updated 3/3/2011 7:15:57 AM ET 2011-03-03T12:15:57

OKLAHOMA CITY, March 2, 2011 (GLOBE NEWSWIRE) -- GMX RESOURCES INC., (NYSE:GMXR), reports today on fourth quarter and year end 2010 financial and operating results.

The Company has scheduled a conference call for Thursday, March 3, 2011 at 8:00 a.m. CST (9:00 a.m. EST) to discuss fourth quarter and annual 2010 financial and operating results. To access the call, dial (877) 303-9132 or (408) 337-0136 prior to the conference call start time. Please reference conference code 45454158. A replay of the call will be available after 11:00 a.m. EST on March 3, 2011 through March 17, 2011 and can be accessed using the following number and pass code. Toll free: (800) 642-1687 or (706) 645-9291. Replay conference code 45454158.    A presentation pertaining to this call will be available on the Company's website no later than 6:00 a.m. CST, March 3, 2011.  www.gmxresources.com

Management Comments

Ken L. Kenworthy, Jr., Chairman and Chief Executive Officer, said, "2010 was another challenging year for our industry. Natural gas prices continued to deteriorate throughout the year and contrary to historical norms we did not experience a commensurate decrease in service costs. Throughout the year GMXR continued to focus on cost control and improving well performance. Our Haynesville/Bossier ("H/B") horizontal ("Hz") drilling program was successful – we increased our H/B proved reserves 800%. Our production of 17.5 BCFE was 28% higher than 2009 - a company record. Based on improved well results, we are forecasting an increase in production for 2011. In spite of limited access to completion services for most of the year and higher stimulation costs, we managed to drill and complete 19 H/B Hz wells at an average cost of $8.6 million and we do expect costs to decline in 2011.  Our G&A costs, on a per unit basis, came down sequentially from 3Q10 to 4Q10 by 7% and our LOE on a per unit basis came down 29% from the previous year."

"We were successful developing the regulatory and legal mechanisms to be able to drill laterals longer than 6000' in our core acreage and the first two long lateral wells were drilled and completed in Q4. Long laterals greater than 6000' will be the only H/B Hz wells we plan to drill in 2011.  We also activated a dedicated Acquisitions team in early 2010 focused exclusively on finding new growth opportunities for the company and we succeeded in negotiating several significant acreage acquisitions in the Bakken and Niobrara oil plays that will transform GMXR in the next eighteen months. We now have 67,000 acres in these two oil basins which represents 60% of our total acreage."

Operational and Financial Highlights for the Three Months and Year Ended December 31, 2010

  • Net loss applicable to common shareholders was $149 million and $146 million or $(5.27) per share and $(5.18) per share for the three months and year ending December 31, 2010, respectively.
  • As detailed below, non-GAAP net income available to common shareholders per share was $(0.06) and $0.10 for the three months and year ended December 31, 2010, respectively. 2010 non-GAAP EPS was impacted by additional DD&A recognized in fourth quarter of 2010 due to previously announced revisions of Cotton Valley estimated proved reserves. DD&A for our oil and natural gas properties was $2.25 per Mcfe and $1.88 per Mcfe for the three months and year ended December 31, 2010 compared to $1.77 per Mcfe and $1.76 per Mcfe for the respective periods in 2009.
  • Lease operating expenses were $0.47 per Mcfe and $0.61 per Mcfe for the three months and year ended December 31, 2010, respectively, compared to $0.89 per Mcfe and $0.86 per Mcfe for the respective periods in 2009.
  • General and administrative expenses were $1.33 per Mcfe and $1.55 per Mcfe for the three months and year ended December 31, 2010, respectively, compared to $1.89 per Mcfe and $1.57 per Mcfe for the respective periods in 2009.
  • Adjusted EBITDA(1) of $16.9 million and $61.9 million for the three months and year ended December 31, 2010, respectively, compared to $16.1 million and $66.0 million for the respective periods in 2009.
  • Discretionary cash flow(1)  of $13.1 million and $47.6 million for the three months and year ended December 31, 2010, respectively, compared to $11.8 million and $50.8 million for the respective periods in 2009.
  • Production for fourth quarter of 2010 was 5.3 BCFE up 48% from the fourth quarter of  2009 and production for the year was 17.5 BCFE up 28% from 2009. Production in the fourth quarter 2010 increased 14% over the third quarter of 2010.
  • 2010 year-end Haynesville/Bossier estimated proved reserves increased 206 BCFE, or 800%, compared to year-end 2009. In addition the PV-10 value of these reserves at December 31, 2010 was $151.9 million, up from $32.8 million at year-end 2009.
  • Well costs for fourth quarter of 2010 averaged approximately $9.0 million, which was $0.5 million less than previously forecasted by the Company.
  • The Company completed a total of eight H/B Hz wells during the fourth quarter of 2010 which was a Company record number of completions in a single quarter and attributable to the increased availability of fracture stimulation services.
  • The Company's total estimated proved reserves at December 31, 2010 are 319.3 BCFE a decrease of approximately 10% from December 31, 2009 total estimated proved reserves of 355.3 BCFE. Year-end 2010 Cotton Valley Sand, Travis Peak, and other non-Haynesville/Bossier reserves are 85.2 BCFE, a decrease of 244.2 BCFE compared to year-end 2009 reserves of 329.4 BCFE. The Company removed all Cotton Valley Sand vertical well PUDs, representing 219.6 BCFE of the decrease, for adherence with the SEC 5-year guideline for booking reserves due to the Company's new focus on the oil resource plays recently acquired, as well as, the intention to develop the Cotton Valley Sands on a horizontal basis.
  • The Company established itself as a leader in long lateral (>6,000') drilling in the Haynesville/Bossier play by working with regulatory and legal frameworks that facilitate cross-unit boundaries and create production sharing units that allow long lateral drilling.
  • The Company created a Mergers and Acquisitions team dedicated to pursuing opportunities that will ultimately become the future growth engine of the Company. The team evaluated 30 different opportunities in addition to over 300,000 acres in the Rockies.

