OKLAHOMA CITY, Nov. 6, 2009 (GLOBE NEWSWIRE) -- GMX Resources Inc. (Nasdaq:GMXR) (visit www.gmxresources.com to view the most recent Company presentation and for more information on the Company) today reported financial and operating results for the third quarter and nine months ended September 30, 2009 and updated 2009 through 2011 guidance.
Financial Results for the Three Months Ended September 30, 2009
GMXR reported a net loss of $2.8 million for the three months ended September 30, 2009 as compared to 2008's third quarter net income of $9.6 million. Diluted loss per share for the three months ended September 30, 2009 was $0.19 per share compared to net income of $0.50 per share for the three months ended September 30, 2008. Adjusted net income available to common shareholders, a non-GAAP measure adjusting for unrealized derivative losses and income tax valuation allowances, was $1.6 million, or $0.08 per share, for the third quarter of 2009 and is calculated as follows:
Three Months Ended
September 30, 2009
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(in thousands, except per share amounts) Amount per share
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Net loss applicable to common stock $ (3,938) $ (0.19)
Adjustments:
Income tax valuation allowance 4,577 0.22
Unrealized losses on derivatives,
net of taxes of $494 959 0.05
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Adjusted net income applicable to common stock $ 1,598 $ 0.08
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The third quarter 2009 operating results continued to be impacted by lower market prices for crude oil and natural gas as compared to the second quarter of 2009. Oil and gas sales in the third quarter of 2009 of $23.1 million increased 1% from sales in the second quarter of 2009 of $22.8 million as a result of a 5.5% increase in crude oil and natural gas production. GMXR's production from its East Texas operations in the third quarter of 2009 increased to 3.49 billion cubic feet equivalent of natural gas ("Bcfe") as compared to production of 3.31 Bcfe in the second quarter of 2009. Natural gas prices realized in the third quarter of 2009 averaged $6.26 per thousand cubic feet ("Mcf"), 4% lower than the $6.54 per Mcf realized in the second quarter of 2009. GMXR's average realized oil prices in the third quarter of 2009 increased to $80.82 per barrel, 7% higher than the $75.88 per barrel in the second quarter of 2009.
During 2009, the Company has continued to focus on reducing operating and overhead costs. As a result, both lease operating expenses and general and administrative expenses on a per Mcfe basis decreased in the third quarter of 2009 compared to the second quarter of 2009. Lease operating expenses of $0.78 per Mcfe in the third quarter of 2009 decreased 5% from $0.82 per Mcfe in the second quarter of 2009. General and administrative expenses of $1.38 per Mcfe in the third quarter of 2009 decreased 14% from $1.61 per Mcfe in the second quarter of 2009.
Among non-GAAP measures, discretionary cash flow generated by GMXR in the third quarter of 2009 was $13.7 million, an increase of 14% over 2009's second quarter non-GAAP discretionary cash flow of $12.0 million.
Financial Results for the Nine Months Ended September 30, 2009
GMXR reported a net loss of $135.4 million for the nine months ended September 30, 2009 as compared to net income of $28.2 million in the nine months ended September 30, 2008. Diluted loss per share for the nine months ended September 30, 2009 was $7.60 per share compared to net income of $1.62 per share for the nine months ended September 30, 2008. Adjusted net income available to common shareholders, a non-GAAP measure adjusting for unrealized derivative losses, non-cash impairment charges and writedowns, bad debt expenses and income tax valuation allowances, was $3.7 million, or $0.20 per share, for the first nine months of 2009 and is calculated as follows:
Nine Months Ended
September 30, 2009
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(in thousands, except per share amounts) Amount per share
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Net loss applicable to common stock $(138,851) $ (7.60)
Adjustments:
Full cost accounting impairment, net of
taxes of $61,298 118,990 6.51
Inventory writedown, net of taxes of $2,118 4,111 0.22
Income tax valuation allowance 17,290 0.95
Unrealized losses on derivatives, net of
taxes of $961 1,866 0.10
Bad debt expense, net of taxes of $165 321 0.02
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Adjusted net income applicable to common stock $ 3,727 $ 0.20
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Recent Capital Raising and Hedging Transactions
In October 2009, the Company completed public offerings of 6,950,000 shares of common stock at $15.00 per share and $86.25 million aggregate principal amount of 4.50% convertible senior notes due 2015. The Company used the aggregate net proceeds from these offerings of $181 million to repay the outstanding indebtedness under its revolving bank credit facility, to repay all of its outstanding senior secured notes, and the Company will use the remaining portion of these net proceeds for general corporate purposes.
The 4.50% convertible are general senior, unsecured obligations of the Company and are convertible, under certain circumstances, into cash, shares of the Company's common stock or a combination of cash and shares of the Company's common stock, at the Company's election. The notes bear interest at a fixed rate of 4.50% per year, payable on May 1 and November 1 of each year, beginning May 1, 2010. The notes will mature on May 1, 2015.
