Exhibit 99.1
GMXR
FOR IMMEDIATE RELEASE
FOR ADDITIONAL INFORMATION CONTACT
| | | | |
| Michael J. Rohleder | | James A. Merrill | | Harry C. Stahel, Jr. |
| President | | Chief Financial Officer | | Vice President – Finance |
| (405) 254-5838 | | (405) 254-5805 | | (405) 254-5802 |
GMXRAnnounces First Quarter 2010 Earnings and Operating Results:
Reduced Well Costs; 2010-2012 Guidance Increased
Oklahoma City, Oklahoma, Wednesday, May 5th 2010GMX RESOURCES INC., NYSE listed: ‘GMXR’; (visit www.gmxresources.com to view the most recent Company presentation and for more information on the Company)today announces financial and operating results for the first quarter ending March 31, 2010.
Financial Results for the Three Months Ending March 31, 2010
GMXR reported a net income applicable to common shareholders of $3.8 million for the three months ended March 31, 2010 as compared to 2009’s first quarter net loss applicable to common shareholders of $133.2 million. Diluted earnings per share for the three months ended March 31, 2010 was $0.14 per share compared to a diluted loss of $8.67 per share for the first quarter of 2009. Adjusted net income available to common shareholders for the three months ended March 31, 2010 a non-GAAP measure adjusting for such items as deferred tax valuation allowances, unrealized derivative gains and losses, non-cash interest expense and other one-time charges is broken out as follows:
| | | | | | | | |
| | | Quarter Ending March 31, 2010 | |
(in thousands, except for per share amounts) | | Amount | | | Per share(1) | |
| | |
Net income applicable to common shareholders | | $ | 3,815 | | | $ | 0.14 | |
Adjustments: | | | | | | | | |
Deferred income tax valuation allowance | | | (5,757 | ) | | | (0.20 | ) |
One time severance costs(2) | | | 1,525 | | | | 0.05 | |
Unrealized loss on derivative contracts | | | 221 | | | | 0.01 | |
Non-cash interest expense(3) | | | 1,537 | | | | 0.05 | |
| | | | | | | | |
Adjusted net income applicable to common shareholders | | $ | 1,341 | | | $ | 0.05 | |
| | | | | | | | |
| (1) | Per share amounts are calculated on a fully diluted basis. |
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| (2) | One time compensation costs were incurred due to the resignation of certain operation personnel in March 2010 and include approximately $0.6 million in cash costs and $0.9 million in non-cash compensation costs related to the acceleration of vesting for restricted stock and stock options. |
| (3) | Non-cash interest expense is comprised of the amortization of discounts related to our convertible notes, share lending agreements and deferred premiums on derivative instruments. |
The Company’s first quarter results continued to be positively impacted by production from the Haynesville/Bossier (“H/B”) horizontal (“Hz”) drilling. As of March 31, 2010, the Company had 15 gross/14.9 net producing H/B horizontal wells. Production from H/B Hz wells accounted for 50% of total production for the first quarter of 2010 compared to 10% for 2009. The Company’s average daily production for 1Q 2010 was 35.5 MMcfe per day compared to 39.1 MMcfe per day for 4Q 2009. The Company had anticipated completing two additional H/B horizontal wells during the first quarter of 2010 but the completion dates were delayed into the second quarter of 2010 by the service companies used to complete our wells. Natural gas production decreased to 3.066 Bcf for the first quarter of 2010 compared to 3.430 Bcf for the fourth quarter of 2009, a decrease of 11%. During the first quarter of 2010, the Company completed and brought on to production 2 H/B horizontal wells. Production of oil in the first quarter of 2010 decreased to 22 MBbls compared to 28 MBbls for the fourth quarter of 2009. Natural gas prices realized in the first quarter of 2010 averaged $6.40 per thousand cubic feet (“Mcf”) compared to $6.74 in fourth quarter of 2009. The impact of hedges on realized natural gas prices in the first quarter of 2010 was $1.35 per Mcf compared to $2.29 per Mcf in the fourth quarter of 2009. GMXR’s average realized oil prices in the first quarter of 2010 were $75.47 compared to $88.27 in the fourth quarter of 2009, which was increased by $13.82 for the impact of oil hedges. Oil and natural gas sales in the first quarter of 2010 were $21.3 million compared to $25.6 million in the fourth quarter of 2009.