(1) Adjusted net income 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.

Financial Results for the Three Months and Year Ended December 31, 2010

The Company reported 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, compared to a net loss applicable to common shareholders of $48.8 million ($1.88 per basic and fully diluted share) and $185.9 million ($9.20 per basic and fully diluted share) for the respective periods in 2009. 

Adjusted net income (loss) available to common shareholders, a non-GAAP measure adjusting for items set forth below, was $(1.8 million) or $(0.06) per basic and fully diluted share and $2.6 million or $0.10 per basic and fully diluted share for the three months and year ended December 31, 2010, respectively:

  Three Months Ended

December 31, 2010
Year Ended

December 31, 2010
(in thousands, except for per share amounts) Amount Per

Share (1)
Amount Per

Share(1)
GAAP Net income (loss) applicable to common shareholders $ (149,045) $ (5.27) $ (146,039) $ (5.18)
         
Adjustments:        
         
One-time severance costs (2) -- -- 1,525 0.05
Impairment of oil and natural gas properties  132,832  4.70   132,832 4.71
Impairment on assets held for sale 10,880 0.38 10,880 0.39
Unrealized loss on derivative contracts 19 -- 122 --
Ineffectiveness of cash flow hedges  (93)  -- 1,280 0.05
Non-cash interest expense (3)  1,627  0.06 6,383 0.23
Deferred income tax valuation allowance  2,115  0.07 (4,239) (0.15)
Extinguishment of debt  (141) --  (141) --
         
Adjusted net income (loss) applicable to common shareholders  $ (1,806)  $ (0.06) $ 2,603  $ 0.10
 
(1) Per share amounts for the year ended December 31, 2010 are calculated on a fully dilutive basis except for GAAP Net income (loss) applicable to common shareholders which was calculated using the basic number of outstanding shares. Due to the adjusted net loss applicable to common stock for the three months ended December 31, 2010, per share amounts are calculated using the basic number of shares which excludes items that would be antidilutive.
(2) One-time compensation costs were incurred due to the resignation of certain operation personnel in March 2010 and include approximately $0.6 million in cash costs and $0.9 million in non-cash compensation costs related to the acceleration of vesting for restricted stock and stock options.
(3) 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, 2010 and 2009:

  Year Ended December 31, Quarter Ended December 31,
     
  2010 2009   2010 2009  
Production:        
Oil (MBbls)  95  119 24 28
Natural gas (MMcf)  16,901  12,908 5,168 3,430
Gas equivalent (MMcfe)  17,474  13,620 5,314 3,597
Average daily (MMcfe)  47.9  37.3 57.8 39.1
         
