OKLAHOMA CITY, Aug. 3, 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 announced a Letter of Intent for the sale of an interest in its Endeavor Pipeline assets; reported financial and operating results for the three and six months ended June 30, 2009; updated 2009 guidance; and announced resolution of SEC comment letter.
Letter of Intent for an Interest in Endeavor Pipeline Assets
GMXR announced today it has signed a non-binding Letter of Intent to sell an interest in its Endeavor Pipeline assets to Kinder Morgan Tejas Pipeline LLC for $40 million. The Company expects the transaction to close within 45 days, subject to the satisfactory completion of due diligence and the negotiation and execution of definitive agreements. This transaction will provide the capital required by the Company to add a second H&P FlexRig3(TM) to its Haynesville/Bossier horizontal development program.
Financial Results for the Three Months Ended June 30, 2009
GMXR reported a net loss of $8.2 million for the three months ended June 30, 2009 as compared to 2008's second quarter net income of $12.1 million. Diluted earnings (loss) per share for the three months ended June 30, 2009 were ($0.51) per share compared to $0.74 per share for the three months ended June 30, 2008. Adjusted net income available to common shareholders, a non-GAAP measure adjusting for unrealized derivative losses, non-cash inventory writedowns, bad debt expenses and income tax valuation allowances, was $1.4 million or $0.08 per share for the second quarter of 2009 and is broken out as follows:
Three Months Ended
June 30, 2009
----------------------
(in thousands, except per share amounts) Amount per share
--------- ---------
Net loss applicable to common stock $ (9,321) $ (0.51)
Adjustments:
Inventory writedown, net of taxes of $948 1,841 0.10
Deferred income tax valuation allowance 7,909 0.43
Unrealized losses on derivatives, net of
taxes of $350 680 0.04
Bad debt expense, net of taxes of $165 321 0.02
--------- ---------
Adjusted net income applicable to common
stock $ 1,430 $ 0.08
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The Company did not recognize a full cost accounting impairment charge during the three months ended June 30, 2009 due to an increase in natural gas and crude oil prices from March 31, 2009.
The second quarter operating results were impacted by the decline in market prices for crude oil and natural gas. Oil and gas sales in the second quarter of 2009 of $22.8 million decreased 40% from 2008's second quarter sales of $38.0 million as a 2% production increase was largely offset by lower crude oil and natural gas prices. GMXR's production from its East Texas operations in the second quarter of 2009 increased to 3.31 billion cubic feet equivalent of natural gas ("Bcfe") as compared to production of 3.25 Bcfe in the second quarter of 2008. Natural gas prices realized in the second quarter of 2009 averaged $6.54 per thousand cubic feet ("Mcf"), 41% lower than the $11.03 per Mcf realized in the second quarter of 2008. GMXR's average realized oil prices in the second quarter of 2009 declined to $75.88 per barrel, 30% lower than the $108.10 per barrel in 2008's second quarter.
Among non-GAAP measures, discretionary cash flow generated by GMXR in the second quarter of 2009 was $12.0 million, a decrease of 55% over 2008's second quarter non-GAAP discretionary cash flow of $26.5 million.
Financial Results for the Six Months Ended June 30, 2009
GMXR reported a net loss of $132.6 million for the six months ended June 30, 2009 as compared to net income of $18.3 million in the six months ended June 30, 2008. Diluted earnings (loss) per share for the six months ended June 30, 2009 was ($8.03) per share compared to $1.14 per share for the six months ended June 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 $2.1 million or $0.13 per share for the first half of 2009 and is broken out as follows:
Six Months Ended
June 30, 2009
----------------------
(in thousands, except per share amounts) Amount per share
---------- ----------
Net loss applicable to common stock $(134,911) $ (8.03)
Adjustments:
Full cost accounting impairment, net of
taxes of $61,298 118,990 7.09
Inventory writedown, net of taxes
of $2,118 4,111 0.24
Deferred income tax valuation allowance 12,713 0.76
Unrealized losses on derivatives, net of
taxes of $467 906 0.05
Bad debt expense, net of taxes of $165 321 0.02
---------- ----------
Adjusted net income applicable to common
stock $ 2,130 $ 0.13
========== ==========
The 2009 operating results were impacted by the decline in market prices for crude oil and natural gas. Oil and gas sales in the first half of 2009 of $45.7 million decreased 30% from 2008's sales of $65.2 million as a 7% production increase was largely offset by lower crude oil and natural gas prices. GMXR's production from its East Texas operations in the first half of 2009 increased to 6.5 Bcfe as compared to production of 6.1 Bcfe in the first half of 2008. Natural gas prices realized in the first half of 2009 averaged $6.72 per Mcf, 33% lower than the $10.04 per Mcf realized in the first half of 2008. GMXR's average realized oil prices in the first half of 2009 declined to $68.49 per barrel, 30% lower than the $98.47 per barrel in the six months ended June 30, 2008.