2010 First Quarter Operational Update
As previously announced, the Company completed two Haynesville/Bossier horizontal wells (“H/B Hz”) in the first quarter. The Company successfully completed the Mia Austin #1H H/B Hz with a 14.1 million cubic feet of gas per day (“MMCF/D”) initial production (“IP”) rate. The well has a 4,600 foot lateral, with 12 frac stages and was flowing on a 20/64 choke with 5,492 pounds of Flowing Casing Pressure (“FCP”) into a sales line with 850 pounds of Line Pressure (“LP”). Additionally, the Company successfully completed the Verhalen E #1H with an 8.3 MMCF/D IP rate. This well has a 4,300 foot lateral, with 12 frac stages and was flowing on an 18/64 choke with 3,870 pounds FCP into a sales line with 640 pounds of LP. These wells were the last two using 4 1/2” casing. All future H/B Hz wells will use 5 1/2” casing.
Two additional wells were rescheduled from Q1 to early Q2 and have been successfully completed. The Bosh #19H H/B Hz was tested with a 10.1 MMCF/D IP rate. The well was drilled with a 4,153 foot lateral, and stimulated with 12 frac stages, however during the process of drilling out the plugs an obstruction prevented the last 6 of 12 frac stages from being accessed. After several attempts the Company made a decision to cease current efforts to drill out the remaining plugs and produce the well from approximately 6 of the 12 frac stages across 2,174 feet of the open lateral. The well test was over 24
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hours on a 14/64 choke with 4,526 pounds of FCP into a sales line with 590 pounds of LP. Also originally scheduled for Q1 and rescheduled to Q2 was the Verhalen D #3H H/B Hz which tested with an 11.1 MMCF/D IP rate. The well was drilled with a 4,900 foot lateral and stimulated with 11 frac stages. The well test was over 24 hours on a 22/64 choke with 5,200 pounds of FCP into a sales line with 627 pounds of LP.
Scheduled for completion in Q2 and previously announced was the Blocker Heirs #20H H/B Hz with a 14.4 MMCF/D IP rate. The well was drilled with a 4,450 foot lateral and stimulated with 11 frac stages. The well test was over 24 hours on a 20/64 choke with 5,890 pounds of FCP into a sales line with 975 pounds of LP. The Verhalen E #6H H/B Hz has also been completed in Q2 and had an IP rate of 11.1 MMCF/D. This well was drilled with a 4,500 foot lateral and stimulated with 10 frac stages. The well test was over 24 hours on a 20/64 choke with 5,283 pounds of FCP into a sales line with 635 pounds of LP.
Wells Costs
The Company has now completed a total of six H/B Hz wells YTD, with a seventh well, the Blocker-Ware # 8H scheduled to begin the frac process on May 7, 2010. The first six wells have averaged approximately $8.2 million in completed well cost (“CWC”) and the Company expects that CWC will decline over the next few months as a result of increased drilling efficiencies and cost engineering of the completion designs. The current cost estimates are slightly less than $8.0 million. The Company is budgeting $8.2 million for its average CWC in 2010.
Well Results
H/B Hz well results are continuing to improve. The switch to 5 1/2” casing has allowed the Company to continue to refine the completion designs allowing greater flexibility in the perforation schemes without material increases in stimulation costs. The modified completion design for the 5 1/2” cased wells resulted in IPs above 11 MMCF/D but more importantly, is the FCP for all of these wells is significantly higher than previously drilled H/B Hz wells within the same proximity. The Company expects that the production profiles on the most recent wells will support an increase in EUR’s up to the range of 5.3 to 6.5 Bcfe. Incoming production data available from other operators in the Harrison County area also corroborate the Company’s view of the EUR with a 5 1/2” cased well.
The Company has already drilled and successfully completed four H/B Hz wells in Q2 with a fifth well scheduled to begin the frac process on May 7, 2010. Two additional H/B Hz wells are scheduled to begin the frac process late June 2010.