Average Sales Price:        
Oil (per Bbl)        
Wellhead price $ 76.77 $ 56.61 $ 81.96 $ 74.45
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives  —   19.41 13.82
         
Total $ 76.77 $ 76.02 $ 81.96 $ 88.27
         
Natural gas (per Mcf)        
Wellhead price $ 3.96 $ 3.85 $ 3.54 $ 4.45
Effect of hedges, excluding gain or loss from ineffectiveness of derivatives  1.39  2.68 1.32 2.29
         
Total $ 5.35 $ 6.53 $ 4.86 $ 6.74
         
Average sales price, excluding gain or loss from ineffectiveness of derivatives (per Mcfe) $ 5.60 $ 6.85 $ 5.10 $ 7.11
         
Operating and Overhead Costs (per Mcfe):        
Lease operating expenses $ 0.61 $ 0.86 $  0.47 $ 0.89
Production and severance taxes   0.04   (0.07) 0.06  0.04
General and administrative 1.55  1.57  1.33 1.89
         
Total $ 2.20 $ 2.36 $ 1.86 $ 2.82
         
Other (per Mcfe):        
Depreciation, depletion and amortization—oil and natural gas production $ 1.88 $ 1.76 $ 2.25 $ 1.77

Production.  Production for the three months and year ended December 31, 2010 was 5.3 Bcfe and 17.5 Bcfe, respectively, compared to 3.6 Bcfe and 13.6 Bcfe for the three months and year ended December 31, 2009, increases of 48% and 28% from the respective 2009 periods. Production of oil for the three months and year ended December 31, 2010 decreased to 24 MBbls and 95 MBbls, respectively, compared to 28 MBbls and 119 MBbls for the same periods in 2009. Natural gas production for the three months and year ended December 31, 2010 increased to 5.2 Bcf and 16.9 Bcf, respectively, compared to 3.4 Bcf and 12.9 Bcf for the same periods in 2009, an increase of 51% and 31% respectively. Greater production of natural gas in the three months and year ended December 31, 2010 was the result of the Company's continued development of H/B Hz wells. We expect increases in production in 2011 as we continue our H/B Hz drilling program. 

Oil and Natural Gas Sales. Oil and natural gas sales in the three months and year ended December 31, 2010 increased 6% and 2% to $27.2 million and $96.5 million, respectively, compared to the same periods in 2009. This was due to an increase in oil and natural gas production of 48% and 28% between the three months and year ended December 31, 2010 and 2009, respectively, and offset by an 18% and 28% reduction in average sales price between the three months and the year ended 2010 and 2009, respectively. The average price per barrel of oil and Mcf of natural gas received in the three months and year ended December 31, 2010 was $81.96 and $4.86, and $76.77 and $5.35, respectively, compared to $88.27 and $6.74, and $76.02 and $6.53 for the same respective periods in 2009. 

In the three months and year ended December 31, 2010, as a result of hedging activities excluding non-cash derivative ineffectiveness, we recognized an increase in natural gas sales of $6.8 million and $23.6 million respectively, compared to an increase in oil and natural gas sales of $8.1 million and $36.9 million for the same respective periods in 2009. In the fourth quarter and full year 2010, hedging increased the average natural gas sales price by $1.32 per Mcf and $1.39 per Mcf, respectively, compared to an increase in natural gas sales price of $2.29 per Mcf and $2.68 Mcf for the same periods in 2009. Hedging activities excluding non-cash derivative ineffectiveness, increased our average oil sale price by $13.82 per Bbl and $19.41 per Bbl in the three months and year ended December 31, 2009, respectively.

Lease Operations. Lease operating expense decreased $0.7 million and $1.1 million, or 22% and 10%, for the three months and year ended December 31, 2010 compared to the same periods in 2009. Lease operating expense on an equivalent unit of production basis was $0.47 per Mcfe and $0.61 per Mcfe in the three months and year ended December 31, 2010 compared to $0.89 per Mcfe and $0.86 per Mcfe for the same periods in 2009. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in H/B Hz well production and cost control measures implemented in 2010. With little to no incremental increase in lease operating costs from a typical Cotton Valley vertical well, the significantly larger amount of production from a typical H/B Hz well results in lower per unit lease operating cost. Lease operating expense will continue to grow throughout 2011 as the number of producing wells increase; however, we expect lease operating expense on a per unit basis to continue to decline during 2011 as additional production comes on line from our H/B Hz drilling program.