In addition to the common stock and convertible notes offerings in October 2009, on November 2, 2009, the Company received $36 million in proceeds from Kinder Morgan Endeavor LLC from the sale of a 40% interest in Endeavor Gathering LLC, a new entity formed to hold all of the Company's midstream assets. The proceeds from this sale will be used for general corporate purposes which includes the use of a second operated H&P FlexRig3 (TM) on the Company's acreage in Harrison and Panola counties in East Texas.
The Company expects that the capital raised during 2009 will be sufficient to fund a four rig drilling program through the point at which its discretionary cash flows will exceed its capital expenditures. The Company will continually adjust capital expenditures based on the current commodity price environment to ensure that the Company has adequate liquidity in cash and/or with availability under its revolving bank credit facility. The Company expects to complete a semi-annual redetermination of the borrowing base under its revolving bank credit facility in November 2009. The Company does not anticipate a material change in the borrowing base from this redetermination.
In October 2009, the Company purchased $6.00 put options on 1.9 Bcf, 11.1 Bcf, and 13.4 Bcf, respectively, of 2010, 2011, and 2012 natural gas production. The cost per MMbtu of these put options was $0.7725 for a total cost of $20.4 million which will be paid in the month the contract is settled. In November 2009, the Company sold $4.00 puts on 0.965 Bcf of 2010 natural gas production and received approximately $162,000. The Company anticipates selling additional puts and calls on these volumes over the three year period to recover the cost of these purchased puts. Currently, the Company has 60%, 39%, and 32% of its expected natural gas production hedged in 2010, 2011, and 2012, respectively, at a weighted average floor price of $6.43, $6.13, and $6.29 for the respective years. 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 36 month period to ensure our net operating income and cash flow.
Third Quarter 2009 Operational Results
Operating a one rig drilling program the Company achieved very good corporate metrics in the third quarter. Production for the quarter was up 5% sequentially from the second quarter of 2009, in part due to the Company's focus on H/B Hz drilling.
During the 3rd quarter of 2009, the Company drilled and completed two previously announced H/B Hz wells -- the Holt 1H and the Verhalen B 1H, and spud the Verhalen C 1H which was completed in late October. The Holt 1 H and Verhalen B 1H wells have averaged over 5.7 mmcfe/d for the first thirty days of production and continue to outperform the previous H/B Hz wells drilled by the Company earlier this year. The Verhalen C 1H has been on line for less than two weeks but is producing at a comparable rate. Additionally, these three wells represent the lowest completed well costs ("CWC") to date, with the Verhalen C 1H CWC expected to be less than $7 million. The TJT Simpson 1 H began the completion process in late October and the Company experienced a mechanical integrity issue with the production casing during the second stage of treatment. The indications from the first stage flow back are significant enough to expect results equal to or greater than previously reported wells. We are developing a plan for repair that will allow us to successfully complete the well in the fourth quarter of 2009.The Company also spud the Snider A 1 H in late September. On this well the Company is coring the entire Haynesville / Bossier formation and will submit this core to the Haynesville Shale Consortium sponsored by Core Labs, Inc.
The Company has joined the Object Reservoir Haynesville project which currently has 14 members representing virtually all of the major Haynesville operators. This affiliation will provide the Company with an immense amount of information, data and modeling tools capable of determining behaviors and success characteristics of over 60 H/B Hz wells already drilled in the basin.
CWC have continued to decline due to the Company's focus on reducing drilling time and materials management. The average drilling time for the last three H/B Hz is less than 40 days and the Company expects additional reductions in drilling times. Each day of drilling time reduced represents a $70,000 cost reduction. The Company continues to competitively bid subcontracted services and material which has resulted in substantial costs savings compared to the second quarter of 2009.
The third quarter was an active quarter for many other operators in East Texas and with a record number of H/B Hz well results reported by those operators, the new results continue to corroborate the Company's view of the viability and productivity of its East Texas acreage. H/B Hz reported IP results from other operators have ranged from 6.0 mmcfe/d to over 15 mmcfe/d with 30 day production rates in the range of 5.7 mmcfe/d to 9.1 mmcfe/d; a 60% increase in 30 day production rates from our best wells to date. We believe these results in and around the GMXR core area attest to the quality of the formation in East Texas and are indicative of the benefit of the learning curve derived from considerably more drilling activity. The Company has a number of data sharing agreements with other operators and has actively pursued dialog to compare and contrast information related to drilling and completion techniques. The Company intends to modify some of its drilling and completions techniques and expects to continue to deliver increasingly better results over time. These changes will be implemented in late fourth quarter 2009 and early first quarter 2010.
Ken Kenworthy, Jr., Chairman and CEO said in a statement, "We are continuing to deliver better results at lower costs from our Haynesville / Bossier assets. We've taken the necessary steps to ensure we have the capital in place in advance to put GMXR back into a growth mode. We are active learners willing to apply the best of class techniques in our drilling and completion programs. We will continue to hedge through 2012 to make certain we meet our targeted rate of return from our H/B Hz program. The Company is back in a growth profile with a second rig active as of October 15th and the expectation of the third and fourth rig becoming active in the first quarter of 2010. A number of new shareholders were part of the most significant capital raise in the history of the Company which now positions us to fund our four rig program through 2012 and become cash flow positive."