Among non-GAAP measures, discretionary cash flow generated by GMXR in the six months ended June 30, 2009 was $25.2 million, a decrease of 42% over 2008's first half non-GAAP discretionary cash flow of $43.3 million.
Our oil and gas properties impairment charge in the first half of 2009 was recorded in the first quarter and was based on March 31, 2009 cash spot market prices of $3.63 per Mmbtu for natural gas and $49.64 per Bbl of oil computed in accordance with current guidelines established by the Securities and Exchange Commission (SEC). Recently, the SEC issued new rules related to disclosure of oil and natural gas reserves and the computation of impairment for companies that follow the full cost method of accounting. These new rules, which do not take effect until the end of 2009, will change the prices utilized in our SEC reserve estimates and will use an average cash spot market price based on the first day of each month over the trailing twelve month period rather than the cash spot market price at the end of each quarter.
Second Quarter 2009 Operational Results
GMXR has 62,160 (42,300 net) acres that are prospective for Haynesville/Bossier ("H/B") development, giving us a total of 777 gross (529 net) 80-acre Haynesville/Bossier horizontal ("H/B Hz") locations. Our H/B Hz development in East Texas/Northwest Louisiana continues to be very successful. The Company has drilled and completed a total of seven H/B Hz wells, drilled but not yet completed two additional wells and is currently drilling its tenth H/B Hz well.
Cost Reduction and CAPEX Control
The Company's focus on reduction in drilling costs has continued to drive favorable economics with rates of return in the range of 35% to 45%, when you include our hedges and use a 5.4 - 6.5 Bcfe EUR. The emphasis on supplier selection, drilling methodology and the deployment of the FlexRig3(TM) from Helmerich and Payne has facilitated a dramatic drop in total costs. The latest completion (Holt 1H) will be in the $7 million range for total completed well cost. The Company is continuing to focus on reducing drilling times by an additional five to ten days which could reduce well costs by $375,000 to $750,000. Current frac and stimulation costs have been reduced to approximately one third the cost per stage compared to similar completions in the first quarter. These cost reductions are a combination of supplier base management, proppant selection and frac design. The Company continues to develop frac and stimulation schemes that will deliver the maximum results with decreasing costs.
The Company spent a total of $41.9 million in CAPEX during the second quarter. This was a decrease in capital expenditure of 41% as compared to $70.5 million in the first quarter. In the six months ended June 30, 2009, our capital expenditures were $112.4 million of which $64.2 million was for drilling and completing H/B horizontal wells; $6.1 million was for rig delay fees; $9.0 million on Cotton Valley and Travis Peak drilling and other drilling related expenditures including tubular inventory and $33.1 million was related to leasehold and infrastructure costs. For the six months ended June 30, 2009, the Company had six H/B Hz completions and the Company expects to have three completions in each of the third and fourth quarters of 2009.
In the last six months of 2009, we expect to have capital expenditures of approximately $45.0 million a 60% reduction from 1H 2009. Of the remaining 2009 capital expenditures, $34.0 million is related to drilling and completing H/B horizontal wells, $6.0 million is related to rig termination and lay down fees and $5 million is related to leasehold and infrastructure costs. Our current capital expenditure budget for the rest of 2009 assumes one operated rig drilling H/B Hz wells. Upon successful completion of the Endeavor Pipeline transaction, the Company will bring up an additional H&P FlexRig3 on or around October 1st. In this event, the Company expects to drill and complete an additional 2 H/B Hz wells in 2H 2009 for $13 million of additional CAPEX.
Production and Well Performance
GMXR produced 3.31 Bcfe in Q2 2009 as compared to 3.25 Bcfe in Q2 2008, a 2% increase. GMXR produced 6.5 Bcfe in 1H 2009 compared to 6.1 Bcfe in 1H 2008, a 7% increase. Sequentially, production increased 3% from Q1 2009 to Q2 2009. Production from the H/B Hz wells was approximately 31% and 24% of the Company's production for the three and six months ended June 30, 2009, respectively.
The five H/B Hz wells with lateral lengths in excess of 4000' have averaged 5.4 Mmcfg for the first 30 days of production with an average Initial Production ("IP") rate of 9.0 Mmcfg/d. Four of those five have been on for at least 60 days with an average of 3.9 Mmcfg for the second 30 day period and two of those five wells have been on production for at least 90 days and have averaged 3.4 Mmcfg for the third 30 days. This production data fits our forecast very well and indicates EUR potential in the range of 5.4 Bcfe to 6.5 Bcfe depending on the decline rate and B-factor applied to the production rates. Decline rates in the Company's East Texas core area appear to be flatter than decline rates reported by other operators in N. Louisiana.
The Company drilled and completed a total of four H/B Hz wells in the second quarter, and drilled but has not yet completed a fifth well (TJT Simpson 1H), which is scheduled to complete in August 2009. Additionally the Company spud and began drilling the Holt 1H, currently on flowback and the Verhalen "B" 1H which is currently drilling and expected to complete in late August 2009.
