural gas volumes, the average Henry Hub spot price of $4.12 and $4.38 for 2011 and 2010, respectively, per million British thermal units (MMBTU) and was adjusted for energy content, transportation fees, regional price differences, and system shrinkage. For crude oil, the average West Texas Intermediate posted price of $96.19 and $79.43 for 2011 and 2010, respectively, per barrel and was adjusted for quality, transportation fees, and regional price differentials.

(3) The proved reserves as of December 31, 2011 include a reduction to both volumes and revenues to reflect committed VPP volumes due for approximately 94 months. The effect of the VPP reduction to reserves and PV-10 is 14.3 Bcfe and $45.5 million, respectively.  

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

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

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

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

(1) Due to the adjusted net loss applicable to common shareholders for the three months and year ended December 31, 2011, per share amounts are calculated using the weighted average basic number of shares that excludes items that would be antidilutive. Basic weighted average common shares outstanding for the three months and year ended December 31, 2011 was 57,397,696 and 53,071,200, respectively.

(2) Non-cash interest expense is comprised of the amortization of discounts related to our convertible notes, share lending agreement and deferred premiums on derivative instruments.

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

(1) In 2011, the Company sold future production through a VPP covering a portion of its Haynesville Shale assets, which included approximately 450 MMcf that was produced during the three months and year-ended December 31, 2011. The operating and overhead costs per Mcfe for the three months and year ended December 31, 2011 are calculated including the VPP volumes as the Company is responsible for these expenses under the terms of the VPP.

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

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

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

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

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

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

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

Impairment of oil and natural gas properties and assets held for sale.  For the $78.0 million non-cash impairment charge recorded in the fourth quarter of 2011, $76.0 million was related to the impairment of oil and gas properties subject to the full cost ceiling test and $2.0 million was related to a change in value of assets held for sale. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges, and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Natural gas represented approximately 96% of the Company's total proved reserves at the end of 2011, and as a result, a decrease in natural gas prices can significantly impact the Company's ceiling test. Of the $76.0 million related to the non-cash impairment of oil and gas properties, $38.1 million resulted from the net book value of oil and gas properties exceeding the net present value of future net revenues, $33.9 million related to the monetization of cash flow hedges that were previously used in the full cost ceiling test and $4.0 million related to impairment on our acquisition cost of East Texas and North Louisiana undeveloped acreage outside of our primary development area being subject to the full cost method ceiling test and was based on the Company's decision not to develop the acreage. The remaining $2.0 million of the $78.0 million non-cash impairment charge was related primarily to an impairment on rig related and equipment that was sold in 2011.

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

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

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

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

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

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

Oil and Natural Gas Sales. Oil and natural gas sales during the year ended December 31, 2011 increased 21% to $116.7 million compared to $96.5 million during the year ended December 31, 2010. Oil and natural gas sales included gains (losses) from the ineffectiveness from derivatives of $0.1 million and $(1.3) million for the year ended December 31, 2011 and 2010, respectively, and are the result of a difference in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point. The increase in oil and natural gas sales was due to a 35% increase in production on a Bcfe-basis, a 20% increase in oil prices, a 24% increase in the average realized price of NGLs, offset by a 16% decrease in the average realized price of natural gas, excluding ineffectiveness of hedging activities. The average price per barrel of oil, per gallon of natural gas liquids NGLs and Mcf of natural gas received (excluding ineffectiveness from derivatives) in the year ended December 31, 2011 was $92.33, $0.98 and $4.50, respectively, compared to $76.77, $0.79 and $5.33, respectively, for the year ended December 31, 2010. Our realized sales price for natural gas, excluding the effect of hedges of $0.90 and $1.60, for the year ended December 31, 2011 and 2010, respectively, was approximately 89% and 85% of the average NYMEX closing contract price for the respective periods. During the year ended December 31, 2011 and 2010, the conversion of natural gas to NGLs produced an upgrade of approximately $0.67 per Mcf and $0.81 per Mcf, respectively, for every Mcf of natural gas produced. This upgrade in value was previously included in the realized price of our natural gas sales.

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

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

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

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

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

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

General and Administrative Expense. General and administrative expense for the year ended December 31, 2011 was $28.9 million compared to $27.1 million for the year ended December 31, 2010, an increase of $1.8 million, or 6%. General and administrative expense per equivalent unit of production was $1.20 per Mcfe, including VPP volumes, for the year ended December 31, 2011 compared to $1.56 per Mcfe for the comparable period in 2010. The overall increase in general and administrative expense for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to approximately $1.3 million in expenses for the year ended December 31, 2011, legal fees related to the VPP, and other legal matters, as well as transaction fees related to the hedge monetization. General and administrative expenses include $3.7 million and $5.5 million of non-cash compensation expense as of the year ended December 31, 2011 and 2010, respectively. Non-cash compensation represented 13% and 20% of total general and administrative expenses for the year ended December 31, 2011 and 2010, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature. 

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

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

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

Capital Resources and Liquidity

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

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

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

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

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

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

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 risks relating to the Company's ability to obtain financing for its planned activities, commodity price risks, drilling and production risks, risks related to weather and unforeseen events, governmental regulatory risks and other risks, many of which are beyond the control of the Company. Reference is made to the Company's reports filed with the Securities and Exchange Commission for a more detailed disclosure of the risks. For all these reasons, actual results or developments may differ materially from those projected in the forward-looking statements.