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GMX RESOURCES INC. Announces Financial and Operational Results for the Three Months Ended March 31, 2012

OKLAHOMA CITY, May 2, 2012 (GLOBE NEWSWIRE) -- GMX RESOURCES INC., (NYSE:GMXR)(the "Company" or "GMXR"), reports today on the financial and operating results for the first quarter ended March 31, 2012.

Company Highlights for the Three Months Ended March 31, 2012

Operational

  • In the first quarter of 2012, the Company achieved an average oil production of 341 barrels/day (Bbls/d). The Company estimates for the month of June 2012, oil production will be approximately 1,100 Bbls/d, representing a 224% increase over the 2012 first quarter average.
     
  • Total production for the first quarter 2012 was 596,000 BOE, which includes 31,000 Bbls of oil and 146,000 Bbls of NGLs. The NGL production represents a 35% increase over previous guidance due primarily to a change in the dispatch of our natural gas to plants with higher NGL recoveries and plant efficiencies. Oil production for the first quarter 2012 represents a 41% increase over first quarter 2011, and NGL production in the first quarter 2012 represents a 121% increase over the first quarter of 2011.
     
  • Natural gas production for the three months ended March 31, 2012 decreased to 2.5 Bcfe compared to 5.5 Bcfe for the three months ended March 31, 2011, a decrease of 54%. If we add back the VPP volumes of 1.2 Bcfe, natural gas production decreased by 1.8 Bcfe, or 33%. The decrease in natural gas production resulted primarily from the natural decline in the Company's Haynesville/Bossier (H/B) wells as a result of the Company's suspension of its H/B horizontal drilling program in mid-2011, as well as the conversion of more natural gas into NGLs.
     
  • Production guidance for the second quarter 2012 is estimated by the Company to be 591,000 BOE, which includes 80,000 Bbls of oil and 94,000 Bbls of NGLs. Full year 2012 guidance is estimated by the Company to be 2,355,000 BOE, which includes 346,000 Bbls of oil and 473,000 Bbls of NGLs. Oil and NGLs are estimated to be 35% of total 2012 production and 76% of total 2012 revenues, excluding income from hedges, as oil and NGL production ramps up in the Williston Basin. The decrease in second quarter NGL production guidance is due to a declared force majeure at a Carthage Texas plant that lasted for two weeks that had an estimated 15,000 Bbl impact, and the sale of a portion of our un-processed gas in the Carthage Texas area for a total price that is greater than the combined estimated price of residue gas and the net processing upgrade. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the hydrocarbons for GMXR.

PV-10 and Positive Reserve Revisions

  • The PV-10 value of our Williston Basin reserves at year end 2011 as reported by the Company's independent third-party reserve auditor was $14.4 million. As of the end of the first quarter 2012 and based on SEC oil and gas prices as of March 31, 2012, our in-house reserve engineer estimates that our PV-10 value in the Williston Basin has increased to $39.5 million representing a 174% increase. 
     
  • At the end of the first quarter 2012, our in-house reserve engineer estimated a total net estimated ultimate recovery ("EUR") for our proved Williston Basin wells of 1,798 MBOE, including positive reserve revisions of 252 MBOE.

Bakken

  • The Company's three wells in McKenzie County, North Dakota had an average of 1,973 IP BOE/d, and the Company's seven Bakken/Three Forks wells have an average IP of 1,420 BOE/d.   Initial Production ("IP") rates reported is either peak one hour rates multiplied times 24 or full 24 hour volumes depending upon the operator.
     
  • The Company expects to reduce completed well costs for the Williston Basin with a near term goal of $8.5 million per well. Costs savings have been achieved on our last two wells as a result of utilizing a new directional drilling company together with other efficiencies as we high grade the services needed in drilling and completing Williston Basin wells.    Fracture stimulation services have become more readily available. As a result, our new estimate for spud to oil sales cycle has been reduced from 90 days to 70 days and our estimated spud to gas sales is 90 days. We expect our spud-to-spud cycle to be 45 days.   In a review of the total costs for fracture stimulation including horsepower, equipment, proppant and fluids, we have seen an approximate $1 million or 50% decrease from our first operated well to the most recent completed operated well.
     
  • The Company's fourth operated well, the Lange 11-30-1H, in which the Company has an approximate 89% working interest, located in Sections 30&31, Township 147N, Range 99W in McKenzie County, North Dakota, was drilled to a measured depth of 20,519' with a lateral length of 9,348'. The well was completed as a 32-stage frac Middle Bakken producer achieving a peak rate of 2,549 BOE/d @1,500 psi flowing casing pressure.  
     
  • The Company's fifth operated well, the Akovenko 24-34-1H, in which the Company has an approximate 66% working interest, located in Sections 3&10, Township 145N, Range 95W in McKenzie County, North Dakota, has been successfully drilled with a measured depth of 19,927' with a lateral length of 8,305' in the Middle Bakken. The well is expected to be fracture stimulated with a 31-stage sliding sleeve completion in May 2012. 
     
