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.
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:
The following table summarizes certain key operating and financial results for the three months and year ended December 31, 2010 and 2009:
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 for more information on the Company.
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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.
CONTACT: Alan Van Horn Manager, Investor Relations 405.254.5839