The Company is currently drilling in its 100% operated core acreage with 2 rigs; rigs 3 & 4 are scheduled to begin in the first quarter of 2010. We have elected to participate in two H/B Hz wells in the non-operated core area in the fourth quarter of 2009 and will likely participate in additional non-operated wells in the core area in 2010.
Production and Production Guidance
GMXR produced 3.49 Bcfe in the third quarter of 2009 as compared to 3.51Bcfe in the third quarter of 2008, a 1% decrease. GMXR produced 10.02 Bcfe in the first nine months of 2009 compared to 9.63 Bcfe in the first nine months of 2008, a 4% increase. Sequentially, production increased 5.5% from 3.31 Bcfe in the second quarter of 2009. The production flattening was attributable to the Company only running one rig for approximately six months of 2009 and the Company's decision to switch from primarily drilling the Cotton Valley Sands to exclusively drilling the Haynesville/Bossier Shale. Production guidance for the fourth quarter of 2009 ranges from 3.50 Bcfe to 3.75 Bcfe. Production from H/B Hz wells was approximately 53% and 30% of the Company's production for the three and nine months ended September 30, 2009, respectively.
Production guidance for 2010 and 2011 is estimated to be 17 Bcfe and 25 Bcfe, respectively, under a three rig drilling program. Under a four rig drilling program, production is estimated to be 19 Bcfe and 30 Bcfe for 2010 and 2011, respectively. The production guidance for 2010 and 2011 does not include any anticipated production from new non-operated wells other than two H/B Hz wells where we have elected to participate.
Updated Budget Guidance
GMXR's current 2009 two rig CAPEX budget is estimated at $175 million which includes the drilling of 10 HB Hz wells and 12 H/B Hz completions in 2009. Almost 100% of the remaining 2009 drilling program will be focused on Haynesville/Bossier horizontal drilling which has the Company's highest expected rate of return. For the nine months ended September 30, 2009, the Company had nine H/B Hz completions and the Company expects to have three completions in the fourth quarter of 2009. In the nine months ended September 30, 2009, our capital expenditures were $138.3 million, of which $82.3 million was for drilling and completing H/B horizontal wells, $9.2 million was for rig delay fees, $9.3 million was for Cotton Valley and Travis Peak drilling and other drilling related expenditures including tubular inventory and $37.5 million was related to leasehold and infrastructure costs. In the last three months of 2009, we expect to have capital expenditures of approximately $36.7 million primarily related to drilling and completing H/B Hz wells with two operated rigs. We do not expect to have significant infrastructure or inventory expenditures in the last three months of 2009.
The Company is using the H&P FlexRig3(TM) for its H/B Hz wells which has already provided efficiencies in reducing drilling days and lowering costs. The cost of recent H/B Hz wells is averaging $7.0 million based on a 35 to 40 day drilling schedule. The authorization for expenditure ("AFE") for the Company's latest well spud in October 2009 was $6.5 million. The Company is working to reduce drilling times by an additional five to ten days which could reduce well costs by $350,000 to $700,000.
Anticipated 2010 capital expenditure guidance ranges from $190 million for a three H/B Hz rig drilling program to $220 million if the fourth contracted rig begins H/B Hz drilling in late March 2010 as scheduled. For 2011, capital expenditure guidance ranges from $200 million to $245 million for a three and four rig program, respectively. Due to the recent capital raising activities, the Company has the potential to increase the 2010 and/or 2011 capital expenditure guidance by approximately $25 million if the Company elects to participate in additional proposed non-operated wells.
Based on the capital expenditures planned for 2010 and 2011 and the proceeds from the recent offerings, we believe the Company has ample liquidity to execute either a three or four rig drilling program. With the reserves added from either the three or four rig drilling program, the Company expects to generate excess capacity under its revolving bank credit facility. In addition, the Company's active hedging program should help generate positive operating cash flow.
Management Comment
"Over the last six months, we have repositioned the Company to return to a growth company. The proceeds from the recent offerings along with the midstream monetization have provided us with the capital and liquidity to run a four rig drilling program in 2010 and 2011 until the point in time in which our discretionary cash flow exceeds our capital expenditures which is projected to occur in the second half of 2012," stated Jim Merrill, Chief Financial Officer. Mr. Merrill continued, "East Texas Haynesville/Bossier results from all operators have significantly improved during the third quarter of 2009. Along with our continued focus on reducing drilling and completion costs, we expect to achieve improved financial and operating results as we accelerate our Haynesville/Bossier horizontal drilling program."
GMXR Third Quarter 2009 Earnings Conference Call
GMXR has scheduled a conference call for Friday, November 6, 2009 at 10:00 a.m. CST (11:00 a.m. EST) to discuss third quarter 2009 financial and operating results. To access the call, dial 719.325.2312 or 888.312.9865 before the call begins. A replay of the call will be available after 2:00 PM EST, November 6, 2009. To access the replay, please dial 719.457.0820 or 888.203.1112 and reference passcode 5043699. The corporate presentation being used for this call is available for download at http://www.gmxresources.com under the Events and Presentation tab.