  • The Company's sixth operated well, the Johnston 31-4-1H, was spud on April 5, 2012.   GMXR currently projects a 38% working interest in the well.   GMXR working interest may increase upon receipt of final elections. The Johnston 31-4-1H is located in Sections 4&9, Township 146N, Range 99W in McKenzie County, North Dakota.   This well, a Middle Bakken target, has been successfully drilled to a measured depth of 21,219' with a lateral length of 9,300'.   The Company expects to fracture stimulate the well in June 2012.
     
  • The Company's seventh operated well, the Fairfield State 21-16-1H located in Sections 16&21, Township 143N, Range 99W in Billings County, North Dakota is expected to spud in May 2012.   The Company currently has a 32% working interest in the well and with possible trades and receipt of final elections working interest may increase.
     
  • The Company's workover rig arrived in North Dakota on March 23, 2012, and work has been done on the Evoniuk 21-2-1H and the Frank 31-4-1H and Wock 21-2-1H. The Evoniuk 21-2-1H, Frank 31-4-1H and Wock 21-2-1H are currently on pump and producing oil.  
     
  • The Neil 24-19MBH well, 4% working interest, located in Sections 18&19, Township 148N, Range 98W in McKenzie County, North Dakota has been successfully drilled in the Middle Bakken and completed by Burlington Resources and Initial Production tests reported 1,935 BOE/d.   
     
  • The Logan 24-8H well, in which the Company has an approximate 17% working interest, located in Sections 5&8 Township 148N Range 98W in McKenzie County, North Dakota was successfully drilled by Burlington Resources in the Middle Bakken. The operator is currently on location and preparing the well for fracture stimulation.
     
  • The Pojorlie 21-2-1H well, in which the Company has an approximate 34% working interest, located in Sections 2&11, Township 146, Range 98W in McKenzie County, North Dakota is a Three Forks target, has been successfully drilled by Continental Resources to a measured depth of 21,210' with a lateral length of 9,597'.   The operator has successfully pulled the core from the Middle Bakken through the Three Forks, and has prepared the well for fracture stimulation. 
     
  • The Company has signed a contract with a subsidiary of ONEOK Partners, L.P., a leader in the gathering, processing, storage and transportation of natural gas in the U.S., for many of our McKenzie and Billings County, North Dakota wells.   The natural gas being produced by our McKenzie and Billings County producing wells is currently being flared. The contract with ONEOK will enable the Company to capture the value of the NGLs and high MMBTU content natural gas.  ONEOK's analysis projects approximately 1,500 BTU gas and approximately 6.7 of C3+ GPM of NGLs.   Rights-of-way acquisitions and construction have been completed, and the Evoniuk 21-2-1H well located in Billings County, North Dakota has delivered its first gas into the ONEOK gathering line last week.   ONEOK is currently acquiring rights-of-way and will begin construction of gathering lines to the Lange 11-30-1H, Akovenko 24-34-1H, and Johnston 31-4-1H wells in McKenzie County, North Dakota, as well as additional locations in both McKenzie and Billings County, North Dakota.

Niobrara

  • GMXR acquired its Niobrara acreage position with specific ideas of basin flexure and maturity, and leveraging our execution with modern seismic investigation.  We now have three data points near the basin axis in our North Mustang Doty Hill area, the Samson Defender well and the two recent well completions by Devon.  Using these results with the seismic overprint will help guide future development.  We continue to believe that success in this play will require placing well laterals to intersect open fractures in targeting the sub-members of the Niobrara Chalk.  The two Devon wells will be used to calibrate models on locations that will be drilled in areas with more intensive tectonic signatures as well as vetting future completion design issues.
     
  • We are also noting emerging efforts of targeting the Codell-Turner interval within the Niobrara system.  That interval is more of a conventional target that while it certainly can be impacted by natural fractures, it is a tight clastic reservoir being characterized as less erratic than the chalky members.
     
  • We expect to receive our first set of 3D seismic from our Chugwater area of 30,817 net acres in May 2012.

Financial

  • Net loss applicable to common shareholders was $40.6 million, or $0.66 per basic and fully diluted share for the three months ended March 31, 2012.
     
  • As detailed below, non-GAAP adjusted net loss applicable to common shareholders(1) was $12.1 million , or $0.20 per basic and fully diluted share, for the three months ended March 31, 2012.
     
  • Lease operating expenses were $3.1 million for the three months ended March 31, 2012, compared to $2.9 million for the three months ended March 31, 2011.
     
  • General and administrative expenses were $7.0 million for the three months ended March 31, 2012, compared to $7.1 million for the three months ended March 31, 2011.
     
  • Adjusted EBITDA(1) was $7.0 million for the three months ended March 31, 2012, compared to $19.0 million for the three months ended March 31, 2011.
     
  • Discretionary cash flow (1) was $(8.2) million for the three months ended March 31, 2012 compared to $11.8 million for the three months ended March 31, 2011.
     
  • 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. As of March 31, 2012, we have made $25.1 million of these planned capital expenditures.
     
  • The Company's balance on its 2013 Senior Convertible Notes at year-end 2011 was $72.8 million.   The Company completed a total of four separately negotiated debt-for-equity exchange transactions with holders of the 2013 Senior Convertible Notes since year-end 2011. The debt for equity transactions have resulted in the issuance of 8,901,089 shares of common stock and has reduced the principal amount of the 2013 Senior Convertible Notes by $18.1 million leaving a principal balance of $54.7 million as of May 1, 2012.