Previously Reported Second Quarter Well Results
- Our fourth H/B Hz well, the Baldwin #14H, had a 24 hour initial production rate of 9.2 million cubic feet of gas per day ("Mmcfgpd") on a 20/64th choke at 4,874 pounds of flowing casing pressure ("FCP"). The lateral length of this well is 4,420' and is located entirely in the upper sub-layers (the "A" sub layer) of the H/B. The well had thirteen fracture treatment stages.
- Our fifth H/B Hz completion was the Verhalen "A" #2H which had a 24 hour initial production rate of 8.5 Mmcfgpd on a 14/64th choke at 4,164 pounds of FCP. The lateral length of this well is 4,260' and is located entirely in the "A" sub-layer of the H/B. The well had twelve fracture treatment stages.
- Our sixth H/B Hz completion was the Blocker Ware #19H which had a 24 hour initial production rate of 8.9 Mmcfgpd on a 22/64th choke at 4,470 pounds of FCP. The lateral length of this well is 4,450' and is located entirely in the "A" sub-layer of the H/B. The well had twelve fracture treatment stages.
- The seventh H/B Hz completion was the Blocker Heirs #12H which had a 24 hour initial production rate of 9.4 Mmcfgpd on a 23/64th choke at 5,344 pounds of FCP. The lateral length of this well is 5,100' and is located entirely in the "A" sub-layer of the H/B. The well had 14 fracture treatment stages.
2009 Updated Guidance
GMXR's current 2009 one rig CAPEX budget is estimated at $157 million which includes the drilling and completion of 10 HB Hz wells and 2 other H/B Hz completions in 2009. Almost 100% of the remaining $45 million related to the 2009 CAPEX will be focused on Haynesville/Bossier horizontal drilling which has the Company's highest expected rate of return and includes the drilling and completion of four H/B wells and two completions of H/B Hz wells that have been successfully drilled.
The Company expects production for the year to be in the range of 13.5 to 14.5 Bcfe with Q3 production in the range of 3.3 to 3.6 Bcfe.
Resolution of SEC Comment Letter
On July 20, 2009, the Company received notification from the SEC that the SEC had no further comments after reviewing the Company's responses to the SEC's comments (originally received in January 2009), which had focused on certain aspects of the Company's oil and gas reserves and production.
Management Comment
Ken L. Kenworthy, Chief Executive Officer, said "The second quarter was incredibly active for the Company. The entire company from Oklahoma City, Oklahoma to Harrison County, Texas performed to its highest level under very adverse economic and market conditions. In addition to the drilling and completion of four Haynesville horizontal wells we lowered our completed well costs nearly 40% to $7MM; increased our average IP rate to 9 mmcfg/d; we raised $69 million in a follow on equity offering dramatically improving our liquidity; successfully negotiated a new borrowing base with our banks; added a new bank to our lending group; positioned the Company to find a very strong partner in the mid-stream sector to purchase an interest in the assets of our wholly owned subsidiary Endeavor Pipeline and broadened our management by creating three new executive positions.
"We are continuing to focus on our liquidity and are pleased to be able to announce a Letter of Intent has been signed with Kinder Morgan for an interest in the assets of our Endeavor Pipeline subsidiary. This transaction will provide enough near term liquidity for us to be able to activate another FlexRig3(TM) in early October. Once we activate our second H/B Hz rig, we will actively attempt to hedge 60% - 80% of our future production, to help assure our operating income and lock-in higher returns. Additionally, the activation will further reduce our 'lay down fees' for our contracted rigs. This focus on liquidity should reassure our shareholders that we can continue to find avenues to exploit our position in the H/B Hz development and ultimately return to a growth and value enhancement business plan."