Production and Severance Taxes. Production and severance taxes increased 106% and 180% to $0.3 million and $0.7 million in the three months and year ended December 31, 2010, respectively, compared to $0.1 million and a benefit of $0.9 million for the same periods in 2009. Production and severance taxes are assessed on the value of the oil and natural gas produced. The increase resulted from increased gas sales offset to some extent from lower oil and natural gas sales prices as well as procedural changes for accounting for severance refunds due for exempt gas wells. 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 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.

General and Administrative Expense. General and administrative expense for the three months and year ended December 31, 2010 were $7.1 million and $27.1 million, respectively, compared to $6.8 million and $21.4 million for the same periods in 2009. The increase of $5.7 million, or 27%, between the years 2010 and 2009 was due to an increase in administrative and supervisory personnel, severance compensation, as well as an increase in corporate operating expenses due to our growth. General and administrative expense per equivalent unit of production was $1.33 per Mcfe and $1.55 per Mcfe for the three months and year ended December 31, 2010, respectively, compared to $1.89 per Mcfe and $1.57 for the comparable periods in 2009. Approximately, $5.5 million or 20% of the general and administrative expenses in 2010 was related to non-cash compensation expense compared to $4.6 million or 22% in 2009. 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. The Company expects general and administrative expenses on a per Mcfe basis to decrease as production increases.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $5.6 million and $7.1 million, or 72% and 23%, to $13.4 million and $38.1 million in the three months and year ended December 31, 2010, respectively. The oil and natural gas properties depreciation, depletion and amortization rate per equivalent unit of production was $2.25 per Mcfe and $1.88 per Mcfe in the three months and year ended December 31, 2010, respectively, compared to $1.77 per Mcfe and $1.76 for the same periods in 2009. The increase is due to current year production being a greater percentage of the total proved reserves as a result of negative reserve revisions to the Cotton Valley proved reserves in 2010.

Impairment of Oil and Natural Gas Properties and Assets Held for Sale. As a result of the removal of the Company's proved undeveloped Cotton Valley Sand Reserves from the year end 2010 reserve report, the reduction in the present value at 10% of the reserves limited the amount of oil and gas properties that could be capitalized on the balance sheet under the SEC's "ceiling" test, we recognized an impairment charge on oil and gas properties of $132.8 million in the fourth quarter and year ended December 31, 2010 compared to an impairment charge on oil and gas properties of $50.1 million and $188.2 million for the three months and the year ended December 31, 2009, respectively. The Company may be required to recognize additional impairment charges or writedowns in future reporting periods if market prices for oil or natural gas continue to decline or remain at their depressed levels. In addition, the Company impaired an additional $10.9 million related to assets held for sale as of December 31, 2010.

Interest. Interest expense for the three months and year ended December 31, 2010 was $5.0 million and $18.6 million compared to $4.2 million and $16.7 million for the same period in 2009.   Interest expense for the three months and year ended December 31, 2010 includes non-cash interest of $1.6 million and $6.4 million, respectively, related to the accretion of the 5.00% senior convertible notes due 2013, the 4.50% senior convertible notes due 2015, the deferred premiums on derivative instruments and the amortization of the share lending agreement.

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. 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 the risk of declines in crude oil and natural gas prices, we typically enter into crude oil and natural gas swaps, collars, three-way collars, and put spreads.

For the year ended December 31, 2010, our capital expenditures were $190.7 million, of which:

  • $166.5 million was for drilling and completing H/B Hz wells;
  • $4.0 million was for rig delay fees;
  • $2.6 million on Cotton Valley Sands and Travis Peak drilling and other drilling related expenditures including tubular inventory; and
  • $17.6 million was related to leasehold and infrastructure costs.