Hedging Program Update

  • Our current strategy is to use swaps and costless collars to protect our flowing proved developed production, and use puts and put spreads to establish floors for our proved undeveloped production.  Since the forward prices for oil are less than the current prices for oil, our structure allows us to preserve the optionality benefits of oil price increases.  As we bring on new wells, we plan to increase our hedges to establish floors and protect revenues.
     
  • Bakken crude oil is produced and stored in tank batteries on location until the buyer picks up the oil by truck. The sales price realized is a function of the daily NYMEX contract price less an agreed upon basis differential which varies each month. The Company's basis differential in the Bakken has varied from month to month, ranging from a low of $5.50 in August of 2011 to as high as $25.00 in March of 2012. GMXR's basis differential in April was $12.00 and is estimated at $10.00 for the remainder of 2012 year.
     
  • The historical basis differential on the company's East Texas crude oil has been both a premium and discount to the daily NYMEX contract but in 2011, it was less than a $2.00 discount to NYMEX.
     
  • We have executed fixed-price natural gas swaps in late March against the NYMEX for approximately 65% of our post-processing dry natural gas for April 2012 through December 2013 period.  For the last nine months of 2012, we swapped 4.03 BCF at $2.60 and for all of 2013 we swapped 4.24 BCF at $3.50. In connection with these swaps, we also entered into a Basis Swap in which we locked in a natural gas price differential between the NYMEX and the Houston Ship Channel at $0.08. The combination of these trades effectively locks in a sales price to GMXR of $ 2.52 for 4.03 BCF during the last nine months of 2012, and $3.42 for 4.24 BCF during 2013.
     
  • Based on the current NYMEX natural gas price for April, May and June and our swap price of $2.60, the estimated revenue from our natural gas hedges will be approximately $695,000 in the second quarter 2012.  
     
  • We have executed fixed price crude oil swaps against the NYMEX for April 2012 through December 2013. For the last nine months of 2012, we swapped 38,565 barrels at $106.40 and for all of 2013 we swapped 42,581 barrels at $106.40. For 2014, we executed a costless three-way collar for 35,528 barrels with a ceiling of $114.10, a floor of $100 and a sold put of $80. In addition to the fixed price crude oil swaps and costless three-way collar, we bought $100- $90 put spreads for 19,421 barrels for the last six months of 2012, $100 puts for 26,654 barrels in 2013, and $95 - $75 put spreads for 19,893 barrels in 2014.

(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.

Management Comments

Michael J. Rohleder, President said "The first quarter of 2012 marks the beginning of the full scale development transition for GMXR. One year ago, we had not drilled a single well in North Dakota and we were producing minimal oil. Today we are on our way to a company record oil production quarter, we have substantially increased our proved oil reserves, and we are operating and participating in a total of twelve Bakken wells. Our well results and results from other operators have de-risked a substantial portion of our acreage in McKenzie and Billings counties. This transition was necessary and vital for the company. Natural gas pricing has continued to deteriorate, falling 35% in the first quarter, which is making life very difficult for operators focused primarily on gas. Our 2012 capital expenditures are focused only on oil, our drilling and completion costs are coming down and our results on a per well basis are improving. Our last three wells have had an average 1,973 Boe/d IP rate. Second quarter 2012 catalysts include the completion of as many as six additional wells, which we expect will contribute to our second quarter 2012 forecast of 80,000 barrels of oil. 

Challenges remain for the Company as we navigate through the most prolonged downturn in natural gas pricing the industry has experienced - we are now in the fourth year of lower prices. This environment has challenged all of us to think longer term while dealing with the immediate term and making investments necessary to continue to grow. We have met these economic challenges with creativity and investor support. We will continue to focus on resolving our near term liquidity needs with creative solutions across the spectrum of options available to us. We believe the combination of valuable oil assets, operational execution plus the option value of our natural gas reserves will be the foundation of our success moving forward."

First Quarter 2012 Conference Call Dial in Specifics

The Company has scheduled a conference call for Thursday, May 3, 2012 at 8:00 a.m. CDT (9:00 a.m. EDT) to discuss the first quarter 2012 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 71894779. A telephonic replay of the call will be available after 11:00 a.m. EDT on May 3, 2012 through May 10, 2012 and can be accessed using the following number and pass code: Toll free: (855) 859-2056 or (800) 585-8367 using pass code 71894779.   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=112199&CompanyID=GMXR&e=1&mediaKey=B6D3B9EAE6270A1344B4B56B803EF2BA

Financial Results for the Three Months Ended March 31, 2012

The Company reported a net loss applicable to common shareholders of $40.6 million ($0.66 per basic and fully diluted share) for the three months ended March 31, 2012, compared to a net loss applicable to common shareholders of $54.5 million ($1.29 per basic and fully diluted share) for the three months ended March 31, 2011, respectively.

Adjusted net loss applicable to common shareholders, a non-GAAP measure adjusting for items set forth below, was $12.1 million or $0.20 per basic and fully diluted share, for the three months ended March 31, 2012. Adjusted net loss is provided as a supplemental financial measure and we believe it provides additional information regarding our operating financial performance.