GMXR Summary Operating Data for the Three and Nine Months Ended September 30, 2009
Summary Operating Data
Three Months Nine Months
Ended Ended
September 30, September 30,
---------------- ----------------
2008 2009 2008 2009
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Production:
Oil (MBbls) 51 28 150 91
Natural gas (MMcf) 3,204 3,322 8,733 9,477
Gas equivalent production (MMcfe) 3,513 3,491 9,632 10,024
Average daily (MMcfe) 38.2 37.9 35.2 36.7
Average Sales Price:
Oil (per Bbl)
Wellhead price $114.97 $ 63.93 $110.91 $ 51.18
Effect of hedges (15.14) 16.89 (11.97) 21.11
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Total $ 99.83 $ 80.82 $ 98.94 $ 72.29
Natural gas (per Mcf)
Wellhead price $ 10.42 $ 3.44 $ 10.61 $ 3.63
Effect of hedges (0.66) 2.82 (0.67) 2.93
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Total $ 9.76 $ 6.26 $ 9.94 $ 6.56
Average sales price (per Mcfe) $ 10.36 $ 6.61 $ 10.55 $ 6.86
Operating and Overhead Costs
(per Mcfe):
Lease operating expenses $ 1.17 $ 0.78 $ 1.11 $ 0.86
Production and severance taxes 0.47 0.08 0.49 (0.11)
General and administrative 1.31 1.38 1.24 1.45
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Total $ 2.95 $ 2.24 $ 2.84 $ 2.20
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Cash Operating Margin (per Mcfe) $ 7.41 $ 4.37 $ 7.71 $ 4.66
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Other (per Mcfe):
Depreciation, depletion and
amortization--oil and natural
gas properties $ 2.00 $ 1.70 $ 2.01 $ 1.86
Results of Operations -- Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008
Oil and Natural Gas Sales. Oil and natural gas sales in the three months ended September 30, 2009 decreased 37% to $23.1 million compared to the three months ended September 30, 2008. This decrease was due to a 36% decrease in the average realized price of oil and natural gas, net of hedging activities. The average price per barrel of oil and Mcf of natural gas received (net of hedging) in the three months ended September 30, 2009 was $80.82 and $6.26, respectively, compared to $99.83 and $9.76, respectively, in the three months ended September 30, 2008. Production of oil for the three months ended September 30, 2009 decreased to 28 MBbls compared to 51 MBbls for the three months ended September 30, 2008, a decrease of 45%. The decrease in oil production is due to the natural decline in the Company's Cotton Valley Sand vertical well production which has historically provided most of the Company's oil production. H/B horizontal wells typically do not have oil production. Natural gas production for the three months ended September 30, 2009 increased to 3,322 MMcf compared to 3,204 MMcf for the three months ended September 30, 2008, an increase of 4%. The increase in natural gas production resulted from production related to nine producing H/B horizontal wells that were on-line during the third quarter of 2009. Production from H/B horizontal wells accounted for 53% of total production in the third quarter of 2009.
In the three months ended September 30, 2009, as a result of hedging activities, we recognized an increase in oil and natural gas sales of $0.5 million and $9.3 million, respectively, compared to a decrease in oil and natural gas sales of $0.8 million and $2.1 million, respectively, in the third quarter of 2008. In the third quarter of 2009, hedging increased the average natural gas and oil sales price by $2.82 per Mcf and $16.89 per Bbl compared to a decrease in natural gas sales price of $0.66 per Mcf and $15.14 per Bbl in the third quarter of 2008.
Lease Operations. Lease operations expense decreased $1.4 million, or 34.1%, in the three months ended September 30, 2009 to $2.7 million, compared to the three months ended September 30, 2008. Lease operations expense on an equivalent unit of production basis decreased $0.39 per Mcfe in the three months ended September 30, 2009 to $0.78 per Mcfe, compared to the three months ended September 30, 2008. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented during 2009. During the three months ended September 30, 2008, the Company incurred additional lease operating expenses related to several well workovers and road and compressor repairs. 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 horizontal well results in lower per unit lease operating costs.
Production and Severance Taxes. Production and severance taxes decreased 83% from $1.7 million in the three months ended September 30, 2008 to $0.3 million in the three months ended September 30, 2009. Production and severance tax expense decreased in comparison to the third quarter of 2008 due to a decrease in oil and natural gas prices between the two periods and the fact that more producing wells in the third quarter of 2009 have received production and severance tax exemptions. Upon approval by the State of Texas, certain wells, including our H/B horizontal wells, are exempt from severance taxes for a period of ten years and we expect this to continue to reduce our expense going forward.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $0.5 million, or 5%, to $7.8 million in the three months ended September 30, 2009 compared to the three months ended September 30, 2008. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.70 per Mcfe in the three months ended September 30, 2009 compared to $2.00 per Mcfe in the three months ended September 30, 2008. This decrease is due primarily to a lower cost basis in oil and gas properties subject to amortization due to previously recorded impairment charges as a result of lower oil and natural gas prices at year end 2008 and March 31, 2009.
