OKLAHOMA CITY, Aug. 8, 2012 (GLOBE NEWSWIRE) -- GMX RESOURCES INC., (NYSE:GMXR) (the "Company" or "GMXR"), reports today on the financial and operating results for the second quarter ended June 30, 2012.
Company Highlights for the Three and Six Months Ended June 30, 2012
Record Oil Production
- In the second quarter of 2012, the Company achieved an average oil production of 705 barrels/day (Bbls/d). For the month of June 2012, oil production was 720 Bbls/d, representing a 111% increase over the 2012 first quarter average.
- Total production for the second quarter 2012 was 536,000 barrels of oil equivalent (Boe), which includes 64,115 Bbls of oil and 50,000 Bbls of NGLs. Oil production for the second quarter 2012 represents a 164% increase over second quarter 2011, and NGL production in the second quarter 2012 represents a 43% decrease over the second quarter of 2011. During the second quarter 2012 we continued to see limitations in third party NGL capacity and infrastructure, and elected to sell a portion of our unprocessed gas in the Carthage Texas area for a total price that was a premium to the local index and was greater than the combined estimated price of residue gas and the net processing upgrade on the gas that was processed. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the hydrocarbons for the Company.
- Natural gas production for the three months ended June 30, 2012 decreased to 2.5 billion cubic feet (Bcf) compared to 5.9 Bcf for the three months ended June 30, 2011, a decrease of 57%. Including the VPP volumes of 1.0 Bcfe, natural gas production decreased by 2.4 Bcfe, or 41%. The decrease in natural gas production resulted primarily from the natural decline in the Company's Haynesville/Bossier (H/B) wells as a result of the Company's suspension of its H/B horizontal drilling program in mid-2011.
East Texas Liquids Rich Natural Gas Assets
- The Company engaged Global Hunter Securities on July 17, 2012 as the financial advisor in connection with a proposed sale of a portion of the Company's Cotton Valley Sand liquids rich natural gas properties located in East Texas. The Proved Developed and Producing wells are in the mature stage of production with shallow decline rates. The assets being sold have additional upside through infill horizontal development on acreage that is all held by production. The Company currently expects the sale of these properties to occur during the third quarter of 2012, with the proceeds to be used for our Bakken drilling program.
Bakken
- The Company spud its eighth operated well on July 2, 2012. The Basaraba 24-35-1H is located in Sections 26&35, Township 144N, Range 100W in Billings County, North Dakota. The Company has an 89% working interest in the Basaraba 24-35-1H which has a proposed total depth of 20,950' and a proposed total vertical depth of 11,221'. We are currently drilling in the lateral portion of the well and expect to reach total depth within the next few days.
- During the second quarter of 2012, the focus of our drilling program was on the area in McKenzie County that had been de-risked by GMXR and other operators. In the second quarter we had three operated and one non-operated well successfully completed and brought to sales. The Lange 11-30-1H, the Akovenko 24-34-1H and the Johnston 31-4-1H were operated wells that were completed as Middle Bakken wells, while the Pojorlie 21-2-1H was drilled and completed as a first bench Three Forks well by Continental Resources. The average peak 24-hour initial production rate for our operated wells in McKenzie County during the second quarter was 1,837 Boe per day (Boe/d).
- The Pojorlie 21-2-1H well, in which the Company has an approximate 34% working interest, located in Sections 2&11, Township 146N, Range 98W in McKenzie County, North Dakota, is a Three Forks target that was successfully drilled by Continental Resources to a measured depth of 21,210' with a lateral length of 9,597'. The average 30-day gross production from the well is 257 Boe/d. This well also included a core sample taken from the Middle Bakken through the Three Forks.
- The Company's seventh operated well, the Fairfield State 21-16-1H, is located in Sections 16&21, Township 143N, Range 99W in Billings County, North Dakota, and the Company has a 96% working interest in the well. The well experienced screen out four stages into the process, and the stimulation process was temporarily suspended. After evaluating available options, the Company will now finish out completion of this well using plug & perf on the balance of the lateral in order to bring the well to sales.