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.

 Three Months Ended
March 31, 2012
 AmountPer Share(1)
(in thousands, except for per share amounts)    
GAAP net loss applicable to common shareholders  $ (40,601)  $ (0.66)
Adjustments:    
Deferred income tax provision 1,887 0.03
Impairment of oil and natural gas properties and assets held for sale 28,999 0.47
Unrealized gain on changes in fair value of hedges (790) (0.01)
Non-cash interest expense (2) 1,228 0.02
Gain on extinguishment of debt (2,781) (0.05)
Adjusted net loss applicable to common shareholders  $ (12,058) $ (0.20)
     
(1)  Due to the adjusted net loss applicable to common shareholders for the three months ended March 31, 2012, 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 ended March 31, 2012 was 61,672,720.
(2)  Non-cash interest expense is related to the accounting for convertible bonds and the share lending agreement.

The following table summarizes certain key operating and financial results for the three months ended March 31, 2012 compared to the three months ended March 31, 2011.

Summary Operating Data

 Three Months Ended
March 31, 2012
 2012 (1)2011
Production:    
Oil (MBbls) 31 22
Natural gas (MMcf) 2,517 5,515
Natural gas liquids (MBbls) 146 66
Gas equivalent production (MMcfe) 3,576 6,040
Natural gas VPP volumes (MMcfe) 1,183 -
Gas equivalent production including VPP volumes (MMcfe) 4,759 6,040
Average daily production excluding VPP volumes (MMcfe) 39.3 67.1
Average daily production including VPP volumes (MMcfe) 52.3 67.1
Average Sales Price:    
Oil (per Bbl)    
Wellhead price  $ 93.97  $ 92.34
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives - -
Total  $ 93.97  $ 92.34
Natural gas liquids (per Bbl)    
Sales price  $ 34.91  $ 35.68
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives - -
Total  $ 34.91  $ 35.68
Natural gas (per Mcf)    
Wellhead price  $ 1.62  $ 3.67
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives 2.11 0.80
Total  $ 3.73  $ 4.47
Average sales price, excluding gain or loss from ineffectiveness of derivatives (per Mcfe)  $ 4.87  $ 4.80
Operating and Overhead Costs (per Mcfe):    
Lease operating expenses  $ 0.65  $ 0.48
Production and severance taxes (0.05) 0.07
General and administrative 1.47 1.17
Total  $ 2.07  $ 1.72
Other (per Mcfe):    
Depreciation, depletion and amortization-oil and natural gas properties  $ 1.66  $ 1.87
(1) For 2012, the amounts presented are net of the Volumetric Production Payment ("VPP") volumes, with exception of "Operating and Overhead Costs (per Mcfe)," which are presented gross of the VPP volumes.

Results of Operations for the Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended March 31, 2012 decreased 41% to $17.4 million compared to $29.4 million in the first quarter of 2011. The decrease in oil and gas sales was primarily due to a 21% decrease in production on a Bcfe-basis as a result of the natural decline from the Company's H/B production which was suspended in mid-2011 and 20% attributable to natural gas volumetric production payment ("VPP") volumes of 1.2 Bcfe that were sold in the form of a term overriding royalty interest in December 2011. The average price per barrel of oil, per barrel of natural gas liquid ("NGLs") and Mcf of natural gas received (exclusive of ineffectiveness from derivatives) in the three months ended March 31, 2012 was $93.97, $34.91 and $3.73, respectively, compared to $92.34, $35.68 and $4.47, respectively, in the three months ended March 31, 2011. This represented a 2% increase in oil prices, a 2% decrease in the average realized price in NGLs, and a 17% decrease in the average realized price of natural gas. Our realized sales price for natural gas, including revenue from NGLs and excluding the effect of hedges of $2.11 and $0.80, for the three months ended March 31, 2012 and 2011, respectively, was approximately 133% and 99% of the average NYMEX closing contract price for the respective periods. In the first quarter of 2012 and 2011, the conversion of natural gas to NGLs produced an upgrade of approximately $2.02 per Mcf and $0.43 per Mcf, respectively, for every Mcf of natural gas sold. For the three months ended March 31, 2012, oil and gas sales did not include gains or losses from the ineffectiveness of derivatives. For the three months ended March 31, 2011, oil and gas sales included a gain of $0.4 million from ineffectiveness of derivatives as a result of a difference in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point.

Natural gas production for the three months ended March 31, 2012 decreased to 2.5 Bcf compared to 5.5 Bcf for the three months ended March 31, 2011, a decrease of 54%. If we add back the VPP volumes of 1.2 Bcf, natural gas production decreased by 1.8 Bcf, or 33%. The decrease in natural gas production resulted primarily from the natural decline in the Company's H/B wells as a result of the suspension of the Company's H/B horizontal drilling program in mid-2011. The Company's last H/B well was completed and brought on line in August 2011. Oil production for the three months ended March 31, 2012 increased 41% to 31 MBbls, from 22 MBbls for the three months ended March 31, 2011, as a result of the Company's new Bakken production. For the first quarter of 2012, the Company produced 14,300 Bbls in the Bakken and 16,700 Bbls in East Texas compared to only having East Texas oil production in the first quarter of 2011. NGL production for the three months ended March 31, 2012 increased to 146 MBbls compared to 66 MBbls for the three months ended March 31, 2011, an increase of 121%. This increase was due primarily to a change in the dispatch of our natural gas to plants with higher NGL recoveries and plant efficiencies, which first became available to us in April 2011 and which continued to expand their capacity to process our gas throughout 2011.