General and Administrative Expense. General and administrative expense for the three months ended September 30, 2009 was $4.8 million compared to $4.6 million for the three months ended September 30, 2008, an increase of $0.2 million, or 5%. General and administrative expense per equivalent unit of production was $1.38 per Mcfe for the three months ended September 30, 2009 compared to $1.31 per Mcfe for the three months ended September 30, 2008. A significant portion of the Company's general and administrative expense is related to non-cash compensation expense. Non-cash compensation expense for the three months ended September 30, 2009 and 2008 was $1.4 million or 29% of total general and administrative expenses and $1.0 million or 21% of total general and administrative expenses, respectively. General and administrative expenses have 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.
Interest. Interest expense for the three months ended September 30, 2009 was $4.2 million compared to approximately $3.6 million for the three months ended September 30, 2008. This increase is primarily due to a greater amount of outstanding debt during the three months ended September 30, 2009. Interest expense for the three months ended September 30, 2008 and 2009 includes non-cash interest expense of $757,000 and $846,000, respectively related to the amortization of our 5.00% convertible senior notes and the adoption of FASB ASC 470-20, Accounting for Convertible Debt Instruments that May Be Settled in Cash Upon Conversion.
Income Taxes. Income tax for the three months ended September 30, 2009 was an expense of $4.5 million as compared to an expense of $4.7 million in the three months ended September 30, 2008. The tax expense for the three months ended September 30, 2009 was due to $4.6 million of deferred tax expense relating to a valuation allowance for federal net operating loss carryforwards that increased our tax expense.
Results of Operations -- Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008
Oil and Natural Gas Sales. Oil and natural gas sales in the nine months ended September 30, 2009 decreased 32% to $68.7 million compared to the nine months ended September 30, 2008. This decrease was due to a 35% decrease in the average realized price of oil and natural gas, net of hedging activities, partially offset by a 4% increase in production. The average price per barrel of oil and Mcf of natural gas received (net of hedging) in the nine months ended September 30, 2009 was $72.79 and $6.56, respectively, compared to $98.94 and $9.94, respectively, in the nine months ended September 30, 2008. Production of oil for the first nine months of 2009 decreased to 91MBbls compared to 150 MBbls for the first nine months of 2008, a decrease of 39%. The decrease in oil production is due to the natural decline in the Company's Cotton Valley Sand vertical well production which has historically provided most of the Company's oil production. H/B horizontal wells typically do not have oil production. Natural gas production for the first nine months of 2009 increased to 9,477 MMcf compared to 8,733 MMcf for the first nine months of 2008, an increase of 9%. The increase in natural gas production resulted from production related to nine producing H/B horizontal wells that were on-line during the first nine months of 2009. Production from H/B horizontal wells accounted for 30% of total production in the first nine months of 2009.
In the nine months ended September 30, 2009, as a result of hedging activities, we recognized an increase in oil and natural gas sales of $1.9 million and $27.7 million, respectively, compared to a decrease in oil and natural gas sales of $1.8 million and $5.8 million, respectively, in the first nine months of 2008. In the first nine months of 2009, hedging increased the average natural gas and oil sales price by $2.93 per Mcf and $21.11 per Bbl compared to a decrease in natural gas sales price of $0.67 per Mcf and $11.97 per Bbl in the first nine months of 2008.
Lease Operations. Lease operations expense decreased $2.1 million, or 19%, in the nine months ended September 30, 2009 to $8.6 million, compared to $10.7 million in the nine months ended September 30, 2008. Lease operations expense on an equivalent unit of production basis decreased $0.25 per Mcfe in the nine months ended September 30, 2009 to $0.86 per Mcfe, compared to the nine months ended September 30, 2008. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented during the first nine months of 2009. 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 horizontal well will result in lower per unit lease operating costs.
Production and Severance Taxes. As a result of the recognition of severance tax refunds of approximately $2.0 million in the nine months ended September 30, 2009, production and severance taxes decreased 123% from an expense of $4.7 million in the nine months ended September 30, 2008 to income of $1.1 million in the nine months ended September 30, 2009. Upon approval by the State of Texas, certain wells, including our H/B horizontal wells, are exempt from severance taxes for a period of ten years and we expect this to reduce our expense going forward. Excluding the production and severance tax refunds received in the first nine months of 2009, production and severance tax expense decreased in comparison to the first nine months of 2008 due to a decrease in oil and natural gas prices between the two periods and the fact that more producing wells in the first nine months of 2009 have received the production and severance tax exemptions.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $1.6 million, or 7%, to $24.4 million in the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The increase in expense is due to the increase in depreciation related to property and equipment. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.86 per Mcfe in the nine months ended September 30, 2009 compared to $2.01 per Mcfe in the nine months ended September 30, 2008. This decrease in the rate per Mcfe is due to a lower cost basis in oil and gas properties subject to amortization due to previously recorded impairment charges as a result of lower oil and gas prices at year end 2008 and at March 31, 2009.
Impairment and other writedowns. As a result of lower oil and natural gas prices from year-end 2008, we recognized an impairment charge on oil and gas properties of $180.3 million in the nine months ended September 30, 2009. In addition, as a result of the decline in oil and natural gas related material costs, we recognized a writedown of $6.2 million on pipeline related inventories in this nine month period. The Company may be required to recognize additional impairment charges or writedowns in future reporting periods if market prices for oil or natural gas and material costs continue to decline.