Production Guidance
The Company met Q1 2010 production guidance with a total of 3.2 billion cubic feet of gas equivalent (“Bcfe”) produced during the quarter. This was down approximately 11% from the previous quarter (Q4 2009) due to the rescheduling into Q2 2010 of two of the forecasted four H/B Hz wells that were expected to be completed and producing in Q1 2010.
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Production guidance for Q2 is reaffirmed at an expected range of 4.2 to 4.4 Bcfe with the variable related to frac scheduling.
Due to the increased success in its H/B Hz results, the Company is increasing its production guidance for 2010 to range between 17.5 and 19.0 Bcfe, and for 2011 to range between 24.0 and 25.5 Bcfe, and for 2012 to range between 29.0 and 30.5 Bcfe. The current well results indicate the Company could even exceed these ranges but frac scheduling delays may cause production gaps that would prevent the higher levels of production.
Management Comment
Ken L. Kenworthy, Jr. Chairman and Chief Executive Officer said “Q1 was a great period in many respects but most importantly we achieved all of our previously announced objectives. We met our production guidance of 3.2 Bcfe, we transitioned our completion techniques and have five wells in a row that have more than 10 MMCF/D IP rates which is the performance we projected almost two years ago and our average completed well cost for the first six wells in 2010 is $8.2 million which is on the low end of our previous cost projections of $8 to $9 million. Our liquidity position is bolstered by an increase in production, our hedge position and our lower costs. We are increasing our production guidance for the next three years due to our confidence in the latest well results and we still believe that our planned drilling program will be funded by cash flow and bank debt – not the capital markets.”
GMXR First Quarter Earnings and Operational Update Conference
GMXR has scheduled a conference call for Thursday, May 6, 2010 at 10:00 a.m. CST (11:00 a.m. EST) to discuss first quarter 2010 financial and operating results. To access the call, dial 877-303-9132 or 408-337-0136 before the call begins. Please reference Pass code 69853690. A replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until May 16, 2010. To access the replay, please dial 800-642-1687 or 706-645-9291 and reference pass code 69853690. The corporate presentation being used for this call is available for download athttp://www.gmxresources.com under the Events and Presentation tab.
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GMXRSummary Financial Summary for the Three Months Ended March 31, 2010
| | | | | | | |
| | | Three Months Ended
March 31, |
| | | 2009 | | | 2010 |
Production: | | | | | | | |
Oil (MBbls) | | | 30 | | | | 22 |
| | |
Natural gas (MMcf) | | | 3,042 | | | | 3,066 |
Gas equivalent production (MMcfe) | | | 3,224 | | | | 3,199 |
Average daily (MMcfe) | | | 35.8 | | | | 35.5 |
| | |
Average Sales Price: | | | | | | | |
Oil (per Bbl) | | | | | | | |
Wellhead price | | $ | 36.27 | | | $ | 75.47 |
Effect of hedges | | | 24.25 | | | | — |
| | | | | | | |
Total | | $ | 60.52 | | | $ | 75.47 |
Natural gas (per Mcf) | | | | | | | |
Wellhead price | | $ | 4.11 | | | $ | 5.05 |
Effect of hedges | | | 2.79 | | | | 1.35 |
| | | | | | | |
Total | | $ | 6.90 | | | $ | 6.40 |
| | |
Average sales price (per Mcfe) | | $ | 7.08 | | | $ | 6.66 |
| | |
Operating and Overhead Costs (per Mcfe): | | | | | | | |
Lease operating expenses | | $ | 0.98 | | | $ | 0.97 |
Production and severance taxes | | | (0.51 | ) | | | 0.22 |
General and administrative | | | 1.38 | | | | 2.25 |
| | | | | | | |
Total | | $ | 1.85 | | | $ | 3.44 |
| | | | | | | |
Cash Operating Margin (per Mcfe) | | $ | 5.23 | | | $ | 3.22 |
| | | | | | | |
| | |
Other (per Mcfe): | | | | | | | |
Depreciation, depletion and amortization—oil and natural gas properties | | $ | 2.18 | | | $ | 1.63 |
Results of Operations—Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009
Oil and Natural Gas Sales.Oil and natural gas sales for the three months ended March 31, 2010 decreased 7% to $21.3 million compared to the first quarter of 2009. This decrease is primarily due to lower realized natural gas prices. The average prices per barrel of oil and mcf of natural gas received in the first quarter of 2010 were $75.47 and $6.40, respectively, compared to $60.52 and $6.90, respectively, for the first quarter of 2009. Production of oil in the first quarter of 2010 decreased to 22 MBbls compared to 30 MBbls for the first quarter of 2009. The decrease in oil production is due to the natural decline in the Company’s Cotton Valley Sands 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 increased to 3,066 MMcf for the first quarter of 2010 compared to 3,042 MMcf for the first quarter of 2009, an increase of less than 1%. During the first quarter of 2010, the Company completed and brought on to production 2 H/B Hz wells. The Company had anticipated completing
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two additional H/B Hz wells during the first quarter of 2010 but the completion dates were delayed into the second quarter of 2010 by the service companies used to complete our wells. As of March 31, 2010, the Company had 15 gross/14.9 net producing H/B horizontal wells. Production from H/B horizontal wells accounted for 50% of total production for the first quarter of 2010 compared to 10% for 2009.