For the three months ended March 31, 2012, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $5.3 million compared to an increase in natural gas sales of $4.4 million in the first quarter of 2011. In the first quarter of 2012, hedging, excluding ineffectiveness, increased the average natural gas sales price by $2.11 per Mcf compared to an increase in natural gas sales price of $0.80 per Mcf in the first quarter of 2011. The increase in natural gas sales and sales price, as a result of hedging activities for the three months ended March 31, 2012, was due to the amortization of realized gain on our cash flow hedges that we monetized in the fourth quarter 2011. The realized gain recorded in other comprehensive income will be amortized into earnings ratably through 2013. Our derivative contracts on oil had no effect on our oil sales for the three months ended March 31, 2012 and 2011.

Lease Operations. Lease operations expense increased $0.2 million, or 7%, for the three months ended March 31, 2012, to $3.1 million, compared to $2.9 million for the three months ended March 31, 2011. The increase in lease operating expenses is due to higher lease operating expenses related to the Company's Bakken oil production.

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. For the three months ended March 31, 2012, accounts receivable recorded was greater than the severance tax expense recorded resulting in income of $0.2 million in the three months ended March 31, 2012 compared to expense of $0.4 million in the three months ended March 31, 2011. In the first quarter of 2012, the Company reversed an accrual for certain third party costs related to the preparation of severance tax refund requests that had been historically netted against the refunds. The severance tax refund requests are now being prepared internally by the Company.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $5.3 million, or 42%, to $7.5 million in the three months ended March 31, 2012 compared to $12.8 million for the three months ended March 31, 2011. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.66 per Mcfe in the three months ended March 31, 2012 compared to $1.87 per Mcfe in the three months ended March 31, 2011. This decrease in the rate per Mcfe is due to the recent impairment charges recognized by the Company which has lowered the amount of oil and gas properties subject to amortization.

Impairment of oil and natural gas properties and assets held for sale.  For the $29.0 million impairment charge recorded in the first quarter of 2012, $28.9 million was related to the impairment of oil and gas properties subject to the full cost ceiling test and $0.1 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 70% of the Company's total production at the end of the first quarter 2012. During the first quarter of 2012, the 12-month average of the first day of the month natural gas price decreased 9% from $4.12 per MMbtu at December 31, 2011 to $3.73 per MMbtu at March 31, 2012, contributing to the impairment for the first quarter of 2012. The $28.9 million impairment of oil and gas properties resulted from the decrease in natural gas prices, decrease in non-Bakken reserves, and higher lease operating expenses, offset by approximately $8.0 million of Bakken PV-10 additions exceeding Bakken related capital expenditures.

General and Administrative Expense. General and administrative expense for the three months ended March 31, 2012 was $7.0 million, compared to $7.1 million for the three months ended March 31, 2011, a decrease of $0.1 million, or 1%. General and administrative expenses include $0.9 million and $1.2 million of non-cash compensation expense as of the three months ended March 31, 2012 and 2011, respectively. Non-cash compensation represented 13% and 17% of total general and administrative expenses, for the three months ended March 31, 2012 and 2011, 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 March 31, 2012 was $10.7 million compared to $8.0 million for the same period in 2011. For the three months ended March 31, 2012 and 2011, interest expense includes non-cash interest expense of $1.2 million and $1.5 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the three months ended March 31, 2012 and 2011 was $11.3 million and $6.6 million, respectively, of which $2.7 million and $0.9 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $4.7 million was mainly due to the Company's issuance and sale in February 2011 of $200 million aggregate principal amount of 11.375% Senior Notes due 2019. In December 2011, the Company completed an exchange offer for all but $2 million of the 11.375% Senior Notes due 2019 which resulted in $283.5 million of new Senior Secured Notes due 2017. As part of the exchange, certain backstop parties purchased an additional $100 million of the Senior Secured Notes. The Indenture for the Senior Secured Notes provides the Company with a PIK option that allows for a 9% cash interest payment along with additional Senior Secured Notes of 4% resulting in an annual interest rate of 13%. For the first semi-annual interest payment on the Senior Secured Notes due June 1, 2012, the Company has elected the PIK option and has accrued interest at the higher rate.

Income Taxes. Income tax expense for the three months ended March 31, 2012 was $1.9 million as compared to $1.4 million in the same period in 2011. The income tax expense recognized in the three months ended March 31, 2012 and 2011, 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 gains on derivative contracts designated as hedges where the mark-to-market change on the hedges, net of deferred taxes, is recorded to other comprehensive income.

Net income to non-controlling interest. Net income to non-controlling interest was $0.9 million for the three months ended March 31, 2012 compared to $1.4 million for the three months ended March 31, 2011. This decrease was due lower natural gas production in East Texas.

