OKLAHOMA CITY, Nov. 8, 2010 (GLOBE NEWSWIRE) -- GMX RESOURCES INC. (NYSE:GMXR) ("GMXR" or the "Company") today reported operational and financial results for the third quarter and nine months ended September 30, 2010. (visit for more information on the Company)
Financial and Operating Highlights for the Third Quarter 2010 and Recent Events
- Adjusted net income available to common shareholders per fully diluted share was $0.03 and $0.16 for the three and nine months ended September 30, 2010, respectively.
- Adjusted EBITDA of $16.6 million and $45.0 million for three and nine months ended September 30, 2010, respectively, compared to $16.7 million and $49.9 million for the respective periods in 2009.
- Discretionary cash flow of $12.4 million and $34.4 million for three and nine months ended September 30, 2010, respectively, compared to $13.7 million and $38.9 million for the respective periods in 2009.
- Natural gas and oil production volumes increased by 8% to 4.65 billion cubic feet of natural gas equivalent ("Bcfe") in the third quarter 2010 compared to 4.31 Bcfe in the second quarter 2010, and increased by 21% to 12.16 Bcfe in the first nine months of 2010 compared to 10.02 Bcfe in the nine months ended September 30, 2009.
- Lease operating expenses were $0.60 per Mcfe and $0.67 per Mcfe for the three and nine months ended September 30, 2010, respectively, compared to $0.78 and $0.86 per Mcfe for the three and nine months ended September 2009, respectively.
- Estimated total proved reserves as of September 30, 2010 were 442.3 Bcfe based on SEC pricing, an increase of 24% from December 31, 2009.
- The Company is in negotiations to sublease two H&P FlexRigs™, one of which is currently being subleased through January 2011, further reducing the capital commitments of the Company.
- 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 Third Quarter 2010
The Company reported net income applicable to common shareholders of $2.2 million ($0.08 per basic and fully diluted share) and $3.0 million ($0.11 per basis and fully diluted share) for the three and nine months ended September 30, 2010, respectively, compared to a net loss applicable to common shareholders of $2.5 million ($0.12 per basic and fully diluted share) and $137.1 million ($7.52 per basis and fully diluted share) for the three and nine months ended September 30, 2009, respectively.
Adjusted net income available to common shareholders, a non-GAAP measure adjusting for non-cash items set forth below, was $1.0 million ($0.03 per basic and fully diluted share) and $4.4 million ($0.16 per basic and fully diluted share) for the three and nine months ended September 30, 2010, respectively:
(1) Per share amounts are calculated on a fully diluted basis.
(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 and nine months ended September 30, 2010 and 2009:
Total production for the third quarter of 2010 of 4.65 Bcfe represents a 33% increase in production compared to the third quarter of 2009 and a 8% sequential increase in quarterly production compared to the second quarter of 2010. This sequential production growth also reflected a 10% growth in Haynesville/Bossier ("H/B") horizontal ("Hz") production. The increase in natural gas production resulted from production related to 23 producing H/B Hz wells that were on-line at September 30, 2010. During the third quarter of 2010, the Company brought on-line three H/B Hz wells, and production from H/B Hz wells accounted for 64% of total production in the third quarter of 2010 compared to 40% in the third quarter of 2009.
Oil and gas sales net of gain or loss from non-cash derivative ineffectiveness in the three months ended September 30, 2010 increased 8% to $24.8 million compared to $23.1 million for the three months ended September 30, 2009. Ineffectiveness of derivatives reduced oil and gas sales by $116,000 and $72,000 for the three months ended September 30, 2010 and 2009, respectively, and is the result of a difference in the fair value of the Company's cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on the Company's expected sales point. The increase in oil and natural gas sales was due to a 33% increase in production offset by a 19% decrease in the average realized price of oil and natural gas, excluding non-cash ineffectiveness of hedging activities.