Niobrara DJ Basin Update
- The Company has received the initial processing of the seismic program covering 172 square miles of its ongoing 226 square mile program in the Chugwater area. With the addition of the previous seismic project (North Mustang area), owned jointly by the Company, Devon and Chesapeake, the Company now has over 300 square miles of high quality 3D seismic, across and proximal to approximately 40,000 leasehold acres, that confirms targets in the Niobrara Petroleum System. Joints and fractures will be essential elements of the Niobrara Petroleum System. Additional targets are also being evaluated in the Pennsylvanian-Permian sections. Previous scientific studies confirm that thermal maturity and geological settings are present for oil saturated reservoirs and the 3D seismic indicates the existence of multiple pay zones. Significant drilling opportunities appear to be present on the Company's acreage.
Financial
- Net loss applicable to common shareholders was $106.1 million, or $1.52 per basic and fully diluted share, and $146.7 million, or $2.23 per basic and fully diluted share, for the three and six months ended June 30, 2012, respectively.
- As detailed below, non-GAAP adjusted net loss applicable to common shareholders(1) was $12.7 million, or $0.18 per basic and fully diluted share, and $24.7 million, or $0.38 per basic and fully diluted share, for the three and six months ended June 30, 2012, respectively.
- Impairment expenses were $91.7 million and $120.7 million for the three and six months ended June 30, 2012, respectively, compared to $16.9 million and $65.2 million for the three and six months ended June 30, 2011, respectively.
- Lease operating expenses were $2.9 million and $6.0 million for the three and six months ended June 30, 2012, respectively, compared to $2.8 million and $5.7 million for the three and six months ended June 30, 2011, respectively.
- General and administrative expenses were $6.8 million and $13.8 million for the three and six months ended June 30, 2012, respectively, compared to $7.6 million and $14.7 million for the three and six months ended June 30, 2011, respectively.
- Adjusted EBITDA(1) was $6.0 million and $13.0 million for the three and six months ended June 30, 2012, respectively, compared to $21.3 million and $40.4 million for the three and six months ended June 30, 2011, respectively.
- Discretionary cash flow (1) was $(5.7) million and $(13.9) million for the three and six months ended June 30, 2012, respectfully, compared to $13.7 million and $25.5 million and for the three and six months ended June 30, 2011, respectively.
- The 2012 capital expenditure plan is estimated to be approximately $100 million (including capitalized interest expense and G&A), which will fund our Bakken oil focused drilling and development plans. As of June 30, 2012, we have made $51.6 million of these planned capital expenditures.
- The Company's outstanding principal balance of its 5.00% Senior Convertible Notes due 2013 ("2013 Convertible Notes") at year-end 2011 was $72.8 million. The Company completed a total of six separately negotiated debt-for-equity exchange transactions with holders of the 2013 Convertible Notes during the six months ended June 30, 2012. The debt-for-equity transactions have resulted in the issuance of 11,271,510 shares of common stock and have reduced the principal amount of the 2013 Convertible Notes by $20.8 million, leaving an outstanding principal balance of $52.0 million as of July 1, 2012.
(1) Adjusted net loss available to common shareholders, adjusted EBITDA and discretionary cash flow are non-GAAP measures that are further described and reconciled below in this press release.
Management Comments
James A. Merrill, Chief Financial Officer said "The Company is continuing to make progress on the transition to an oil focused producer outlined in January 2011 when we announced the acquisition of our Bakken and Niobrara positions. We forecasted that 2012 was going to be financially challenging as we worked to grow our oil production which would lead to higher revenues to cover interest and operating costs. During the last 18 months, we have focused on the incremental steps necessary to achieve our goals particularly related to a disciplined and Bakken focused capital expenditure plan, reducing overall G & A expenses by at least 20% and keeping lease operating expenses flat to slightly declining in 2012 despite the higher overall lease operating expenses associated with oil wells. I am pleased to report that our current and expected 2012 capital expenditures are in-line with our $97 million capex budget announced earlier in the year and G&A expenses have decreased in the first half of 2012 and we expect to see greater savings in the second half of the year. We did not forecast the unprecedented pricing pressure that we have had to incorporate into our business plan and as a result we have been forced to account for larger than expected impairments. The Company continues to pro-actively address the need for even better drilling results, more liquidity and debt reduction through a variety of means."