Net Loss and Net Loss Per Share

Net Loss and Net Loss Per Share-Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. For the three months ended March 31, 2012, we reported a net loss applicable to common shareholders of $40.6 million, and for the three months ended March 31, 2011 we reported a net loss applicable to common shareholders of $54.5 million. Net loss per basic and fully diluted share was $0.66 for the first quarter of 2012 compared to net loss per basic and fully diluted share of $1.29 for the first quarter of 2011.

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. We plan to continue to hedge oil and natural gas in the future to mitigate our commodity price risk.

As of March 31, 2012, we had cash, cash equivalents and short-term investments of $77.4 million, including $4.3 million in restricted cash and $2.0 million in short-term investments. Through the period ended March 31, 2012, we have funded our operating expenses and capital expenditures through operating cash flows and from capital raised in December of 2011 which included $100 million from a bond exchange of our 11.375% Senior Noted due 2019 for our new Senior Secured Notes due 2017, $49.7 million in connection with the VPP, and $18.5 million from the December 2011 monetization of the Company's then existing hedge portfolio.

We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry and market conditions and the availability of capital. In the first three months of 2012, our cash outlay for capital expenditures was $25.1 million. We anticipate funding approximately $97 million of cash capital expenditures in 2012 with cash on hand, positive operating cash flow, and asset sales or other potential capital market activities. Our 2012 capital expenditure budget will focus on our Bakken development plans particularly in McKenzie and Billings Counties of North Dakota. In the Bakken, we are currently running one drilling rig. Based on available liquidity, we plan to add a second rig in the Bakken during the third quarter of 2012. In the Niobrara, we will continue to evaluate our seismic work and surrounding well results from other operators with only minimal capital expenditures related to the completion of our seismic project.

The Company's balance on its 2013 Senior Convertible Notes at year-end 2011 was $72.8 million.   The Company completed a total of four separately negotiated debt-for-equity exchange transactions with holders of the 2013 Senior Convertible Notes since year-end 2011. Three of these exchange transactions were completed in March 2012 resulting in the issuance of 6,187,005 shares of our common stock and reduced the debt on the 2013 Senior Convertible Notes by $13.4 million leaving a principal balance of $59.4 million as of March 31, 2012. The fourth exchange transaction for $4.7 million in 2013 Senior Convertible Notes was completed on May 1, 2012 resulting in the issuance of 2,714,084 shares of our common stock and leaving a principal balance of $54.7 million. During 2012, we will continue to evaluate additional opportunities to exchange our equity securities for our 5.00% Convertible Notes and other refinancing and repayment options allowed under the Senior Secured Notes to address the 2013 maturity of these notes.

In order to protect us against the financial impact of a decline in oil and natural gas prices, we have an active hedging program. We executed in late March fixed price natural gas swaps against the NYMEX for approximately 65% of our post-processing dry natural gas for the period of April 2012 through December 2013.  For the last nine months of 2012, we swapped 4.03 BCF at $2.60 and for all of 2013 we swapped 4.24 BCF at $3.50. In connection with these swaps, we also entered into a basis swap in which we locked in a natural gas price differential between the NYMEX and the Houston Ship Channel at $0.08. The combination of these trades effectively locks in a sales price to GMXR of $2.52 for 4.03 BCF during the last nine months of 2012, and $3.42 for 4.24 BCF during 2013.

We executed in late March fixed price crude oil swaps against the NYMEX for April 2012 thru December 2013. For the last nine months of 2012, we swapped 38,565 barrels at $106.40 and for all of 2013 we swapped 42,581 barrels at $106.40. For 2014, we executed a costless three-way collar for 35,528 barrels with a ceiling of $114.10, a floor of $100 and a sold put of $80. We also bought $100- $90 put spreads for 19,421 barrels for the last six months of 2012, $100 puts for 26,654 barrels in 2013, and $95 - $75 put spreads for 19,893 barrels in 2014.

Our strategy is to use swaps and costless collars to protect our flowing proved developed production, and use puts and put spreads to establish floors for our proved undeveloped production.  Since the forward prices for oil are less than the current prices for oil, our structure allows us to preserve the optionality benefits of oil price increases.  As we bring on new wells, we plan to increase our hedges to establish floors and protect revenues.

GMXR is a resource play rich E&P company with development acreage in two oil shale resources in the Bakken (North Dakota / Montana) targeting the Bakken & Sanish-Three Forks and the DJ Basin (Wyoming) targeting the Niobrara Formation; both plays are 90% oil. Our natural gas resources are located in the East Texas Basin, in the Haynesville/Bossier gas shale and the Cotton Valley Sand Formation, where the majority of our acreage is contiguous and held by production. We believe these oil and natural gas resource plays provide a substantial inventory of operated, high probability, repeatable, organic growth opportunities. The Bakken properties contain nearly 600 undrilled, 9,500' lateral length locations, 43 potential operated 1280-acre units and 197 operated locations, with between 45% and 100% working interest.   The Niobrara properties contain 584 undrilled, 4,000' lateral length locations, 95 potential operated 640-acre units and 380 operated locations, with an average working interest of 70%. The Haynesville/Bossier and the Cotton Valley Sand locations include 253 net Haynesville/Bossier horizontal locations, and 83 net Cotton Valley Sand horizontal locations. The Company believes multiple basins and both oil and natural gas resource choices provide us with flexibility to allocate capital to achieve the highest risk adjusted rate of return on our portfolio. Please visit www.gmxresources.com for more information on the Company.