For the first quarter of 2010, as a result of revenue protection activities, we recognized an increase in oil and natural gas sales of $4.1 million, compared to an increase in oil and natural gas sales of $9.2 million for the first quarter of 2009. For the first quarter of 2010, revenue protection activities increased the average natural gas sales price by $1.35 per Mcf compared to an increase in the average natural gas sales price of $2.79 per Mcf for the first quarter of 2009. The Company did not have any oil protected for the first quarter of 2010 but the revenue protection activities for oil production in the first quarter of 2009 increased the average oil sales price by $24.25 per Bbl during the quarter.
Lease Operations. Lease operations expense decreased $42,000 in the first quarter of 2010 to $3.1 million, a 1% decrease compared to the first quarter of 2009. Lease operations expense on an equivalent unit of production basis was $0.97 per Mcfe for the first three months of 2010 compared to $0.98 per Mcfe for the first three months of 2009. During the first three months of 2010, well workover costs increased by $135,000 to $314,000 compared to $179,000 during the first three months of 2009. During the first quarter of 2010, the Company incurred workover expenses on several Cotton Valley wells in order to increase their oil and natural gas production. In determining whether or not to workover a well, the Company reviews the economics and payback period related to the workover as well as the technical complexity of the proposed workover. Most workovers have a payback period of less than one year and are approved by executive management of the Company. In addition to an increase in workovers the Company also incurred approximately $310,000 of additional non-operated ad valorem tax expense during the first quarter of 2010. Before the additional expenses related to workover’s and non-operated ad valorem taxes, lease operating expenses on a per unit basis would have been $0.83 per Mcfe. It is anticipated that as additional production is added from H/B horizontal wells that lease operating expenses on an equivalent unit basis will continue to decrease and will be less than historically from the Company’s Cotton Valley wells. With little to no incremental increase in lease operating costs from a typical Cotton Valley Sands 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 were $0.7 million in the three months ended March 31, 2010 compared to income of $1.7 million in the three months ended March 31, 2009 as a result of severance tax refunds of approximately $2.0 million received in the first quarter of 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 continue to reduce our expense going forward as we receive exemptions on recently completed wells.
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General and Administrative Expense.General and administrative expense for the first quarter of 2010 was $7.2 million compared to $4.4 million for the first quarter of 2009, an increase of 62%. The Company incurred approximately $1.5 million in severance costs of which $0.9 million or 62% was a non-cash expense. Adjusting for the severance costs incurred in the first quarter of 2010, general and administrative expense per equivalent unit of production was $1.77 per Mcfe for the first quarter of 2010 compared to $1.38 per Mcfe for the comparable period in 2009. A significant portion of the Company’s general and administrative expense is related to non-cash compensation expense. In addition to the $0.9 million in non-cash compensation, mentioned above the Company incurred an additional $1.5 million in non-cash compensation costs during the first quarter of 2010 or 26% of general and administrative expenses excluding severance costs in the first quarter of 2010 compared to $1.0 million or 24% in the first quarter of 2009. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature. The Company expects general and administrative expenses on a per Mcfe basis to decrease as production increases.
Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense decreased $2.5 million to $6.4 million in the first quarter of 2010, down 28% from the first quarter of 2009. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.63 per Mcfe for the quarter ended March 31, 2010 compared to $2.18 per Mcfe in the first quarter of 2009. The depletion rate decrease was due to a lower cost basis in oil and gas properties subject to amortization due to previously recorded impairment charges during 2009 as a result of lower crude oil and natural gas prices. In addition, in the fourth quarter of 2009 in connection with the sale of a portion of our pipeline assets, we changed the estimated useful life of the pipeline assets from 10 to 20 years which reduced depreciation expense by approximately $0.7 million between the first quarter of 2010 and first quarter of 2009.
Impairment of oil and natural gas properties.As a result of lower oil and natural gas prices at March 31, 2009, which limited the amount of oil and gas properties that could be capitalized on the balance sheet under the SEC’s “ceiling” test, the Company recognized an impairment charge on oil and gas properties of $138.1 million in the first quarter of 2009. Due to an increase in the trailing twelve month average of the first-day-of-the-month oil and natural gas prices and the additional proved reserves added during the quarter from the Company’s drilling activities, the Company did not recognize an impairment charge during the first quarter of 2010. The Company may be required to recognize additional impairment charges or writedowns in future reporting periods if market prices for oil or natural gas continue to decline or remain at their depressed levels.
Interest.Interest expense for the first quarter of 2010 was $4.2 million compared to $4.1 million for the first quarter of 2009. For the three months ended March 31, 2010 and 2009, interest expense includes non-cash interest expense of $2.2 million and $1.3 million, respectively. As a result of the adoption of accounting guidance related to convertible bonds, share lending agreements and fair value, the Company’s non-cash interest expense related to these particular accounting standards was $1.5 million and $0.8 million for the three months ended March 31, 2010 and 2009, respectively. Cash interest expense for the three months ended March 31, 2010 and 2009 was $2.0 million and $2.8 million, respectively. The decrease in cash interest expense of $0.8 million is due to the lack of borrowing under the revolving credit agreement in the first quarter of 2010 compared to the first quarter of 2009.
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Income Taxes. Income tax for the first quarter of 2010 was a benefit of $5.8 million as compared to a benefit of $2.4 million in the first quarter of 2009. The income tax benefit recognized in the first quarter of 2009 and 2010 was a result of a reduction in the valuation allowance on net deferred tax assets caused by an increase in deferred tax liabilities primarily related to unrealized gains on derivative contracts designated as hedges where the mark to market change on the hedges, net of deferred taxes is recorded to other comprehensive income.
Net Income and Net Income Per Share
Net Income and Net Income Per Share—Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009. For the three months ended March 31, 2010 we reported net income applicable to common shareholders of $3.8 million and for the three months ended March 31, 2009, we reported a net loss applicable to common shareholders of $133.2 million. Net income per basic and fully diluted share was $0.14 for the first quarter of 2010 compared to net loss of $8.67 per basic and fully diluted share for the first quarter of 2009. Weighted average basic shares outstanding increased by 83% from 15,354,680 shares in the first quarter of 2009 to 28,097,699 shares in the first quarter of 2010.
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 reductions in gas prices, we have entered into natural gas swaps, three way 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. Our capital expenditure budget for 2010 is $175 million which will be used to drill and complete 22 H/B Hz wells during 2010. In the first quarter of 2010, our capital expenditures were $40.6 million of which $38.3 million was primarily for drilling and completing H/B Hz wells and $2.3 million was related to infrastructure. We may continue to revise our capital expenditure budget during 2010 depending on our ability to continue to sublease a contracted Helmerich & Payne FlexRig3™ that is currently on a six month sublease through the end of October 2010 and our ability to enter into additional joint operating agreements (“JOA”) with other operators that have adjoining acreage to jointly develop Haynesville leasehold rights. The Company recently executed a JOA with EXCO Operating Company, LP to jointly develop Haynesville/Bossier leasehold rights in the Scottsville area of Harrison County, Texas. The Company will operate the joint leasehold with an 84.3% working interest and EXCO will participate with a 15.7% working interest representing the pro rata shares of each company’s leasehold contribution under the JOA.