Michael J. Rohleder, President said "We have focused on four very important goals during the first half of 2012. First, to demonstrate that our Bakken development program can deliver the production and economic benefits to successfully transition GMXR to be a more balanced oil and natural gas producing company; second, create the necessary liquidity to continue to fund our drilling programs; third, resolve the Senior Convertible Notes due in February of 2013; and fourth, continue to evaluate and define the upside opportunity of our Niobrara position.
Our most recent results in McKenzie County, North Dakota, the doubling of our oil production from the first quarter to the second quarter 2012, and the oil production growth of 107% in the first six months of 2012 compared to the first six months of 2011 are all big steps in the transformation of GMX Resources.
Our decision to monetize a portion of our East Texas liquids rich assets will generate additional liquidity and fund our oil focused drilling programs into 2013. This sale process was launched in early July and is being managed by Global Hunter Securities. Our expectation is a late third quarter close.
We have made progress on reducing the face value of the 2013 note by doing debt-for-equity exchanges at discounts to par. We used slightly more than 11 million shares to retire almost $21 million of debt. That implies a trade value of about $1.85 per share. The remaining outstanding balance of $52 million in notes will continue to be in focus until a final resolution is achieved ahead of the maturity date.
Finally our Niobrara position of over 40,000 acres with almost 600 locations is an exciting upside opportunity for the company. We have received the majority of our seismic information - over 300 square miles and our engineering team is in the midst of an evaluation that is highlighting the presence of joint and fracture networks needed to make this play work for us. In addition, we are now able to identify specific targets not only in the Niobrara but other potentially productive zones."
Second Quarter 2012 Conference Call Dial in Specifics
The Company has scheduled a conference call for Thursday, August 9, 2012 at 8:00 a.m. CDT (9:00 a.m. EDT) to discuss second quarter 2012 financial and operating results. To access the call, domestic participants should dial (877) 303-9132 and international participants should dial (408) 337-0136 prior to the conference call start time. Please reference conference code 14088282. A telephonic replay of the call will be available after 11:00 a.m. EDT on August 9, 2012 through August 15, 2012 and can be accessed using the following number and pass code. Toll free: (855) 859-2056 or (800) 585-8367 using pass code 14088282. A presentation pertaining to this call will be available on the Company's website prior to the start of the call at www.gmxresources.com
Participants are encouraged to access the live audio webcast of the conference call through the following web link or by accessing the webcast through the Company's website.
Financial Results for the Three and Six Months Ended June 30, 2012
The Company reported a net loss applicable to common shareholders of $106.1 million, ($1.52 per basic and fully diluted share), and $146.7 million, ($2.23 per basic and fully diluted share), for the three and six months ended June 30, 2012, respectively, compared to a net loss applicable to common shareholders of $15.4 million ($0.28 per basic and fully diluted share) and $69.8 million ($1.43 per basic and fully diluted share) for the three and six months ended June 30, 2011, respectively.
Adjusted net loss applicable to common shareholders, a non-GAAP measure adjusting for items set forth below, was $12.7 million and $24.7 million, or $0.18 and $0.38 per basic and fully diluted share, for the three and six months ended June 30, 2012, respectively. Adjusted net loss is provided as a supplemental financial measure, and we believe it provides additional information regarding our operating financial performance.