General and Administrative Expense. General and administrative expense for the nine months ended September 30, 2009 was $14.6 million compared to $12.0 million for the nine months ended September 30, 2008, an increase of $2.6 million, or 22%. A $1.2 million allowance for bad debt was recognized in the second quarter of 2008 related to the bankruptcy of one of our crude oil purchasers. The allowance was subsequently adjusted downward in the third quarter of 2008 to $748,000. However, due to an unfavorable bankruptcy court ruling, we recognized $0.5 million additional bad debt expense in the second quarter of 2009. The reduction in bad debt expense between 2008 and 2009 was offset by an increase in non-cash compensation expense and an increase in administrative and supervisory personnel. General and administrative expense per equivalent unit of production was $1.45 per Mcfe for the nine months ended September 30, 2009 compared to $1.24 per Mcfe for the comparable period in 2008. Excluding the provisions for bad debt expense and non-cash compensation, general administrative expense for the nine months ended September 30, 2008 and 2009 would have been $0.95 per Mcfe and $1.04 per Mcfe, 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. In the second half of 2008, the Company added key employees to execute an H/B horizontal drilling program. As a result, personnel costs have increased in comparison to the first nine months of 2008. The Company expects general and administrative expenses on a per Mcfe basis to decrease as production increases.
Interest. Interest expense for the nine months ended September 30, 2009 was $12.1 million compared to $10.3 million for the nine months ended September 30, 2008. This increase is primarily due to a greater amount of outstanding debt during the nine months ended September 30, 2009. Interest expense for the nine months ended September 30, 2008 and 2009 includes non-cash interest expense of $1.9 million and $2.7 million, respectively related to the amortization of our 5.00% convertible senior notes and the adoption of FASB ASC 470-20, Accounting for Convertible Debt Instruments that May Be Settled in Cash Upon Conversion.
Income Taxes. Income tax for the nine months ended September 30, 2009 was a benefit of $43.7 million as compared to an expense of $13.2 million in the nine months ended September 30, 3008. The effective tax rates for the nine months ended September 30, 2008 and 2009 were 32% and 24%, respectively. The decrease in the effective tax rate in the nine months ended September 30, 2009 was due to $17.3 million of deferred tax expense relating to a valuation allowance for federal net operating loss carryforwards that reduced our tax benefit. Excluding the deferred tax expense for the valuation allowance, our effective income tax rate would have been approximately 34%.
Net Income and Net Income Per Share
For the three months ended September 30, 2009 and 2008, we reported net loss of $2.8 million and net income of $9.6 million, respectively, a decrease of 129%. Net loss applicable to common stock for the three months ended September 30, 2009 was $3.9 million compared to net income of $8.5 million for the three months ended September 30, 2008, a decrease of 146%. Net loss per basic and fully diluted share was $0.19 for the third quarter of 2009 compared to net income of $0.57 and $0.50 respectively, per basic and fully diluted share for the third quarter of 2008. Weighted average fully-diluted shares outstanding increased by 24% from 17,099,929 shares in the third quarter of 2008 to 21,160,616 shares in the third quarter of 2009.
For the nine months ended September 30, 2009 and 2008, we reported a net loss of $135.4 million and net income of $28.2 million, a decrease of 580%. Net income (loss) applicable to common stock for the nine months ended September 30, 2009 and 2008 was $(138.9) million and $24.7 million, respectively, a decrease of 662%. Net loss per basic and fully diluted share was $7.61 and $7.60 respectively, for the nine months of 2009 compared to net income of $1.79 and $1.62 respectively, for the nine months of 2008. Weighted average fully-diluted shares outstanding increased by 20% from 15,224,742 shares in the first nine months of 2008 to 18,278,639 shares in the first nine months of 2009.
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 commodity prices, we have entered into crude oil and natural gas swaps, collars, and put spreads.
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 response to the changing economic environment, we have revised our capital expenditure budget throughout 2009, and we now expect expenditures of approximately $175.0 million for 2009, a decrease from $220 million budgeted at the beginning of the year. In the nine months ended September 30, 2009, our capital expenditures were $138.3 million of which $82.3 million was for drilling and completing H/B horizontal wells; $9.2 million was for rig delay fees; $9.3 million on Cotton Valley and Travis Peak drilling and other drilling related expenditures including tubular inventory and $37.5 million was related to leasehold and infrastructure costs. In the nine months ended September 30, 2009, we had nine H/B horizontal well completions.
In the last three months of 2009, we expect to have capital expenditures of approximately $36.7 million primarily related to drilling and completing H/B horizontal wells. Our current capital expenditure budget for the rest of 2009 assumes two operated rigs drilling H/B horizontal wells. We do not expect to have significant infrastructure or inventory expenditures in the last three months of 2009. We activated an additional drilling rig on October 15, 2009 and we expect to drill and complete one additional H/B horizontal well and begin drilling a second H/B horizontal well with this additional rig in 2009.