GMXR Second Quarter 2009 Earnings Conference Call
GMXR has scheduled a conference call for Tuesday, August 4, 2009 at 10:00 a.m. CDT (11:00 a.m. EDT) to discuss second quarter 2009 financial and operating results. To access the call, dial 877.795.3647 or 719.325.4907 before the call begins. A replay of the call will be available after 2:00 PM, August 4, 2009. To access the replay, please dial 888.203.1112 or 719.457.0820 and reference passcode 1340685. 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 Six Months Ended
June 30, 2009
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2008 2009 2008 2009
-------- -------- -------- --------
Production:
Oil (MBbls) 50 33 98 63
Natural gas (MMcf) 2,949 3,113 5,529 6,155
Gas equivalent production
(MMcfe) 3,254 3,309 6,119 6,533
Average daily (MMcfe) 35.7 36.4 33.6 36.1
Average Sales Price:
Oil (per Bbl)
Wellhead price $ 121.21 $ 54.04 $ 108.79 $ 45.50
Effect of hedges (13.11) 21.84 (10.32) 22.99
-------- -------- -------- --------
Total $ 108.10 $ 75.88 $ 98.47 $ 68.49
Natural gas (per Mcf)
Wellhead price $ 12.22 $ 3.36 $ 10.71 $ 3.73
Effect of hedges (1.19) 3.18 (0.67) 2.99
-------- -------- -------- --------
Total $ 11.03 $ 6.54 $ 10.04 $ 6.72
Average sales price (per
Mcfe) $ 11.70 $ 6.90 $ 10.66 $ 6.99
Operating and Overhead
Costs (per Mcfe):
Lease operating expenses $ 0.97 $ 0.82 $ 1.07 $ 0.90
Production and severance
taxes 0.46 0.09 0.50 (0.21)
General and administrative 1.47 1.61 1.20 1.50
-------- -------- -------- --------
Total $ 2.90 $ 2.52 $ 2.77 $ 2.19
-------- -------- -------- --------
Cash Operating Margin (per
Mcfe) $ 8.80 $ 4.38 $ 7.89 $ 4.80
======== ======== ======== ========
Other (per Mcfe):
Depreciation, depletion
and amortization--oil
and natural gas
properties $ 2.02 $ 1.47 $ 2.02 $ 1.95
Results of Operations for the Three Months Ended June 30, 2009 Compared to the Three Month Ended June 30, 2008
Oil and Natural Gas Sales. Oil and natural gas sales in the three months ended June 30, 2009 decreased 40% to $22.8 million compared to the three months ended June 30, 2008. This decrease was due to a 41.0% decrease in the average realized price of oil and natural gas, net of hedging activities, partially offset by a 1.7% increase in production. The average price per barrel of oil and Mcf of natural gas received (net of hedging) in the three months ended June 30, 2009 was $75.88 and $6.54, respectively, compared to $108.10 and $11.03, respectively, in the three months ended June 30, 2008. Production of oil for the second quarter of 2009 decreased to 33 MBbls compared to 50 MBbls for the second quarter of 2008, a decrease of 34%. Natural gas production for the second quarter of 2009 increased to 3,113 MMcf compared to 2,949 MMcf for the second quarter of 2008, an increase of 5.6%. The increase in natural gas production resulted from production related to seven producing Haynesville/Bossier ("H/B") horizontal wells that were on-line during the second quarter of 2009. Production from H/B Hz wells accounted for 31% of total production in the second quarter of 2009.
In the three months ended June 30, 2009, as a result of hedging activities, we recognized an increase in oil and natural gas sales of $0.7 million and $9.9 million, respectively, compared to a decrease in oil and natural gas sales of $0.7 million and $3.5 million, respectively, in the second quarter of 2008. In the second quarter of 2009, hedging increased the average natural gas and oil sales price by $3.18 per Mcf and $21.84 per Bbl compared to a decrease in natural gas sales price of $ 1.19 per Mcf and $13.11 per Bbl in the second quarter of 2008.
Lease Operations. Lease operations expense decreased $0.4 million, or 13.8%, in the second quarter ended June 30, 2009 to $2.7 million, compared to the three months ended June 30, 2008. Lease operations expense on an equivalent unit of production basis decreased $0.15 per Mcfe in the three months ended June 30, 2009 to $0.82 per Mcfe, compared to the three months ended June 30, 2008. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in HB Hz well production and cost control measures implemented during 2009. With little to no incremental increase in lease operating costs from a Cotton Valley vertical well, the significantly larger amount of production from a H/B Hz well will result in lower per unit lease operating costs.
Production and Severance Taxes. Production and severance taxes decreased 79.6% from $1.5 million in the three months ended June 30, 2008 to $0.3 million in the three months ended June 30, 2009. Production and severance tax expense decreased in comparison to the second 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 second 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 $0.9 million, or 11.3%, to $6.8 million in the three months ended June 30, 2009. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.47 per Mcfe in the three months ended June 30, 2009 compared to $2.02 per Mcfe in the three months ended June 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 gas prices at year-end 2008 and at March 31, 2009.
Impairment of Oil and Natural Gas Properties and Property and Equipment. The Company did not recognize a full cost accounting impairment charge during the three months ended June 30, 2009 due to an increase in natural gas and crude oil prices from March 31, 2009. However, as a result of the continued decline in oil and natural gas related material costs, the Company recognized a write-down of $2.8 million on pipeline related inventories. The Company may be required to recognize additional impairment charges or write-downs 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 three months ended June 30, 2009 was $5.3 million compared to $4.8 million for the three months ended June 30, 2008, an increase of $0.5 million, or 11.2%. 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 2008. However, due to an unfavorable bankruptcy court ruling, we recognized $0.5 million of additional bad debt expense in the second quarter of 2009. The reduction in bad debt expense was offset by an increase in non-cash compensation expense of $0.8 million related to the issuance of restricted grants in the last twelve months. General and administrative expense per equivalent unit of production was $1.61 per Mcfe for the three months ended June 30, 2009 compared to $1.47 per Mcfe for the comparable period in 2008. Excluding the provisions for bad debt expense and non-cash compensation, general and administrative expense for the three months ended June 30, 2008 and 2009 would have been $0.98 per Mcfe and $1.09 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 accelerated horizontal drilling program. As a result, personnel costs have increased in comparison to 2008. 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 June 30, 2009 was $3.9 million compared to approximately $3.7 million for the three months ended June 30, 2008. This increase is primarily due to a greater amount of outstanding debt during the three months ended June 30, 2009. Interest expense for the three months ended June 30, 2008 and 2009 includes non-cash interest expense of $751,000 and $822,000, respectively related to the convertible notes and the adoption of FASB Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.