Adjusted net loss is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income applicable to common shareholders, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.
| Three Months Ended | Six Months Ended | |||
| June 30, 2012 | June 30, 2012 | |||
| Amount | Per Share(1) | Amount | Per Share(1) | |
| (in thousands, except for per share amounts) | ||||
| GAAP net loss applicable to common shareholders | $(106,131) | $(1.52) | $(146,731) | $(2.23) |
| Adjustments: | ||||
| Deferred income tax provision | 1,418 | 0.02 | 3,305 | 0.05 |
| Impairment of oil and natural gas properties and assets held for sale | 91,690 | 1.31 | 120,690 | 1.83 |
| Unrealized gain on changes in fair value of hedges | 11 | — | (779) | (0.01) |
| Non-cash interest expense (2) | 1,171 | 0.02 | 2,399 | 0.04 |
| Gain on extinguishment of debt | (831) | (0.01) | (3,612) | (0.05) |
| Adjusted net loss applicable to common shareholders | $(12,672) | $(0.18) | $(24,728) | $(0.38) |
| (1) Due to the adjusted net loss applicable to common shareholders for the three and six months ended June 30, 2012, per share amounts are calculated using the basic weighted average number of shares that excludes items that would be antidilutive. Basic weighted average common shares outstanding for the three and six months ended June 30, 2012 was 69,925,895 and 65,832,321, respectively. | ||||
| (2) Non-cash interest expense is related to additional interest expense recognized for recent accounting pronouncements applicable to our convertible bonds and our share lending agreement. | ||||
The following table summarizes certain key operating and financial results for the three and six months ended June 30, 2012 compared to the three and six months ended June 30, 2011.
Summary Operating Data
| Three Months Ended | Six Months Ended | |||
| June 30, | June 30, | |||
| 2012 (1) | 2011 | 2012 (1) | 2011 | |
| Production: | ||||
| Oil (MBbls) | 64 | 24 | 95 | 46 |
| Natural gas (MMcf) | 2,534 | 5,852 | 5,051 | 11,367 |
| Natural gas liquids (MBbls) | 50 | 88 | 195 | 153 |
| Gas equivalent production (MMcfe) | 3,217 | 6,524 | 6,793 | 12,563 |
| Natural gas VPP volumes (MMcf) | 1,005 | — | 2,188 | — |
| Gas equivalent production including VPP volumes (MMcfe) | 4,222 | 6,524 | 8,981 | 12,563 |
| Average daily production excluding VPP volumes (MMcfe) | 35.3 | 71.7 | 37.3 | 69.4 |
| Average daily production including VPP volumes (MMcfe) | 46.4 | 71.7 | 49.3 | 69.4 |
| Average Sales Price: | ||||
| Oil (per Bbl) | ||||
| Wellhead price | $86.29 | $100.04 | $88.80 | $96.41 |
| Effect of hedges, excluding gain or loss from ineffectiveness of derivatives | 3.81 | (1.79) | 2.57 | (0.95) |
| Total | $90.10 | $98.25 | $91.37 | $95.46 |
| Natural gas liquids (per Bbl) | ||||
| Sales price | $32.84 | $40.04 | $34.39 | $38.17 |
| Effect of hedges, excluding gain or loss from ineffectiveness of derivatives | — | — | — | — |
| Total | $32.84 | $40.04 | $34.39 | $38.17 |
| Natural gas (per Mcf) | ||||
| Wellhead price | $1.66 | $3.87 | $1.64 | $3.77 |
| Effect of hedges, excluding gain or loss from ineffectiveness of derivatives | 1.85 | 0.68 | 1.98 | 0.74 |
| Total | $3.51 | $4.55 | $3.62 | $4.51 |
| Average sales price, excluding gain or loss from ineffectiveness of derivatives (per Mcfe) | $5.06 | $5.04 | $4.96 | $4.95 |
| Operating and Overhead Costs (per Mcfe): | ||||
| Lease operating expenses including VPP volumes | $0.68 | $0.43 | $0.67 | $0.46 |
| Effect of excluding VPP volumes on lease operating expenses | 0.22 | — | 0.21 | — |
| Lease operating expense excluding VPP volumes | $0.90 | $0.43 | $0.88 | $0.46 |
| Production and severance taxes including VPP volumes | $0.13 | $0.03 | $0.04 | $0.04 |
| Effect of excluding VPP volumes on production and severance taxes | 0.04 | — | 0.01 | — |
| Production and severance taxes excluding VPP volumes | $0.17 | $0.03 | $0.05 | $0.04 |
| General and administrative including VPP volumes | $1.61 | $1.17 | $1.54 | $1.17 |
| Effect of excluding VPP volumes on general and administrative | 0.50 | — | 0.49 | — |
| General and administrative excluding VPP volumes | $2.11 | $1.17 | $2.03 | $1.17 |