During 2010, we funded our H/B Hz drilling program through cash flows from operations, available cash of $35.5 million at the beginning of 2010, and $92 million from borrowings under our bank credit facility. We currently expect to spend cash capital expenditures of $224 million in 2011, including the payment of an anticipated $56 million for the cash portion of the Bakken and Niobrara acreage acquisitions announced in January 2011. We also anticipate issuing approximately 6.8 million common shares in connection with these acreage acquisitions. We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry conditions and the availability of capital. Based on management's current oil and natural gas price expectations for the year ended December 31, 2011, we anticipate that we will have sufficient sources of working capital, including net proceeds from the offerings of our Senior Notes and common stock completed in February 2011, our current, including cash on hand, cash flow from operating activities, proceeds from assets held for sale and availability under our revolving bank credit facility ($60 million as of March 2, 2011), to meet our cash obligations for our 2011 fiscal year, including to fund our one-rig Haynesville/Bossier horizontal drilling program, the 2011 acreage acquisitions in the Bakken and Niobrara, and our anticipated drilling programs in these two new oil plays. We will continually adjust our capital expenditures based on the current and forecasted commodity price environment to ensure that we have adequate liquidity in cash and/or availability under our revolving bank credit facility.

We anticipate using various derivative contracts such as puts, put spreads, and collars to mitigate natural gas and crude oil price risk on 60% to 80% of our expected production over a rolling 24 to 36 month period. Excluding sold calls, for 2011 and 2012, we had hedged approximately 15.5 million MMBtu and 16.7 million MMBtu of natural gas at a weighted average price of $6.11 and $6.08 per MMbtu, respectively, as of December 31, 2010. Our 2011 hedges represent approximately 74% of our average our daily production for the fourth quarter of 2010. We plan to continue to use hedging to mitigate commodity price risk.

"During 2010, the Company navigated through many operational and financial challenges including falling natural gas prices and increased service costs. However the Company's focus on improving its Haynesville/Bossier horizontal drilling program, improving its liquidity, and expanding into oil resource plays has set the Company up for improved financial results and liquidity in 2011 and beyond," said James A. Merrill, Chief Financial Officer. "The recent acreage acquisitions and capital transactions allow the Company to be in the position to allocate capital between oil and gas depending on the commodity price and to accelerate the point in time in which the Company's operating cash flow exceeds its capital expenditures. The increase in production and our focus on managing general and administrative and lease operating costs was clearly evident in the reduction of our per unit metrics in the fourth quarter 2010. With these improving operational metrics and a fully funded business plan, we believe we are in the position to accelerate shareholder value."

Haynesville/Bossier Operational Update

The Company has drilled and completed 31 H/B Hz wells with three additional wells drilled and waiting on completion at year-end 2010.   The Mia Austin #1H with a perforated lateral length of 4,468' and a first day of sales on February 10, 2010 has a cumulative one year production of 1.4 BCFE.   The Company also reports today on the updated results of our first two long laterals.   The Mia Austin #6H (6,080') has a 30 day average production rate of 7,891 Mcfe/d, a 7,241 Mcfe/d 60 day rate and a 6,730 Mcfe/d 90 day rate. The Bosh Heisman #17H (6,164') has a 30 day average production rate of 7,144 Mcfe/d and a 6,846 Mcfe/d 60 day rate. 

The Company's average completed well costs for 2010 were $8.6 million. The fracture stimulation costs increased significantly from the fourth quarter of 2009 ($124,000 per stage) to a peak in October of 2010 ($300,000 per stage) and have since steadily declined to our estimated average of $220,000 per stage in the first quarter of 2011. 

2011 Budget and Guidance and Update

The Company's total cash capital expenditures for 2011 are forecasted at $224 million, which includes $56 million for the Bakken and Niobrara acreage acquisitions, $15.5 million for the Bakken development, $26.9 million for the Niobrara development and $125.7 million for the Haynesville/Bossier drilling program, which includes $29.5 million of 2010 completion costs to be paid in 2011. The Company anticipates drilling and completing 1.3 net wells and 3.9 net wells in the Bakken and Niobrara, respectively, during 2011, at an estimated well cost of $7 million for the Bakken and $4 million for the Niobrara. In addition to the drilling and completion expenditures, the Company anticipates spending approximately $8.0 million for seismic in the Niobrara.

The Company's first quarter and full year 2011 production guidance is 6.0 Bcfe and 25.4 Bcfe, respectively, which represents an increase of 88% and 45% from the first quarter and full year 2010. For 2011, the Company expects to produce 22.8 Bcfe of natural gas and 124,365 BBLs of oil and 348,549 BBLs of NGLs. Crude oil and NGLs as a percentage of production are expected to be 11% for 2011, representing approximately 18% of our total revenues.    