In the three months ended September 30, 2010, as a result of hedging activities but excluding non-cash derivative ineffectiveness, we recognized an increase in natural gas sales of $5.8 million compared to an increase in natural gas and oil sales of $9.4 million and $0.5 million, respectively, in the third quarter of 2009. In the third quarter of 2010, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.29 per Mcf compared to an increase in natural gas and oil sales price of $2.84 per Mcf and $16.89 per Bbl, respectively, in the third quarter of 2009. The Company did not recognize any oil related hedging activities in oil and gas sales in the three months ended September 30, 2010.
Lease operations expense increased $0.1 million, or 3%, in the three months ended September 30, 2010 to $2.8 million, compared to $2.7 million for the three months ended September 30, 2009. Lease operations expense on an equivalent unit of production basis decreased $0.18 per Mcfe in the three months ended September 30, 2010 to $0.60 per Mcfe, compared to $0.78 per Mcfe for the three months ended September 30, 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 during 2010.
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 Hz wells, qualify for full severance tax relief for a period of ten years or recovery of 50% of the cost of drilling and completion, whichever is less. As a result, refunds for severance tax paid to the State of Texas on wells that qualify for reimbursement are recognized as accounts receivable and offset severance tax expense for the amount refundable. Production and severance taxes decreased 307% to a benefit of $0.6 million in the three months ended September 30, 2010 compared to an expense of $0.3 million in the three months ended September 30, 2009, as a result of the Company recording production and severance tax refunds of $1.5 million.
General and administrative expense for the three months ended September 30, 2010 was $6.7 million compared to $4.8 million for the three months ended September 30, 2009, an increase of $1.9 million or 38%. General and administrative expense per equivalent unit of production was $1.43 per Mcfe for the third quarter of 2010 compared to $1.38 per Mcfe for the comparable period in 2009. This increase is a result of the Company recognizing an increase of $1.2 million of payroll expenses related to the hiring of additional personnel compared to the same period in prior year. In addition, there were general increases of $0.7 million in other general and administrative expenses (office expenses, professional fees, travel, etc.). General and administrative expenses include $1.1 million and $1.4 million of non-cash compensation expense as of the three months ended September 30, 2010 and 2009, respectively. Non-cash compensation represented 18% and 29% of total general and administrative expenses for the three months ended September 30, 2010 and 2009, 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 either non-recurring or relatively fixed in nature. The Company expects cash general and administrative expenses on a per Mcfe basis to decrease as production increases.
Capital Resources and Liquidity Update
As of September 30, 2010, we had cash and cash equivalents of $4.1 million and a working capital deficit of $7.6 million. Through the period ended September 30, 2010, we have funded our operating expenses and capital expenditures through positive operating cash flows and draws of $65 million on our revolving bank credit facility that has a current borrowing base of $130 million. Prior to 2010, we have historically generated cash through the same means, as well as financing from our 5.0% and 4.5% convertible debt instruments, which currently have carrying values of $117.8 million and $74.7 million, respectively as of September 30, 2010.
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. In the first nine months of 2010, our capital expenditures were $136.8 million of which $130.4 million was primarily used for drilling and completing H/B Hz wells, H/B acreage acquisitions, land related activities and infrastructure.
We may continue to revise our capital expenditures during 2010 and 2011 depending on our ability to continue to sublease two or more of our contracted Helmerich & Payne FlexRigs™ ("FlexRigs") and the availability of stimulation services used to complete our H/B Hz wells. We continue to seek additional frac dates through multiple service companies. Our capital expenditures, production and revenues could all vary if we are able to obtain additional frac dates during the fourth quarter of 2010.
The Company previously announced its intent to sublease an additional FlexRig3™ in our fleet in order to more properly align our drilling efficiencies with available stimulation services and to manage our liquidity. Currently, the Company is drilling with two (Rig 1 and Rig 2) of its four contracted FlexRig3 rigs and has the other two rigs (Rig 3 and Rig 4) on sublease contracts. The sublease contract for Rig 4 expires in March 2013 and the agreement for Rig 3 expires in January 2011. The Company expects to complete a new sublease agreement for Rig 2 that will run from January 2011 until July 2011with an option to extend six months until December 2011. Rig 3 due back in January 2011 will be re-subleased until April 2012. These two new leases will allow the Company to run one rig from January 2011 until at least July 2011.