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In order to protect the Company’s revenues against the financial impact of such a decline in natural gas prices, the Company has an active rolling three year hedging program. The Company has 10.3 Bcf or 80% of its remaining estimated natural gas production hedged for 2010. In addition, the Company has 14.9 Bcf and 16.7 Bcf of natural gas hedged in 2011 and 2012, respectively, at an average hedge price of $6.14 and $6.08.
As of March 31, 2010, we had not drawn on our credit facility that has a borrowing base of $130 million. At this time, the lenders under the bank credit facility have not determined our new borrowing base. We expect to be notified of the new borrowing base in May 2010. Although we do not yet know the amount of our new borrowing base, based on preliminary indications from the Agent Bank on the credit facility, we do not expect a significant change in the bank borrowing base. As of March 31, 2010, we were in compliance with all financial covenants under our credit facility.
Non-GAAP Measures
Among non-GAAP measures, discretionary cash flow generated by the Company in the first quarter of 2010 was $8.8 million compared to $13.0 million in the first quarter of 2009. EBITDA, or earnings before interest, taxes, depreciation, depletion and amortization (including the impairment charge to oil and natural gas properties) was $12.1 million in the first quarter of 2010 compared to 2009’s first quarter EBITDA of $17.1 million.
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GMX Resources Inc. and Subsidiaries
Consolidated Balance Sheets
(dollars in thousands, except share data)
(unaudited)
| | | | | | | | |
| | | December 31,
2009 | | | March 31,
2010 | |
| | | (as adjusted) | | | | |
| ASSETS | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
Cash and cash equivalents | | $ | 35,554 | | | $ | 9,017 | |
Accounts receivable—interest owners | | | 1,233 | | | | 931 | |
Accounts receivable—oil and natural gas revenues, net | | | 9,340 | | | | 6,993 | |
Derivative instruments | | | 12,252 | | | | 20,901 | |
Inventories | | | 326 | | | | 326 | |
Prepaid expenses and deposits | | | 4,506 | | | | 5,090 | |
| | | | | | | | |
Total current assets | | | 63,211 | | | | 43,258 | |
| | | | | | | | |
OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD | | | | | | | | |
Properties being amortized | | | 756,412 | | | | 790,714 | |
Properties not subject to amortization | | | 39,789 | | | | 43,786 | |
Less accumulated depreciation, depletion, and impairment | | | (464,872 | ) | | | (470,093 | ) |
| | | | | | | | |
| | | 331,329 | | | | 364,407 | |
| | | | | | | | |
| | |
PROPERTY AND EQUIPMENT, AT COST, NET | | | 101,755 | | | | 103,024 | |
| | |
DERIVATIVE INSTRUMENTS | | | 17,292 | | | | 23,553 | |
| | |
OTHER ASSETS | | | 8,484 | | | | 7,439 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 522,071 | | | $ | 541,681 | |
| | | | | | | | |
| | |
| LIABILITIES AND EQUITY | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Accounts payable | | $ | 19,180 | | | $ | 22,700 | |
Accrued expenses | | | 12,907 | | | | 12,071 | |
Accrued interest | | | 3,361 | | | | 2,605 | |
Revenue distributions payable | | | 4,434 | | | | 5,884 | |
Current maturities of long-term debt | | | 48 | | | | 48 | |
| | | | | | | | |
Total current liabilities | | | 39,930 | | | | 43,308 | |
| | | | | | | | |
LONG-TERM DEBT, LESS CURRENT MATURITIES | | | 190,230 | | | | 191,389 | |
DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS | | | 16,299 | | | | 14,635 | |
OTHER LIABILITIES | | | 7,151 | | | | 7,151 | |
| | |