GMXR is a resource play rich E&P company with recently announced 2011 development acreage in Two Oil Resources in the Williston Basin (North Dakota / Montana) and the DJ Basin (Wyoming), targeting the Bakken/Sanish-Three Forks and Niobrara Formations, respectively. Our natural gas resource is located in the Haynesville/Bossier Formation and the Cotton Valley Sand Formation in the East Texas Basin, where the vast majority of our acreage is contiguous, and held by production.  The Company believes multiple productive layers within these domestic oil and natural gas resources provide us with the flexibility to allocate capital across commodities and basins, and to achieve the highest risk adjusted rate of return on our portfolio of resource plays.  Further, the oil and natural gas resources provide a robust inventory of high probability, repeatable, organic growth opportunities. The Bakken properties contain 34 potential operated units (1,280 acre), 136 operated locations (10,000 ft laterals) giving the Company a 7 year inventory using a two rig development program. The Niobrara properties contain 133 potential operated units (640 acre), 532 operated locations (5,000 ft. laterals) giving the Company a 5.5 year inventory using a two rig development program. The Haynesville/Bossier and the Cotton Valley Sand locations include 259 net Haynesville/Bossier horizontal locations, and over 100-250 net Cotton Valley Sand horizontal locations, representing an estimated 12-13 year inventory of development utilizing two continuous rigs.  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)
 
  December 31,
  2010 2009
    (as adjusted) (1)
ASSETS    
CURRENT ASSETS:    
Cash and cash equivalents $ 2,357 $ 35,554
Accounts receivable—interest owners  5,339  1,233
Accounts receivable—oil and natural gas revenues, net  6,829  9,340
Derivative instruments  19,486  12,252
Inventories  326  326
Prepaid expenses and deposits  5,767  4,506
Assets held for sale  26,618  — 
     
Total current assets  66,722  63,211
     
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD    
Properties being amortized  938,701  756,412
Properties not subject to amortization  39,694  39,789
Less accumulated depreciation, depletion, and impairment  (630,632)  (464,872)
     
   347,763  331,329
     
PROPERTY AND EQUIPMENT, AT COST, NET  69,037  101,755
DERIVATIVE INSTRUMENTS  17,484  17,292
OTHER ASSETS  6,084  8,484
     
TOTAL ASSETS $ 507,090 $ 522,071
     
LIABILITIES AND EQUITY    
CURRENT LIABILITIES:    
Accounts payable $ 24,919 $ 19,180
Accrued expenses  33,048  12,907
Accrued interest  3,317  3,361
Revenue distributions payable  4,839  4,434
Current maturities of long-term debt  26  48
     
Total current liabilities  66,149  39,930
     
LONG-TERM DEBT, LESS CURRENT MATURITIES  284,943  190,230
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS  10,622  16,299
OTHER LIABILITIES  7,157  7,151
COMMITMENTS AND CONTINGENCIES    
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, 2,041,169 and 2,000,000 shares issued and outstanding as of 2010 and 2009, respectively, (aggregate liquidation preference $50,000,000)  2  2
Common stock, par value $.001 per share—100,000,000 shares authorized, 31,283,353 issued and outstanding in 2010 and 31,214,968 shares in 2009  31  31
Additional paid-in capital  531,944  522,645
Accumulated deficit  (430,784)  (284,745)
Accumulated other comprehensive income, net of taxes  15,227  8,447
Total GMX Resources' equity  116,420  246,380
Noncontrolling interest  21,799  22,081
     
Total equity  138,219  268,461
     
TOTAL LIABILITIES AND EQUITY $ 507,090 $ 522,071
     
(1) As adjusted as a result of adopting ASU 2009-15, "Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing".
 
 
GMX Resources Inc. and Subsidiaries
Consolidated Statements of Operations
(dollars in thousands, except share and per share data)
 
  Year Ended December 31, Quarter Ended December 31,
  2010 2009   2010 2009
    (as adjusted) (1)   (as adjusted) (1)
OIL AND GAS SALES $ 96,523 $ 94,294 $ 27,177 $   25,556
EXPENSES:        
Lease operations  10,651  11,776 2,507 3,195
Production and severance taxes  743  (930) 296 144
Depreciation, depletion, and amortization  38,061  31,006 13,357 7,753
Impairment of oil and natural gas properties and assets held for sale  143,712  188,150 143,712 50,072
General and administrative  27,119  21,390  7,062  6,811
Total expenses  220,286  251,392  166,934  67,975
Income (loss) from operations  (123,763)  (157,098) (139,757) (42,419)
NON-OPERATING INCOME (EXPENSES):        
Interest expense  (18,642)  (16,748) (4,964) (4,208)
Loss on extinguishment of debt  —   (4,976) —  (4,976)
Interest and other income (loss)  (4)  72 (23) 32
Unrealized loss on derivatives  (122)  (2,370) (19) 457
         