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

GMX Resources Inc. and Subsidiaries
Consolidated Balance Sheets
(dollars in thousands, except share data)
(Unaudited)
     
 March 31,
2012
December 31,
2011
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents  $ 71,079  $ 102,493
Restricted cash 4,325 4,325
Short-term investments 2,000 -
Accounts receivable interest owners 7,904 8,607
Accounts receivable oil and natural gas revenues, net 5,695 7,082
Derivative instruments 778 -
Inventories 326 326
Prepaid expenses and deposits 2,211 2,655
Assets held for sale 1,910 2,045
Total current assets 96,228 127,533
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD  
Properties being amortized 1,085,361 1,062,801
Properties not subject to amortization 153,085 147,224
Less accumulated depreciation, depletion, and impairment (906,232) (871,346)
  332,214 338,679
PROPERTY AND EQUIPMENT, AT COST, NET 64,464 65,858
DERIVATIVE INSTRUMENTS 500 -
OTHER ASSETS 8,983 10,131
TOTAL ASSETS  $ 502,389  $ 542,201
LIABILITIES AND EQUITY    
CURRENT LIABILITIES:    
Accounts payable  $ 12,919  $ 13,550
Accrued expenses 14,485 17,835
Accrued interest 12,557 3,256
Revenue distributions payable 5,411 5,980
Current maturities of long-term debt 58,151 26
Total current liabilities 103,523 40,647
LONG-TERM DEBT, LESS CURRENT MATURITIES 356,958 426,805
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS 312 -
OTHER LIABILITIES 7,684 7,476
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, 6,000,000 shares authorized, 3,176,734 shares issued and outstanding as of March 31, 2012 and December 31, 2011 (aggregate liquidation preference $79,418 as of March 31, 2012 and December 31, 2011) 3 3
Common stock, par value $.001 per share 100,000,000 shares authorized, 69,272,437 shares issued and outstanding as of March 31, 2012 and 63,085,432 shares issued and outstanding as of December 31, 2011 69 63
Additional paid-in capital 702,041 690,986
Accumulated deficit (689,942) (649,341)
Accumulated other comprehensive income, net of taxes 10,517 14,029
Total GMX Resources' equity 22,688 55,740
Noncontrolling interest 11,224 11,533
Total equity 33,912 67,273
TOTAL LIABILITIES AND EQUITY  $ 502,389  $ 542,201
 
 
GMX Resources Inc. and Subsidiaries
Consolidated Statements of Operations
(dollars in thousands, except share and per share data)
(Unaudited)
     
 Three Months Ended
March 31,
 20122011
OIL AND GAS SALES, net of gain from ineffectiveness of derivatives of $0 and $408, respectively  $ 17,401  $ 29,376
EXPENSES:    
Lease operations 3,108 2,898
Production and severance taxes (237) 383
Depreciation, depletion, and amortization 7,465 12,789
Impairment of oil and natural gas properties and assets held for sale 28,999 48,320
General and administrative 6,995 7,077
Total expenses 46,330 71,467
Loss from operations (28,929) (42,091)
NON-OPERATING INCOME (EXPENSES):    
Interest expense (10,702) (8,022)
Gain (loss) on extinguishment of debt 2,781 (108)
Interest and other income 72 269
Unrealized gain (loss) on derivatives 790 (444)
Total non-operating expense (7,059) (8,305)
Loss before income taxes (35,988) (50,396)
INCOME TAX PROVISION (1,887) (1,432)
NET LOSS (37,875) (51,828)
Net income attributable to noncontrolling interest 889 1,412
NET LOSS APPLICABLE TO GMX RESOURCES (38,764) (53,240)
Preferred stock dividends 1,837 1,210
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS $ (40,601)  $ (54,450)
LOSS PER SHARE Basic $ (0.66) $ (1.29)
LOSS PER SHARE Diluted $ (0.66) $ (1.29)
WEIGHTED AVERAGE COMMON SHARES Basic 61,672,720 42,150,589
WEIGHTED AVERAGE COMMON SHARES Diluted 61,672,720 42,150,589
 