In order to protect the Company against the financial impact of a decline in natural gas prices, the Company has an active rolling three year hedging program. The Company has bought puts in place that protect 3.7 Bcf for fourth quarter 2010 natural gas production at an average floor price of $6.35. In addition, the Company bought puts in place that protect 14.9 Bcf and 16.7 Bcf of natural gas production in 2011 and 2012, respectively, at average floor prices of $6.14 and $6.08. The Company has also sold put options that would reduce the average floor price if the monthly natural gas contract settlement price is below $4.36 for fourth quarter 2010, $4.22 for 2011 and $4.13 for 2012. If the monthly natural gas contract settlement price is below the average sold put price, the Company will receive the monthly natural gas contract settlement price plus $1.99 in the fourth quarter of 2010, $1.92 in 2011, and $1.95 in 2012.
As of September 30, 2010, we had $65 million drawn on our revolving bank credit facility that has a borrowing base of $130 million. On July 8, 2010, we completed our semi-annual redetermination of our revolving bank credit facility borrowing base in which we reaffirmed the borrowing base of $130 million, extended the maturity date to August 1, 2012 which can be extended automatically to July 8, 2013 under certain circumstances and modified our Total Net Debt to EBITDA financial covenant. Our next semi-annual redetermination is scheduled to be completed in November 2010 based on the proved reserve information discussed below. As of September 30, 2010, we were in compliance with all financial covenants under our revolving bank credit facility.
Proved Reserves at End of Third Quarter 2010
GMXR's total estimated proved reserves for natural gas and crude oil reserves as of September 30, 2010 were 442.3 Bcfe, consisting of 3.6 million barrels (MMBbls) of crude oil and 420.5 billion cubic feet (Bcf) of natural gas, as prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC).
The Company's total estimated proved reserves as of September 30, 2010 are based in part on an audit of our proved developed producing ("PDP") H/B reserves consisting of 24 drilled and completed H/B Hz wells as of October 1, 2010 by the independent petroleum engineering consulting firm of DeGolyer and MacNaughton ("D&M"). Additionally D&M provided an estimate of the proved undeveloped reserves of a typical well to be drilled in our H/B acreage, which includes related guidance for booking proved undeveloped reserves ("PUD's") for our planned longer lateral lengths. That guidance contemplates revised completion practices by the Company. The report regarding estimates for a typical H/B well of this type concludes an estimated ultimate recovery (EUR) of 6.452 million cubic feet (Bcf) for a 6,460 foot lateral with the limitation of booked offsets to 1,000 foot spacing. The report notes that estimated reserves for a specific well may vary from the typical well studied. The audit report of our PDP H/B reserves and report regarding estimated reserves for a typical H/B PUD well, together with our estimated proved reserves discussed further below, have been made available to the reserve engineers of the banks in the Company's credit facility. The results of the semi-annual borrowing base have not been completed; however, we plan to provide an update on our revolving bank credit facility in the fourth quarter of 2010.
The following tables summarize GMXR's estimated proved reserves as of September 30, 2010:
(1) PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue before income tax of the Company's estimated proved reserves. The PV-10 value is different than the standardized measure of discounted estimated future net cash flows which is calculated after income taxes. The Company believes the PV-10 is a useful measure for evaluating the relative monetary significance of their proved reserves. Investors may use the PV-10 as a basis for comparison of the relative size and value of the Company's reserves to its peers.
(2) The proved reserves as of September 30, 2010 are calculated based on current SEC guidelines. The commodity prices used in the estimate were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price during the period from October 2009 through September 2010. For natural gas volumes, the average Henry Hub spot price of $4.41 per million British thermal units (MMBTU) was adjusted for energy content, transportation fees, regional price differences, and system shrinkage. For crude oil, the average West Texas Intermediate posted price of $73.85 per barrel was adjusted for quality, transportation fees, and regional price differentials.