Total non-operating expenses  (18,768)  (24,022) (5,006) (8,695)
Loss before income taxes  (142,531)  (181,120) (144,763) (51,114)
BENEFIT (PROVISION) FOR INCOME TAXES  4,239  33 (2,115) 3,627
         
NET LOSS  (138,292)  (181,087) (146,878) (47,487)
Net income attributable to noncontrolling interest  3,114  173 1,003 173
         
NET LOSS APPLICABLE TO GMX RESOURCES  (141,406)  (181,260) (147,881) (48,660)
Preferred stock dividends  4,633  4,625 1,164 1,156
         
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS $ (146,039) $ (185,885) $ (149,045) $ (48,816)
         
LOSS PER SHARE—Basic $ (5.18) $ (9.20) $ (5.27) $ (1.88)
         
LOSS PER SHARE—Diluted $ (5.18) $ (9.20) $ (5.27) $ (1.88)
         
WEIGHTED AVERAGE COMMON SHARES—Basic  28,206,506  20,210,400 28,279,607 26,010,528
         
WEIGHTED AVERAGE COMMON SHARES—Diluted  28,206,506  20,210,400 28,279,607 26,010,528
 
(1) As adjusted as a result of adopting ASU 2009-15, "Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing". 

 

GMX Resources Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(dollars in thousands)
 
  Year Ended December 31,
  2010 2009
    (as adjusted) (1)
CASH FLOWS DUE TO OPERATING ACTIVITIES    
Net loss $ (138,292) $ (181,087)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation, depletion, and amortization  38,061  31,006
Impairment and other writedowns  143,712  188,150
Deferred income taxes  (4,209)  — 
Non-cash stock compensation expense  5,450  4,635
Loss (gain) on extinguishment of debt  (141)  4,976
Non-cash interest expense  9,330  6,036
Other  1,402  1,838
Decrease (increase) in:    
Accounts receivable  (1,595)  (1,338)
Prepaid expenses and other assets  (1,730)  (457)
Increase (decrease) in:    
Accounts payable and accrued expenses  6,680  (2,852)
Revenue distributions payable  67  (1,417)
     
Net cash provided by operating activities  58,735  49,490
     
CASH FLOWS DUE TO INVESTING ACTIVITIES    
Purchase of oil and natural gas properties  (172,726)  (162,076)
Proceeds from sales of oil and natural gas properties  5,522  — 
Purchase of property and equipment  (10,284)  (19,248)
Proceeds from sale of property and equipment  1,488  — 
     
Net cash used in investing activities  (176,000)  (181,324)
     
CASH FLOWS DUE TO FINANCING ACTIVITIES    
Advance on revolving bank credit facility  92,000  99,000
Payments on debt  (79)  (179,079)
Proceeds from sale of common stock  —   164,069
Proceeds from sale of preferred stock  949  — 
Issuance of 4.50% Convertible Senior Notes  —   86,250
Dividends paid on Series B Cumulative Preferred Stock  (4,633)  (4,625)
Proceeds from (repayment of) Senior Secured Notes  —   (34,590)
Sale of equity interest of a business  —   36,000
Contributions from non-controlling interest member  1,244  — 
Distributions to non-controlling interest member  (4,640)  — 
Fees paid related to financing activities  (773)  (7,085)
Other  —   732
     
Net cash provided by financing activities  84,068  160,672
     
NET INCREASE (DECREASE) IN CASH  (33,197)  28,838
     
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD  35,554  6,716
     
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 2,357 $ 35,554
     
SUPPLEMENTAL CASH FLOW DISCLOSURE CASH PAID (RECEIVED) DURING THE PERIOD FOR:    
INTEREST, NET OF AMOUNTS CAPITALIZED $ 11,988 $ 15,611
     
INCOME TAXES $ (30) $ (33)
 
(1) As adjusted as a result of adopting ASU 2009-15, "Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing".
 