Throughout 2009, we have accessed the capital markets or sold non-core assets to fund the Company's H/B horizontal drilling program. In May 2009, we were successful in raising $65 million from the sale of 5.75 million shares of common stock. In October 2009, we were again successful in raising $190 million, before estimated expenses of $9 million, from the sale of 6.95 million shares of common stock and the issuance of $86 million of 4.5% convertible senior notes due 2015. In addition, to these capital market transactions, we received $36 million in November 2009 from the partial monetization of our mid-stream assets. We expect that this capital raised during 2009 will be sufficient to fund a four rig drilling program through the point at which our discretionary cash flows will exceed our capital expenditures which is anticipated to be the second half of 2012. We will continually adjust our capital expenditures based on the current commodity price environment to ensure that we have adequate liquidity in either cash and/or with 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 36 month period.
Cash Flow -- Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008
In the nine months ended September 30, 2009 and 2008, we spent $138.3 million and $216.1 million, respectively, in oil and gas acquisitions and development activities, including the acquisition of property and equipment. These investments were funded during the nine months ended September 30, 2009 by cash flow from operations, borrowing under our revolving bank credit facility and proceeds from the issuance of common stock. Cash flow provided by operating activities in the nine months ended September 30, 2009 and 2008 was $31.7 million and $58.8 million, respectively. The decrease in net cash provided by operating activities is due to a decrease in income from operations caused by lower oil and natural gas prices.
GMXR is a 'Pure Play', E & P Company with one of the most leveraged Haynesville / Bossier Horizontal Shale Operations in East Texas. The Company has 465 Bcfe in proved reserves (YE2008), 94% of which are natural gas. The Company's proved reserves are 81% operated and consist of 761 gross / 519 net H/B Hz 80 acre un-drilled locations; 10 gross / 9.9 net H/B producers, and 324 gross / 186.9 net Cotton Valley Sand ("CVS") producers; 2,657 gross / 1,974 net CVS 20 acre un-drilled locations; and 45 gross / 37.5 net Travis Peak / Hosston Sands & Pettit producers. These multiple resource layers provide high probability and the potential for repeatable, organic growth.
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 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)
Dec. 31, Sept. 30,
2008 2009
-------- --------
ASSETS (as adjusted)(1) (Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 6,716 $ 4,192
Accounts receivable--interest owners 576 1,272
Accounts receivable--oil and gas revenues, net 9,145 6,585
Derivative instruments 21,325 14,677
Inventories 691 532
Prepaid expenses and deposits 2,040 2,987
-------- --------
Total current assets 40,493 30,245
-------- --------
OIL AND GAS PROPERTIES, BASED ON THE FULL COST
METHOD
Properties being amortized 608,865 722,163
Properties not subject to amortization 36,034 40,978
Less accumulated depreciation, depletion,
and amortization (211,785) (410,755)
-------- --------
433,114 352,386
-------- --------
PROPERTY AND EQUIPMENT, AT COST, NET 85,284 94,682
DEFERRED INCOME TAXES 7,649 53,047
OTHER ASSETS 7,131 5,483
-------- --------
TOTAL ASSETS $573,671 $535,843
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 35,599 $ 20,038
Accrued expenses 6,089 13,395
Accrued interest 3,290 1,851
Revenue distributions payable 5,293 3,512
Deferred income taxes 6,996 5,715
Current maturities of long-term debt 61 56
-------- --------
Total current liabilities 57,328 44,567
-------- --------
LONG-TERM DEBT, LESS CURRENT MATURITIES 224,281 270,368
OTHER LIABILITIES 6,645 9,308
SHAREHOLDERS' 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,
3,000,000 shares authorized, 2,000,000
shares issued and outstanding (aggregate
liquidation preference $50,000,000) 2 2
Common stock, par value $.001 per
share--authorized 50,000,000 shares; issued
and outstanding 18,794,691 shares in 2008
and 24,263,791 shares in 2009 19 25
Additional paid-in capital 328,002 397,577
Retained earnings (57,902) (195,597)
Accumulated other comprehensive income, net
of taxes 15,296 9,593
-------- --------
Total shareholders' equity 285,417 211,600
-------- --------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $573,671 $535,843
======== ========
(1) Adjusted for retrospective application of FASB ASC 470-20
"Accounting for Convertible Debt Instruments That May Be Settled
in Cash upon Conversion."