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—50,000,000 shares authorized, 31,214,968 shares issued and outstanding in 2009 and 30,787,947 shares issued and outstanding in 2010 | | | 31 | | | | 31 | |
Additional paid-in capital | | | 522,645 | | | | 525,694 | |
Accumulated deficit | | | (284,745 | ) | | | (280,930 | ) |
Accumulated other comprehensive income, net of taxes | | | 8,447 | | | | 18,062 | |
| | | | | | | | |
Total GMX Resources’ equity | | | 246,380 | | | | 262,859 | |
Noncontrolling interest | | | 22,081 | | | | 22,339 | |
| | | | | | | | |
Total equity | | | 268,461 | | | | 285,198 | |
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 522,071 | | | $ | 541,681 | |
| | | | | | | | |
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GMX Resources Inc. And Subsidiaries
Consolidated Statements of Operations
(dollars in thousands, except share and per share data)
(Unaudited)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2009 | | | 2010 | |
| | | (as adjusted) | | | | |
OIL AND GAS SALES | | $ | 22,826 | | | $ | 21,300 | |
| | |
EXPENSES: | | | | | | | | |
Lease operations | | | 3,153 | | | | 3,111 | |
Production and severance taxes | | | (1,660 | ) | | | 710 | |
Depreciation, depletion, and amortization | | | 8,860 | | | | 6,370 | |
Impairment of oil and natural gas properties | | | 138,078 | | | | — | |
General and administrative | | | 4,445 | | | | 7,187 | |
| | | | | | | | |
Total expenses | | | 152,876 | | | | 17,378 | |
| | | | | | | | |
Income (loss) from operations | | | (130,050 | ) | | | 3,922 | |
| | |
NON-OPERATING INCOME (EXPENSES): | | | | | | | | |
Interest expense | | | (4,056 | ) | | | (4,229 | ) |
Interest and other income | | | 19 | | | | 24 | |
Unrealized losses on derivatives | | | (343 | ) | | | (221 | ) |
| | | | | | | | |
Total non-operating expense | | | (4,380 | ) | | | (4,426 | ) |
Income (loss) before income taxes | | | (134,430 | ) | | | (504 | ) |
| | |
INCOME TAX BENEFIT | | | 2,428 | | | | 5,788 | |
| | | | | | | | |
| | |
NET INCOME (LOSS) | | | (132,002 | ) | | | 5,284 | |
Net income attributable to noncontrolling interest | | | — | | | | 313 | |
| | | | | | | | |
| | |
NET INCOME (LOSS) APPLICABLE TO GMX RESOURCES | | | (132,002 | ) | | | 4,971 | |
Preferred stock dividends | | | 1,156 | | | | 1,156 | |
| | | | | | | | |
| | |
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS | | $ | (133,158 | ) | | $ | 3,815 | |
| | | | | | | | |
EARNINGS (LOSS) PER SHARE – Basic | | $ | (8.67 | ) | | $ | 0.14 | |
| | | | | | | | |
EARNINGS (LOSS) PER SHARE – Diluted | | $ | (8.67 | ) | | $ | 0.14 | |
| | | | | | | | |
WEIGHTED AVERAGE COMMON SHARES – Basic | | | 15,354,680 | | | | 28,097,699 | |
| | | | | | | | |
WEIGHTED AVERAGE COMMON SHARES – Diluted | | | 15,354,680 | | | | 28,097,699 | |
| | | | | | | | |
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GMX Resources Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(dollars in thousands)
(Unaudited)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2009 | | | 2010 | |
| | | (as adjusted) | | | | |
CASH FLOWS DUE TO OPERATING ACTIVITIES | | | | | | | | |
Net income (loss) | | $ | (132,002 | ) | | $ | 5,284 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | |
Depreciation, depletion, and amortization | | | 8,860 | | | | 6,370 | |
Impairment of oil and natural gas properties | | | 138,078 | | | | — | |
Deferred income taxes | | | (2,428 | ) | | | (5,757 | ) |
Non-cash compensation expense | | | 1,046 | | | | 2,435 | |
Other | | | 650 | | | | 1,923 | |
Decrease (increase) in: | | | | | | | | |
Accounts receivable | | | 2,719 | | | | 2,649 | |
Inventory and prepaid expenses | | | 234 | | | | (398 | ) |
Increase (decrease) in: | | | | | | | | |
Accounts payable and accrued liabilities | | | (8,193 | ) | | | (2,646 | ) |