| Total cost including VPP volumes | $2.42 | $1.63 | $2.25 | $1.67 |
| Total cost excluding VPP Volumes | $3.18 | $1.63 | $2.96 | $1.67 |
| Other (per Mcfe): | ||||
| Depreciation, depletion and amortization—oil and natural gas properties (excluding VPP volumes) | $1.70 | $1.81 | $1.68 | $1.84 |
| (1) For 2012, the amounts presented are net of the Volumetric Production Payment ("VPP") volumes, with exception of "Operating and Overhead Costs (per Mcfe)," which are presented gross and net of the VPP volumes. | ||||
Results of Operations for the Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011
Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended June 30, 2012 decreased 50% to $16.3 million compared to $32.9 million in the second quarter of 2011. The decrease in oil and gas sales was primarily due to a 51% decrease in production on a Bcfe-basis of which 30% of the decrease was attributable to natural gas volumetric production payment ("VPP") volumes of 1.0 Bcfe that were sold in the form of a term overriding royalty interest in December 2011 and the remainder of the decrease was a result of the natural decline from the Company's Haynesville/Bossier ("H/B") production due to the suspension of the Company's H/B horizontal drilling program in mid-2011. The average price per barrel of oil, per barrel of natural gas liquids ("NGLs") and per thousand cubic feet (Mcf) of natural gas received (exclusive of ineffectiveness from derivatives) in the three months ended June 30, 2012 was $90.10, $32.84 and $3.51, respectively, compared to $98.25, $40.04 and $4.55, respectively, in the three months ended June 30, 2011. This represented a 8% decrease in oil prices, a 18% decrease in the average realized price in NGLs, and a 23% decrease in the average realized price of natural gas. Our realized sales price for natural gas, including revenue from NGLs and excluding the effect of hedges of $1.85 and $0.68, for the three months ended June 30, 2012 and 2011, respectively, was approximately 104% and 89% of the average NYMEX closing contract price for the respective periods. In the second quarter of 2012 and 2011, the conversion of natural gas to NGLs produced an upgrade of approximately $0.64 per Mcf and $0.42 per Mcf, respectively, for every Mcf of natural gas sold.
Natural gas production for the three months ended June 30, 2012 decreased to 2.5 Bcf compared to 5.9 Bcf for the three months ended June 30, 2011, a decrease of 57%. Including the VPP volumes of 1.0 Bcf, natural gas production decreased by 2.4 Bcf, or 41%. The decrease in natural gas production resulted primarily from the natural decline in the Company's H/B wells as a result of the suspension of the Company's H/B horizontal drilling program in mid-2011. The Company's last H/B well was completed and brought on line in August 2011.
Oil production for the three months ended June 30, 2012 increased 164% to approximately 64,100 Bbls, from approximately 24,300 Bbls for the three months ended June 30, 2011, as a result of the Company's new Bakken production. For the second quarter of 2012, the Company produced approximately 39,100 Bbls in the Bakken and approximately 25,000 Bbls in East Texas compared to the second quarter of 2011 when the Company only had East Texas oil production. Bakken and East Texas oil sales, excluding hedges, during the three months ended June 30, 2012 were $3.1 million and $2.4 million, respectively.
NGL production for the three months ended June 30, 2012 decreased to approximately 49,600 Bbls compared to approximately 87,600 Bbls for the three months ended June 30, 2011, a decrease of 43%. Due to the limitations in NGL infrastructure in the second quarter of 2012 and the resulting decrease in available processing capacity, the Company elected to sell a portion of our unprocessed gas in the Carthage Texas area for a total price that was greater than the combined estimated price of residue gas and the net processing upgrade. Since the NGLs can be left in or extracted from the gas stream, we will continue to make gas dispatch decisions based on maximizing the total sales value of the combined hydrocarbon stream.