Income Taxes. Income tax for the three months ended June 30, 2009 was an expense of $8.1 million as compared to an expense of $5.2 million in the three months ended June 30, 3008. The tax expense in the three months ended June 30, 2009 was primarily due to $7.9 million of deferred tax expense relating to a valuation allowance for federal net operating loss carryforwards that increased our tax expense.
Results of Operations for the Six Months Ended June 30, 2009 Compared to the Six Month Ended June 30, 2008
Oil and Natural Gas Sales. Oil and natural gas sales in the six months ended June 30, 2009 decreased 30.0% to $45.7 million compared to the six months ended June 30, 2008. This decrease was due to a 34.4% decrease in the average realized price of oil and natural gas, net of hedging activities, partially offset by a 6.8% increase in production. The average price per barrel of oil and Mcf of natural gas received (net of hedging) in the six months ended June 30, 2009 was $68.49 and $6.72, respectively, compared to $98.47 and $10.04, respectively, in the six months ended June 30, 2008. Production of oil for the first six months of 2009 decreased to 63 MBbls compared to 98 MBbls for the first six months of 2008, a decrease of 35.7%. Natural gas production for the first six months of 2009 increased to 6,155 MMcf compared to 5,529 MMcf for the first six months of 2008, an increase of 11.3%. The increase in natural gas production resulted from production related to seven producing H/B horizontal wells that were on-line during the first six months of 2009. Production from H/B Hz wells accounted for 24% of total production in the first half of 2009.
In the six months ended June 30, 2009, as a result of hedging activities, we recognized an increase in oil and natural gas sales of $1.4 million and $18.4 million, respectively, compared to a decrease in oil and natural gas sales of $1.0 million and $3.7 million, respectively, in the first six months of 2008. In the first six months of 2009, hedging increased the average natural gas and oil sales price by $2.99 per Mcf and $22.99 per Bbl compared to a decrease in natural gas sales price of $ 0.67 per Mcf and $10.32 per Bbl in the first six months of 2008.
Lease Operations. Lease operations expense decreased $0.7 million, or 10.2%, in the six months ended June 30, 2009 to $5.9 million, compared to $6.5 million in the six months ended June 30, 2008. Lease operations expense on an equivalent unit of production basis decreased $0.17 per Mcfe in the six months ended June 30, 2009 to $0.90 per Mcfe, compared to the six months ended June 30, 2008. 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 the first six months of 2009. With little to no incremental increase in lease operating costs from a Cotton Valley vertical well, the significantly larger amount of production from a H/B Hz 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 six months ended June 30, 2009, production and severance taxes decreased 144.2% from an expense of $3.1 million in the six months ended June 30, 2008 to an income of $1.4 million in the six months ended June 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 six months of 2009, production and severance tax expense decreased in comparison to the first six 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 six months of 2009 have received severance tax exemptions.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $2.1 million, or 14.5%, to $16.6 million in the six months ended June 30, 2009. This increase in expense is due primarily 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 $1.95 per Mcfe in the six months ended June 30, 2009 compared to $2.02 per Mcfe in the six months ended June 30, 2008. The 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 of Oil and Natural Gas Properties and Property and Equipment. As a result of lower oil and natural gas prices from year-end 2008, the Company recognized an impairment charge on oil and gas properties of $180.3 million. In addition, as a result of the decline in oil and natural gas related material costs, the Company recognized a write-down of $6.2 million on pipeline related inventories. The Company may be required to recognize additional impairment charges or write-downs 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 six months ended June 30, 2009 was $9.8 million compared to $7.4 million for the six months ended June 30, 2008, an increase of $2.4 million, or 32.6%. 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 purchaser. The allowance was subsequently adjusted downward in the third quarter of 2008. However, due to an unfavorable bankruptcy court ruling, we recognized $0.5 million of additional bad debt expense in the second quarter of 2009. The reduction in bad debt expense 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 $1.50 per Mcfe for the six months ended June 30, 2009 compared to $1.20 per Mcfe for the comparable period in 2008. Excluding the provisions for bad debt expense and non-cash compensation, general administrative expense for the six months ended June 30, 2008 and 2009 would have been $0.83 and $1.07, 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 a H/B horizontal drilling program. As a result, personnel costs have increased in comparison to the first six 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 six months ended June 30, 2009 was $7.9 million compared to $7.1 million for the six months ended June 30, 2008. This increase is primarily due to a greater amount of outstanding debt during the six months ended June 30, 2009. Interest expense for the six months ended June 30, 2008 and 2009 includes non-cash interest expense of $ 1.1 million and $1.8 million, respectively related to the convertible notes and the adoption of FASB Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.