GMX Resources Inc. And Subsidiaries
Consolidated Statements of Operations
(dollars in thousands, except share and per share data)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- ---------------------
2008 2009 2008 2009
---------- ---------- ---------- ----------
(as adjusted) (as adjusted)
(1) (1)
OIL AND GAS SALES $ 36,408 $ 23,075 $ 101,647 $ 68,737
EXPENSES:
Lease operations 4,111 2,708 10,651 8,581
Production and
severance taxes 1,651 279 4,709 (1,074)
Depreciation,
depletion, and
amortization 8,287 7,834 22,743 24,386
Impairment and other
writedowns -- -- -- 186,517
General and
administrative 4,592 4,811 11,958 14,580
---------- ---------- ---------- ----------
Total expenses 18,641 15,632 50,061 232,990
Income (loss)
from operations 17,767 7,443 51,586 (164,253)
NON-OPERATING INCOME
(EXPENSES):
Interest expense (3,583) (4,229) (10,338) (12,080)
Interest and other
income 100 4 146 40
Unrealized loss on
derivatives -- (1,454) -- (2,827)
---------- ---------- ---------- ----------
Total non-operating
expense (3,483) (5,679) (10,192) (14,867)
Income (loss)
before income
taxes 14,284 1,764 41,394 (179,120)
---------- ---------- ---------- ----------
(PROVISION) BENEFIT FOR
INCOME TAXES (4,653) (4,546) (13,208) 43,738
---------- ---------- ---------- ----------
NET INCOME (LOSS) 9,631 (2,782) 28,186 (135,382)
Preferred stock
dividends 1,156 1,156 3,469 3,469
---------- ---------- ---------- ----------
NET INCOME (LOSS)
APPLICABLE TO COMMON
STOCK $ 8,475 $ (3,938) $ 24,717 $(138,851)
========== ========== ========== ==========
EARNINGS (LOSS)
PER SHARE - Basic $ 0.57 $ (0.19) $ 1.79 $ (7.61)
========== ========== ========== ==========
EARNINGS (LOSS)
PER SHARE - Diluted $ 0.50 $ (0.19) $ 1.62 $ (7.60)
========== ========== ========== ==========
WEIGHTED AVERAGE
COMMON SHARES - Basic 14,900,089 21,122,331 13,835,487 18,235,889
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON
SHARES - Diluted 17,099,929 21,160,616 15,224,742 18,278,639
========== ========== ========== ==========
(1) Adjusted for retrospective application of FASB ASC 470-20
"Accounting for Convertible Debt Instruments That May Be Settled
in Cash upon Conversion."
GMX Resources Inc. And Subsidiaries
Consolidated Statements of Cash Flows
(dollars in thousands, except share and per share data)
(Unaudited)
Nine Months Ended
September 30,
------------------
2008 2009
-------- -------
(as adjusted)(1)
CASH FLOWS DUE TO OPERATING ACTIVITIES
Net income (loss) $ 28,186 $(135,382)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion, and amortization 22,743 24,386
Impairment and other writedowns -- 186,517
Deferred income taxes 13,173 (43,738)
Non-cash compensation expense 2,059 3,658
Other 1,460 5,779
Decrease (increase) in:
Accounts receivable (10,614) 1,378
Prepaid expenses and other assets 181 290
Increase (decrease) in:
Accounts payable and accrued expenses (2,982) (9,516)
Revenue distributions payable 4,634 (1,686)
-------- -------
Net cash provided by operating activities 58,840 31,686
-------- -------
CASH FLOWS DUE TO INVESTING ACTIVITIES
Purchase of oil and natural gas properties (196,870) (116,013)
Purchase of property and equipment (19,269) (22,247)
-------- -------
Net cash used in investing activities (216,139) (138,260)
-------- -------
CASH FLOWS DUE TO FINANCING ACTIVITIES
Advance on borrowings 160,000 99,000
Payments on debt (204,115) (55,069)
Issuance of 5.00% Senior Convertible Notes 125,000 ---
Proceeds from sale of common stock 134,681 65,264
Dividends paid on Series B preferred stock (3,469) (2,313)
Fees paid relating to financing activities (4,796) (2,832)
-------- -------
Net cash provided by financing activities 207,301 104,050
-------- -------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS 50,002 (2,524)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 5,907 6,716
-------- -------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 55,909 $ 4,192
======== =======
SUPPLEMENTAL CASH FLOW DISCLOSURE:
CASH PAID DURING THE PERIOD FOR:
Interest $ 7,859 $ 5,283
Taxes $ 35 $ ---
(1) Adjusted for retrospective application of FASB ASC 470-20
"Accounting for Convertible Debt Instruments That May Be Settled
in Cash upon Conversion."
GMX Resources Inc. and Subsidiaries
Non-GAAP Supplemental Information - Discretionary Cash Flows (1)
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2009 2008 2009
(as adjusted) (as adjusted)
(In thousands)
Net Income (Loss) $ 9,631 $ (2,782) $ 28,186 $(135,382)
Non cash charges:
Depreciation, depletion,
and amortization 8,287 7,834 22,743 24,386
Impairment and other
writedowns -- -- -- 186,517
Deferred income taxes 4,618 4,546 13,173 (43,738)
Non cash compensation
expense 970 1,376 2,059 3,658
Other (1,875) 2,750 1,460 5,779
Preferred stock dividends (1,156) -- (3,469) (2,313)
--------- --------- --------- ---------
Non-GAAP discretionary
cash flow $ 20,475 $ 13,724 $ 64,152 $ 38,907
========= ========= ========= =========
Reconciliation of GAAP
"Net cash provided by
operating activities" to
Non-GAAP "discretionary
cash flow
Net cash provided by
operating activities $ 19,287 $ 11,108 $ 58,840 $ 31,686
Adjustments:
Changes in operating
assets and liabilities 2,344 2,616 8,781 9,534
Preferred stock dividends (1,156) -- (3,469) (2,313)
--------- --------- --------- ---------
Non-GAAP discretionary
cash flow $ 20,475 $ 13,724 $ 64,152 $ 38,907
========= ========= ========= =========
(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 to internally
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.