For the three months ended June 30, 2012, as a result of hedging activities, excluding derivative ineffectiveness, we recognized an increase in oil and natural gas sales of $4.9 million compared to an increase in oil and natural gas sales of $3.9 million in the second quarter of 2011. In the second quarter of 2012, hedging, excluding ineffectiveness, increased the average natural gas sales price by $1.85 per Mcf compared to an increase in natural gas sales price of $0.68 per Mcf in the second quarter of 2011. The increase in oil and natural gas sales and sales price, as a result of hedging activities for the three months ended June 30, 2012, was mainly due to the amortization of $4.2 million in realized non-cash gain on our cash flow hedges that we monetized in the fourth quarter 2011. The remaining realized gain of $7.8 million in other comprehensive income will be amortized into earnings ratably through 2013. Our derivative contracts that have not been monetized on natural gas increased our natural gas sales by $0.5 million and $4.0 million for the three months ended June 30, 2012 and 2011, respectively. Our derivative contracts on oil increased our oil sales by $0.2 million and decreased our oil sales by $44,000 for the three months ended June 30, 2012 and 2011, respectively. The effect of our derivative contracts on oil increased the average oil sales price by $3.81 per Bbl for the three months ended June 30, 2012 and decreased it by $1.79 per Bbl for the three months ended June 30, 2011.
Lease Operations. Lease operations expense increased $0.1 million, or 2%, for the three months ended June 30, 2012, to $2.9 million, compared to $2.8 million for the three months ended June 30, 2011. Lease operations expense on a per thousand cubic feet equivalent (Mcfe) basis, excluding VPP volumes increased $0.47, or 109%, to $0.90 for the three months ended June 30, 2012 compared to $0.43 for the three months ended June 30, 2011. The increase in lease operating expenses in total and on a per Mcfe basis is due to higher lease operating expenses related to the Company's Bakken oil production and the impact of the volumetric production payment of $0.22 per Mcfe. For the three months ended June 30, 2012 and 2011, lease operations expense on a per Mcfe basis for East Texas and the Bakken was $0.82 and $2.35, respectively.
Production and Severance Taxes. Production and severance taxes increased 235% to $0.6 million in the three months ended June 30, 2012 compared to $0.2 million in the three months ended June 30, 2011. The increase in production and severance taxes is due to a higher amount of severance tax expense recorded in relation to the qualified reimbursements receivable, which offset severance tax expense, as compared the three months ended June 30, 2011.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $6.8 million, or 51%, to $6.5 million in the three months ended June 30, 2012 compared to $13.3 million for the three months ended June 30, 2011. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.70 per Mcfe in the three months ended June 30, 2012 compared to $1.81 per Mcfe in the three months ended June 30, 2011. This decrease in the rate per Mcfe is primarily due to the recent impairment charges recognized by the Company which has lowered the amount of oil and gas properties subject to amortization.
Impairment of oil and natural gas properties and assets held for sale. For the $91.7 million impairment charge recorded in the second quarter of 2012, $91.8 million was related to the impairment of oil and gas properties subject to the full cost ceiling test, which was offset by a gain of $0.1 million on the sale of assets held for sale. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges, and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Natural gas represented approximately 79% of the Company's total production for the three months ended June 30, 2012. During the second quarter of 2012, the 12-month average of the first day of the month natural gas price decreased 16% from $3.73 per million British thermal units (MMbtu) at March 31, 2012 to $3.15 per MMbtu at June 30, 2012, contributing to the impairment for the second quarter of 2012. Of the $91.8 million impairment of oil and gas properties, $62.8 million was related to the decrease in natural gas and oil prices and $27.9 million was related to continued infrastructure and operational constraints impacting proved producing reserves in the Bakken. The Company anticipates positive Bakken reserve revisions in the future.