 
GMX Resources Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(dollars in thousands)
(Unaudited)
 Three Months Ended
March 31,
 20122011
CASH FLOWS DUE TO OPERATING ACTIVITIES    
Net loss $ (37,875) $ (51,828)
Depreciation, depletion, and amortization 7,465 12,789
Impairment of oil and natural gas properties and assets held for sale 28,999 48,320
Change in fair value of hedges (790) 37
Deferred income taxes 1,887 1,431
Non-cash compensation expense 832 1,159
(Gain) loss on extinguishment of debt (2,781) 108
Non-cash interest expense 2,115 2,403
Non-cash derivative gain in oil and gas sales (5,321) -
Other (28) -
Decrease (increase) in:    
Accounts receivable 2,090 1,613
Inventory and prepaid expenses 770 (322)
Increase (decrease) in:    
Accounts payable and accrued liabilities 2,037 (155)
Revenue distributions payable (574) 992
Net cash (used in) provided by operating activities (1,174) 16,547
CASH FLOWS DUE TO INVESTING ACTIVITIES    
Purchase of oil and natural gas properties (24,924) (85,872)
Proceeds from sale of oil and natural gas properties, property, plant, equipment and assets held for sale 140 2,079
Purchase of short-term investments (2,000) -
Purchase of property and equipment (322) (935)
Net cash used in investing activities (27,106) (84,728)
CASH FLOWS DUE TO FINANCING ACTIVITIES    
Borrowings on revolving bank credit facility - 18,000
Repayments of long-term debt (13) (160,022)
Proceeds from issuance of long-term debt - 193,666
Proceeds from sale of common stock - 105,324
Proceeds from sale of preferred stock - 6,915
Dividends paid on Series B preferred stock (1,837) (1,210)
Fees paid related to financing activities (86) (15,890)
Contributions from non-controlling interest member - 60
Distributions to non-controlling interest member (1,198) (3,378)
Net cash (used in) provided by financing activities (3,134) 143,465
NET (DECREASE) INCREASE IN CASH (31,414) 75,284
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 102,493 2,357
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 71,079 $ 77,641
SUPPLEMENTAL CASH FLOW DISCLOSURE    
CASH PAID DURING THE PERIOD FOR:    
INTEREST, Net of amounts capitalized $ 1,368 $ 4,318
INCOME TAXES, Paid $ - $ 1
NON-CASH INVESTING AND FINANCING ACTIVITIES    
Debt extinguished with common stock $ 13,378 $ -
Additions to oil and natural gas properties from issuance of common stock $ - $ 13,614
Decrease in accounts payable for property additions $ 3,120 $ 10,624
 
 
GMX Resources Inc. and Subsidiaries 
Non-GAAP Supplemental Information - Discretionary Cash Flows (1) 
 (dollars in thousands)
     
 Three Months Ended
March 31,
 20122011
Net loss $ (37,875) $ (51,828)
Non cash charges:    
Depreciation, depletion, and amortization 7,465 12,789
Impairment and other write-downs 28,999 48,320
Deferred income tax provision 1,887 1,431
Non-cash compensation expense 832 1,159
(Gain) loss on extinguishment of debt (2,781) 108
Non-cash interest expense 2,115 2,403
Unrealized gain on changes in fair value of hedges (790) 37
Non-cash derivative gains in oil and gas sales (5,321) -
Other (28) -
Net income attributable to noncontrolling interest (889) (1,412)
Preferred stock dividends (1,837) (1,210)
Non-GAAP discretionary cash flow $ (8,223) $ 11,797
Net cash provided by operating activities $ (1,174) $ 16,547
Adjustments:    
Changes in operating assets and liabilities (4,323) (2,128)
Net income attributable to noncontrolling interest (889) (1,412)
Preferred stock dividends (1,837) (1,210)
Non-GAAP discretionary cash flow $ (8,223) $ 11,797
(1) Discretionary cash flow represents cash provided by operating activities before changes in assets and liabilities less preferred dividends. Discretionary cash flow is presented because we believe it is a useful additional consideration along with net cash provided by operating activities under accounting principles generally accepted in the United States ("GAAP"). Discretionary cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash that is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors in the valuation, comparison and investment recommendations of companies within the natural gas and oil 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. The manner in which we calculate discretionary cash flow may differ from that utilized by other companies.
 
 
GMX Resources Inc. and Subsidiaries 
Non-GAAP Reconciliations - Adjusted EBITDA (1) 
         
         
 Three Months EndedTrailing Twelve Months Ended
Reconciliation of GAAP "Net Income"March 31,March 31,
to Non-GAAP Adjusted EBITDA2012201120122011
         
(Dollars in Thousands)        
Net loss $ (37,875) $ (51,828) $ (195,248) $ (195,407)
Adjustments:        
Depreciation, depletion, and amortization 7,465 12,789 44,946 44,480
Certain non-cash income and adjustments for unrestricted subsidiaries (909) (692) (5,106) (1,039)
Distributions from unrestricted subsidiaries 299 844 3,160 1,934
Impairment and other write-downs 28,999 48,320 186,433 192,033
Deferred income tax provision 1,887 1,432 1,070 2,981
Interest expense 10,702 8,022 34,647 22,435
Change in fair value of hedges (790) 37 (4,552) 1,748
Loss (gain) on extinguishment of debt (2,781) 108 (5,217) (33)
Adjusted EBITDA $ 6,997 $ 19,032 $ 60,133 $ 69,132
(1)  Adjusted EBITDA represents earnings before interest, taxes, depletion, depreciation & amortization and includes non-cash compensation, hedging and derivative activities and other expenses. Adjusted EBITDA is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors in the valuation, comparison and investment recommendations of companies. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.
CONTACT: Alan Van Horn
         Manager, Investor Relations
         405.254.5839

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