Income Taxes. Income tax for the six months ended June 30, 2009 was a benefit of $48.3 million as compared to an expense of $8.4 million in the six months ended June 30, 3008. The effective tax rates for the six months ended June 30, 2008 and 2009 were 31.5% and 26.7%, respectively. The decrease in the effective tax rate in the six months ended June 30, 2009 was due to $12.7 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
Net Income and Net Income Per Share -Three months ended June 30, 2009 Compared to Three months ended June 30, 2008. For the three months ended June 30, 2009 we reported a net loss of $8.2 million and for the three months ended June 30, 2008, we reported net income of $12.1 million. Net loss per basic and fully diluted share was $0.52 and $0.51, respectively, for the second quarter of 2009 compared to net income of $0.82 and $0.74 per basic and fully diluted share for the second quarter of 2008. Excluding the non-cash charges related to the impairment of oil and gas properties and inventory write-downs, unrealized losses on derivatives, bad debt expenses and adjustments for income tax valuation allowances, we would have reported net income of $1.4 million or $0.08 per dilutive share for the three months ended June 30, 2009. Weighted average fully-diluted shares outstanding increased by 23% from 14,724,564 shares in the second quarter of 2008 to 18,132,849 shares in the second quarter of 2009.
Net Income and Net Income Per Share -Six months ended June 30, 2009 Compared to Six months ended June 30, 2008. For the six months ended June 30, 2009 we reported a net loss of $132.6 million and for the six months ended June 30, 2008, we reported net income of $18.3 million. Net loss per basic and fully diluted share was $8.06 and $8.03, respectively, for the first half of 2009 compared to net income of $1.20 and $1.14, respectively per basic and fully diluted share for the first half of 2008. Excluding the non-cash charges of impairment of oil and gas properties and inventory write-downs, unrealized losses on derivatives, bad debt expenses and adjustments to income tax valuation allowances, we would have reported net income of $2.1 million or $0.13 per dilutive share for the six months ended June 30, 2009. Weighted average fully-diluted shares outstanding increased by 20% from 14,037,223 shares in the first half of 2008 to 16,791,133 shares in the first half of 2009.
The following table reconciles the weighted average shares outstanding used for the three and six months ended June 30:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2008 2009 2008 2009
---------- ---------- ---------- ----------
Weighted average
shares outstanding -
basic 13,302,728 18,093,208 13,290,504 16,746,112
Effect of dilutive
securities -
convertible notes 1,204,477 -- 610,859 --
Effect of dilutive
securities - stock
options 217,359 39,641 135,860 45,021
---------- ---------- ---------- ----------
Weighted average
shares outstanding -
diluted 14,724,564 18,132,849 14,037,223 16,791,133
---------- ---------- ---------- ----------
We did not recognize additional dilutive shares for the three and six months ended June 30, 2009 related to the convertible notes as the average stock prices for the three and six months ended June 30, 2009 of $12.41 and $15.20, respectively, did not exceed the conversion price of $32.50. The number of shares issuable increases as the Company's common stock price increases and is finally determined based on the Company's volume weighted average stock price for a specified 60 day measurement period ending on or about the actual conversion date.
Common shares loaned in connection with the convertible notes in the amount of 3,440,000 shares were not included in the computation of earnings per common share for the three and six months ended June 30, 2008 and 2009. While the borrowed shares are considered issued and outstanding for corporate law purposes, the Company believes that the borrowed shares are not considered outstanding for the purposes of computing and reporting earnings per share under GAAP currently in effect because the shares lent pursuant to the share lending agreement are required to be returned to the Company.
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. During 2009, we reduced our initial capital expenditure budget for 2009 from $220 million to approximately $157 million depending on the continued use of one drilling rig and the continuing decline in drilling and completion costs. In the six months ended June 30, 2009, our capital expenditures were $112.4 million of which $64.2 million was for drilling and completing H/B horizontal wells and $16.9 million was related to infrastructure and inventory. In the last six months of 2009, we expect to have capital expenditures of approximately $45.0 million. Of the remaining 2009 capital expenditures, $34.0 million is related to drilling and completing H/B horizontal wells and $6.0 million is related to rig termination and lay down fees. Our current capital expenditure budget for the rest of 2009 assumes one operated rig drilling H/B wells. We do not expect to have significant infrastructure or inventory expenditures in the last six months of 2009. We may continue to adjust this estimate to stay in line with market conditions during the year.
In the event natural gas prices remain at their current depressed levels or our capital expenditures exceed our current expected levels, we may not be able to increase our borrowing base under our revolving bank credit facility to fund a potential shortfall, and we do not expect to be able to grow significantly the available borrowing base in 2009. As a result, we may be required to further reduce or defer part of our 2009 capital expenditure program or seek additional capital through the issuance of additional long-term debt or equity.