 
GMX Resources Inc. and Subsidiaries
Non-GAAP Supplemental Information - Discretionary Cash Flows(1)
 
  Three Months Ended December 31, Year Ended December 31,
  2010 2009 2010 2009
  (unaudited) (unaudited)
  (in thousands)
Net loss  $ (146,878) $ (47,487)  $  (138,292) $ (181,087)
         
Non-cash charges:        
Depreciation, depletion, and amortization 13,357 7,754  38,061 31,006
Impairment of oil and natural gas properties 143,712 50,072 143,712 188,150
Deferred income taxes 2,115 (3,594) (4,209) --
Non cash compensation expense 790 977 5,450 4,635
Loss on extinguishment of debt (141) 4,976 (141) 4,976
Non cash interest expense 2,428 2,189 9,330 6,036
Other (74) (553) 1,402 1,838
         
Preferred stock dividends  (1,164) (2,312)  (4,633) (4,625)
Net income attributable to noncontrolling interest (1,003) (173) (3,114) (173)
         
Non-GAAP discretionary cash flow  $ 13,142  $ 11,849  $ 47,566     $ 50,756
         
         
Reconciliation of GAAP "Net cash provided by operating activities" to Non-GAAP "discretionary cash flow"        
         
Net cash provided by operating activities  $   17,763 $ 8,081  $ 58,735 $ 49,490
         
Adjustments:        
Changes in operating assets and liabilities    (2,454) 6,253     (3,422) 6,064
Preferred stock dividends (1,164) (2,312) (4,633) (4,625)
Net income attributable to noncontrolling interest (1,003) (173) (3,114) (173)
         
Non-GAAP discretionary cash flow  $ 13,142  $11,849  $ 47,566 $ 50,756
 
(1) Discretionary cash flow represents net cash provided by operating activities before changes in assets and liabilities less preferred dividends. Discretionary cash flow is presented because management believes it is a useful financial measure in addition to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Management believes that discretionary cash flow is widely accepted as a financial indicator of an oil and gas company's ability to generate cash which is used internally to fund exploration and development activities. Discretionary cash flow is widely used by professional research analysts and investors in the comparison, valuation, rating and investment recommendations of companies within the oil and gas exploration and production industry. Discretionary cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity, or as an alternative to net income.
 
 
GMX Resources Inc. and Subsidiaries
Non-GAAP Reconciliations – Adjusted EBITDA (1)
 
Reconciliation of GAAP "Net Income" Three Months Ended December 31, Year Ended December 31,
to Non-GAAP Adjusted EBITDA 2010 2009 2010 2009
         
(Dollars in Thousands)        
Net Income (Loss) $ (146,878) $ (47,486) $ (138,292) $ (181,087)
Adjustments:        
Depreciation, depletion, and amortization 13,357 7,754 38,061 31,006
Certain non-cash expenses (income)(2) (180) 206 4,167 6,258
Impairment and other writedowns 143,712 50,072 143,712 188,150
Income taxes 2,115 (3,627) (4,239) (33)
Loss on extinguishment of debt (141) 4,976 (141) 4,976
Interest expense 4,964 4,209 18,642 16,748
Adjusted EBITDA $ 16,949 $ 16,104 $ 61,910 $ 66,018
 
(1) Adjusted EBITDA represents earnings before interest, taxes, depletion, depreciation & amortization and includes non-cash compensation, hedging and derivative activities and other expenses per the Company's revolving bank credit facility.  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 also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our revolving bank credit facility and is used in the financial covenants in our revolving bank credit facility. 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.
(2) Amount above includes non-cash compensation, hedging and derivative activity and other expenses per the Company's revolving bank credit agreement.
CONTACT: Alan Van Horn
         Manager, Investor Relations
         405.254.5839

© Copyright 2012, GlobeNewswire, Inc. All Rights Reserved

Discuss:

Discussion comments

,

Most active discussions

  1. votes comments
  2. votes comments
  3. votes comments
  4. votes comments

Data: Latest rates in the US

Home equity rates View rates in your area
Home equity type Today +/- Chart
$30K HELOC FICO 4.91%
$30K home equity loan FICO 5.20%
$75K home equity loan FICO 4.57%
Credit card rates View more rates
Card type Today +/- Last Week
Low Interest Cards 13.42%
13.40%
Cash Back Cards 17.92%
17.92%
Rewards Cards 17.13%
17.12%
Source: Bankrate.com