Revenue distributions payable and other liabilities | | | (1,121 | ) | | | 601 | |
| | | | | | | | |
Net cash provided by operating activities | | | 7,843 | | | | 10,461 | |
| | | | | | | | |
| | |
CASH FLOWS DUE TO INVESTING ACTIVITIES | | | | | | | | |
Purchase of oil and natural gas properties | | | (64,659 | ) | | | (32,730 | ) |
Purchase of property and equipment | | | (5,847 | ) | | | (3,026 | ) |
| | | | | | | | |
Net cash used in investing activities | | | (70,506 | ) | | | (35,756 | ) |
| | | | | | | | |
| | |
CASH FLOW DUE TO FINANCING ACTIVITIES | | | | | | | | |
Advances on revolving bank credit facility | | | 65,000 | | | | — | |
Payments on debt | | | (36 | ) | | | (31 | ) |
Dividends paid on Series B preferred stock | | | (1,156 | ) | | | (1,156 | ) |
Other | | | — | | | | (55 | ) |
| | | | | | | | |
Net cash provided by (used in) financing activities | | | 63,808 | | | | (1,242 | ) |
| | | | | | | | |
| | |
NET INCREASE (DECREASE) IN CASH | | | 1,145 | | | | (26,537 | ) |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | | | 6,716 | | | | 35,554 | |
| | | | | | | | |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | | $ | 7,861 | | | $ | 9,017 | |
| | | | | | | | |
SUPPLEMENTAL CASH FLOW DISCLOSURE | | | | | | | | |
CASH PAID DURING THE PERIOD FOR: | | | | | | | | |
INTEREST, Net of amounts capitalized | | $ | 4,479 | | | $ | 2,750 | |
INCOME TAXES | | $ | — | | | $ | 31 | |
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GMX Resources Inc. and Subsidiaries
Non-GAAP Supplemental Information - Consolidated Discretionary Cash Flows(1)
(dollars in thousands)
(Unaudited)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2009 | | | 2010 | |
Net income ( loss ) | | $ | (132,002 | ) | | $ | 5,284 | |
| | |
Non-cash charges: | | | | | | | | |
Depreciation, depletion, and amortization | | | 8,860 | | | | 6,370 | |
Impairment of oil and natural gas properties | | | 138,078 | | | | — | |
Deferred income taxes | | | (2,428 | ) | | | (5,757 | ) |
Non cash compensation expense | | | 1,046 | | | | 2,435 | |
Other | | | 650 | | | | 1,923 | |
| | |
Preferred stock dividends | | | (1,156 | ) | | | (1,156 | ) |
Net income attributable to noncontrolling interest | | | — | | | | (313 | ) |
| | | | | | | | |
| | |
Non-GAAP discretionary cash flow | | $ | 13,048 | | | $ | 8,786 | |
| | | | | | | | |
| | |
Reconciliation of GAAP “Net cash provided by operating activities” to Non-GAAP “discretionary cash flow” | | | | | | | | |
| | |
Net cash provided by operating activities | | $ | 7,843 | | | $ | 10,461 | |
| | |
Adjustments: | | | | | | | | |
Changes in operating assets and liabilities | | | 6,361 | | | | (206 | ) |
Preferred stock dividends | | | (1,156 | ) | | | (1,156 | ) |
Net income attributable to noncontrolling interest | | | — | | | | (313 | ) |
| | | | | | | | |
| | |
Non-GAAP discretionary cash flow | | $ | 13,048 | | | $ | 8,786 | |
| | | | | | | | |
| (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. |
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GMX Resources Inc.is a ‘Pure Play’, E & P Company with one of the most concentrated Haynesville/Bossier (H/B) Horizontal Shale Operations in East Texas. The Company has 355 Bcfe in proved reserves (YE2009), 94% of which are natural gas. The Company’s proved reserves are 81% operated and consist of 274 net “Capital Core” H/B Hz un-drilled locations; 18 gross /17.9 net H/B producers, and 324 gross / 186.9 net Cotton Valley Sand (“CVS”) producers; 1,382 net CVS acre un-drilled locations; and 47 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 athttp://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.
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