Earlier in 2009, we were successful in raising $65 million through the issuance of common stock. However, the recent worldwide financial and credit crisis has adversely affected the ability of many companies to access the debt and equity markets. To the extent we determine to raise additional funds through the issuance of additional long-term debt or equity, any such decreased ability to obtain financing could adversely affect our capability to continue with our expected business plan.
As of June 30, 2009, we had $110 million outstanding on our credit facility that has a borrowing base of $175 million. On June 5, 2009, we completed our semi-annual redetermination of our revolving credit facility borrowing base. As a result, the borrowing base has been amended to $175 million, as compared to the prior level of $190 million. As of June 30, 2009, we were in compliance with all financial covenants under our credit facility.
In order to increase liquidity, we are exploring ways to monetize several non-core assets, such as a partial monetization of our mid-stream assets. Subsequent to June 30, 2009, the company entered into a non-binding letter of intent with a third party to monetize an interest in the Company's gathering assets for $40 million. The transaction is expected to close in the third quarter 2009. Upon successful completion of the transaction, the Company will activate an additional drilling rig on or around October 1, 2009 and expects to drill and complete two additional H/B Hz wells in 2009 resulting in approximately $13 million of additional CAPEX.
Cash Flow-Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008
In the six months ended June 30, 2009 and 2008, we spent $112.4 million and $120.9 million, respectively, in oil and natural gas acquisitions and development activities and related property and equipment. These investments were funded during the six months ended June 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 six months ended June 30, 2009 was $20.6 million compared to cash flow provided by operating activities in the six months ended June 30, 2008 of $39.6 million. The decrease in net cash provided by operating activities is due to a decrease in income from operations due to lower 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 763 gross / 521 net H/B Hz 80 acre un-drilled locations; 8 gross / 8 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.
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)
December 31, June 30,
2008 2009
---------------- ------------
ASSETS (as adjusted)(1) (Unaudited)
CURRENT ASSETS:
Cash and cash equivalents $ 6,716 $ 5,070
Accounts receivable - interest owners 576 664
Accounts receivable - oil and gas
revenues, net 9,145 5,887
Derivative instruments 21,325 22,544
Inventories 691 532
Prepaid expenses and deposits 2,040 1,632
---------------- ------------
Total current assets 40,493 36,329
---------------- ------------
OIL AND NATURAL GAS PROPERTIES, BASED
ON THE FULL COST METHOD
Properties being amortized 608,865 701,177
Properties not subject to amortization 36,034 38,078
Less accumulated depreciation,
depletion, and amortization (211,785) (404,823)
---------------- ------------
433,114 334,432
---------------- ------------
PROPERTY AND EQUIPMENT, AT COST, NET 85,284 94,155
DEFERRED INCOME TAXES 7,649 56,928
OTHER ASSETS 7,131 8,119
---------------- ------------
TOTAL ASSETS $ 573,671 $ 529,963
================ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 35,599 $ 16,610
Accrued expenses 6,089 16,819
Accrued interest 3,290 3,336
Revenue distributions payable 5,293 3,349
Deferred income taxes 6,996 8,118
Current maturities of long-term debt 61 58
---------------- ------------
Total current liabilities 57,328 48,290
---------------- ------------
LONG-TERM DEBT, LESS CURRENT
MATURITIES 224,281 255,731
OTHER LIABILITIES 6,645 7,114
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
and 24,561,558 shares in 2008 and 2009,
respectively 19 25
Additional paid-in capital 328,002 396,061
Retained earnings (57,902) (192,814)
Accumulated other comprehensive
income, net of taxes 15,296 15,554
---------------- ------------
Total shareholders' equity 285,417 218,828
---------------- ------------
TOTAL LIABILITIES AND
SHAREHOLDERS' EQUITY $ 573,671 $ 529,963
================ ============
(1) Adjusted for retrospective application of FSP APB 14-1 "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 Six Months Ended
June 30, June 30,
---------------------- ----------------------
2008 2009 2008 2009
---------- ---------- ---------- ----------
(as (as
adjusted) adjusted)
(1) (1)
OIL AND GAS SALES $ 38,040 $ 22,837 $ 65,239 $ 45,663
EXPENSES:
Lease operations 3,156 2,719 6,540 5,872
Production and
severance taxes 1,506 307 3,058 (1,353)
Depreciation,
depletion, and
amortization 7,713 6,837 14,456 16,553
Impairment and other