(3) The 2 Year Average NYMEX Strip Pricing Case scenario was based on the average of the 2011 and 2012 NYMEX strip price as of September 30, 2010 for both oil and natural gas. For oil, the average of the 2011 and 2012 NYMEX price was $85.96 and was adjusted for quality, transportation fees, and regional price differentials. For natural gas volumes, the average of the 2011 and 2012 NYMEX price of $4.76 per MMBTU was adjusted for energy content, transportation fees, regional price differences, and system shrinkage.
(4) The Revenue Floors plus 2 Year Average NYMEX Strip Pricing Case scenario was based on the average of the 2011 and 2012 NYMEX strip price as of September 30, 2010 for both oil and natural gas as listed in footnote (3). However, the average natural gas price used for 2010, 2011, and 2012 was $5.35, $5.32, and $5.61, respectively, to account for the Company's current natural gas hedges.
Timothy L. Benton, Vice President of Geosciences, said, "The use of D&M's work in proved reserve bookings in the Haynesville-Bossier validates the potential of this layer in valuing GMXR's east Texas acreage. D&M has extensive experience throughout the Haynesville play as well as a refined understanding of other horizontal shale plays in North America, especially as it pertains to the impact of longer lateral lengths and progressively efficient completion technologies. While the D&M numbers are lower than GMXR's current 7.2 Bcfe guidance their work confirms prior guidance on the engineering assumptions framing our recoverable resources."
James A. Merrill, GMXR's Chief Financial Officer, said, "We are pleased with our operating achievements for the quarter, while GMXR continues to focus on the fundamentals of cost management, production growth and reserve growth during a more challenging natural gas price environment. Our H/B Hz drilling activities are yielding better results than previously forecasted, and now DeGolyer & MacNaughton has audited our H/B Hz PDP reserve estimates. As a result, our third quarter estimates of proved reserves have increased substantially from year end 2009. This is due to the successful H/B Hz drilling program this year and the addition of H/B Hz PUD bookings using methodology supported by an initial D&M report.
"We have continued to experience relatively high completion costs and unpredictable frac dates driven by limited available equipment in our core area. However, we believe this is out of sync with current gas prices, and is driven by producers who are drilling solely to hold leases taken in 2008. As the drill to hold lease dynamic ends and natural gas focused rig counts are reduced to better align with the natural gas pricing, and service companies take delivery of additional equipment, we believe completion costs will drop and return to being more sensitive and correlated to gas prices. In the interim, we remain focused on cost control. Through our improved drilling efficiencies and other cost containment initiatives, we have reduced the completed well cost per lateral foot."
GMXR Third Quarter Earnings and Operational Update Conference
GMXR has scheduled a conference call for November 9, 2010 at 10:00 AM CST (11:00 AM EST). The participant dial-in number is Toll free: 877-303-9132 or 408-337-0136. A replay of this call will be available after 2:00 PM EST on November 9th and can be accessed using the following number and pass code: Toll free: 800-642-1687 or 706-645-9291. Replay Pass code: 19451842.
GMXR is a 'Pure Play', E&P Company with operations in East Texas focused on Haynesville/Bossier (H/B) Horizontal Shale and Cotton Valley Sand (CVS) development. The Company's 2010 production through September 30, 2010 is comprised of approximately 9% NGLs, 3% oil and 88% natural gas. The Company believes multiple resource layers across the Company's East Texas property base provide a robust inventory for high probability, repeatable, organic growth and contain 265 net H/B Hz undrilled locations and 1,092 net CVS un-drilled locations. A substantial portion of the Company's leased acreage is contiguous, and the Company utilizes existing infrastructure throughout this property base.
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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 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 "Risk Factors" contained in the Company's reports on Form 10-K and Form 10-Q 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.
The SEC requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. In this press release, we have provided estimates of proved reserves based on SEC pricing, as well as alternative pricing methods. As indicated by these alternative pricing sensitivity estimates, estimates of reserves may change significantly based on prices as well as other factors and actual quantities that are ultimately recovered may differ substantially from these or other estimates.
CONTACT: GMX RESOURCES INC. Alan Van Horn, Manager, Investor Relations (405) 254-5839