writedowns -- 2,789 -- 186,517
General and
administrative 4,786 5,324 7,366 9,769
---------- ---------- ---------- ----------
Total expenses 17,161 17,976 31,420 217,358
Income loss from
operations 20,879 4,861 33,819 (171,695)
NON-OPERATING INCOME
(EXPENSES):
Interest expense (3,656) (3,942) (7,133) (7,850)
Interest and other
income 10 14 46 33
Unrealized losses on
derivatives -- (1,028) -- (1,371)
---------- ---------- ---------- ----------
Total non-operating
expense (3,646) (4,956) (7,087) (9,188)
Income (loss) before
income taxes 17,233 (95) 26,732 180,883)
PROVISION (BENEFIT) FOR
INCOME TAXES 5,174 8,069 8,426 (48,285)
---------- ---------- ---------- ----------
NET INCOME (LOSS) 12,059 (8,164) 18,306 (132,598)
Preferred stock
dividends 1,157 1,157 2,313 2,313
---------- ---------- ---------- ----------
NET INCOME (LOSS)
APPLICABLE TO COMMON
STOCK $ 10,902 $ (9,321) $ 15,993 $ (134,911)
========== ========== ========== ==========
EARNINGS (LOSS) PER
SHARE - Basic $ 0.82 $ (0.52) $ 1.20 $ (8.06)
---------- ---------- ---------- ----------
EARNINGS (LOSS) PER
SHARE - Diluted $ 0.74 $ (0.51) $ 1.14 $ (8.03)
---------- ---------- ---------- ----------
WEIGHTED AVERAGE
COMMON SHARES -
Basic 13,302,728 18,093,208 13,290,504 16,746,112
---------- ---------- ---------- ----------
WEIGHTED AVERAGE
COMMON SHARES -
Diluted 14,724,564 18,132,849 14,037,223 16,791,133
========== ========== ========== ==========
(1) Adjusted for retrospective application of FSP APB 14-1 "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)
(Unaudited)
Six Months Ended
June 30,
-----------------------------
2008 2009
----------------- -----------
(as adjusted) (1)
CASH FLOWS DUE TO OPERATING ACTIVITIES
Net income (loss) $ 18,306 $(132,598)
Depreciation, depletion, and amortization 14,456 16,553
Impairment and other writedowns -- 186,517
Deferred income taxes 8,391 (48,285)
Non-cash compensation expense 1,089 2,282
Other 3,335 3,027
Decrease (increase) in:
Accounts receivable (11,378) 2,684
Inventory and prepaid expenses (3,602) 518
Increase (decrease) in:
Accounts payable and accrued
liabilities 6,612 (7,935)
Revenue distributions payable 2,344 (2,185)
----------------- -----------
Net cash provided by operating
activities 39,553 20,578
----------------- -----------
CASH FLOWS DUE TO INVESTING ACTIVITIES
Purchase of oil and natural gas
properties (110,179) (92,476)
Purchase of property and equipment (10,729) (19,914)
----------------- -----------
Net cash used in investing
activities (120,908) (112,390)
----------------- -----------
CASH FLOW DUE TO FINANCING ACTIVITIES
Advances on borrowings 75,509 85,000
Payments on debt (106,035) (55,036)
Proceeds from sale of 5.00% Senior
Convertible Notes 125,000 --
Proceeds from sale of common stock 898 65,347
Dividends paid on Series B preferred
stock (2,313) (2,313)
Fees paid related to financing
activities (4,749) (2,832)
----------------- -----------
Net cash provided by financing
activities 88,310 90,166
----------------- -----------
NET DECREASE IN CASH 6,955 (1,646)
CASH AND CASH EQUIVALENTS AT BEGINNING
OF PERIOD 5,907 6,716
----------------- -----------
CASH AND CASH EQUIVALENTS AT END OF
PERIOD $ 12,862 $ 5,070
================= ===========
SUPPLEMENTAL CASH FLOW DISCLOSURE
CASH PAID DURING THE PERIOD FOR:
INTEREST $ 2,914 $ 6,307
TAXES $ 35 $ --
(1) Adjusted for retrospective application of FSP APB 14-1 "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)
(In thousands)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ---------------------
2008 2009 2008 2009
---------- ---------- ---------- ----------
(as (as
adjusted) adjusted)
(2) (2)
Net Income (Loss) $ 12,059 $ (8,164) $ 18,306 $(132,598)
Non cash charges:
Depreciation, depletion,
and amortization 7,713 6,837 14,456 16,553
Impairment and other
writedowns -- 2,789 -- 186,517
Deferred income taxes 5,174 8,069 8,391 (48,285)
Non cash compensation
expense 543 1,236 1,089 2,282
Other 2,203 2,362 3,335 3,027
Preferred stock dividends (1,157) (1,157) (2,313) (2,313)
---------- ---------- ---------- ----------
Non-GAAP discretionary cash
flow $ 26,535 $ 11,972 $ 43,264 $ 25,183
========== ========== ========== ==========
Reconciliation of GAAP "Net
cash provided by operating
activities" to Non-GAAP
"discretionary cash flow"
Net cash provided by
operating activities $ 30,688 $ 12,735 $ 39,553 $ 20,578
Adjustments:
Changes in operating assets
and liabilities (2,996) 394 6,024 6,918
Preferred stock dividends (1,157) (1,157) (2,313) (2,313)
---------- ---------- ---------- ----------
Non-GAAP discretionary cash
flow $ 26,535 $ 11,972 $ 43,264 $ 25,183
========== ========== ========== ==========
(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.
(2) Adjusted for retrospective application of FSP APB 14-1 "Accounting
for Convertible Debt Instruments That May Be Settled in Cash upon
Conversion"