General and Administrative Expense. General and administrative expense for the three months ended June 30, 2012 was $6.8 million, compared to $7.6 million for the three months ended June 30, 2011, a decrease of $0.8 million, or 11%, as a result of cost cutting measures implemented by the Company in early 2012. General and administrative expenses include $1.6 million and $1.2 million of non-cash compensation expense as of the three months ended June 30, 2012 and 2011, respectively. Non-cash compensation represented 24% and 16% of total general and administrative expenses, for the three months ended June 30, 2012 and 2011, 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.
Interest. Interest expense for the three months ended June 30, 2012 was $10.1 million compared to $7.8 million for the same period in 2011, an increase of $2.3 million or 29%. The increase in interest expense was primarily due to the Company's decision in 2012 to elect the PIK option ("PIK Election") on its $283.5 million of Senior Secured Notes due 2017 that allows for a 9% cash interest payment along with a 4% interest payment in the form of additional Senior Secured Notes resulting in an annual interest rate of 13%, as well as the increase in the amount of the outstanding debt between the periods as a result of the exchange offer completed in December 2011. As part of the exchange, certain parties purchased an additional $100 million of the Senior Secured Notes for a total issuance of $283.5 million of the new Senior Secured Notes due 2017. As a result of the PIK Election, the Company has accrued interest at a higher rate for the three months ended June 30, 2012, which amounted to $3.0 million for the three months ended June 30, 2012. For the three months ended June 30, 2011, only the $200 million of 11.375% Senior Notes due 2019 were outstanding.
For the three months ended June 30, 2012 and 2011, interest expense includes non-cash interest expense of $1.2 million and $1.4 million, respectively, related to the accounting for convertible bonds, our share lending agreement and deferred premiums on derivative instruments. Cash interest expense for the three months ended June 30, 2012 and 2011 was $8.0 million and $7.7 million, respectively, of which $3.0 million and $2.0 million, respectively, was capitalized to properties not subject to amortization on the consolidated balance sheets. The increase in cash interest expense of $0.3 million was mainly due to the Company's completion of an exchange offer in December 2011 for all but $2 million of the 11.375% Senior Notes due 2019 which resulted in the issuance of $283.5 million of new Senior Secured Notes due 2017.
Income Taxes. Income tax expense for the three months ended June 30, 2012 was $1.4 million as compared to $1.4 million in the same period in 2011. The income tax expense recognized in the three months ended June 30, 2012 and 2011, respectively, was a result of a change in the valuation allowance on net deferred tax assets caused by a change in deferred tax liabilities primarily related to 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 to non-controlling interest. Net income to non-controlling interest was $1.0 million for the three months ended June 30, 2012 compared to $1.7 million for the three months ended June 30, 2011. This decrease was due to lower natural gas production in East Texas.
Net Loss and Net Loss Per Share
Net Loss and Net Loss Per Share—Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011. For the three months ended June 30, 2012, we reported a net loss applicable to common shareholders of $106.1 million, and for the three months ended June 30, 2011 we reported a net loss applicable to common shareholders of $15.4 million. Net loss per basic and fully diluted share was $1.52 for the second quarter of 2012 compared to net loss per basic and fully diluted share of $0.28 for the second quarter of 2011.
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 oil and natural gas prices, we have historically entered into swaps, three-way collars and put spreads. We plan to continue to hedge oil and natural gas in the future to mitigate our commodity price risk.
As of June 30, 2012, we had cash, cash equivalents and short-term investments of $42.5 million, including $4.3 million in restricted cash and $6.0 million in short-term investments. Through the period ended June 30, 2012, we have funded our operating expenses and capital expenditures through operating cash flows and from capital raised in December of 2011, which included $100 million from a bond exchange of our 11.375% Senior Noted due 2019 for our new Senior Secured Notes due 2017, $49.7 million in connection with the VPP, and $18.5 million from the December 2011 monetization of the Company's then existing hedge portfolio.
We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry and market conditions and the availability of capital. In the first six months of 2012, our cash outlay for capital expenditures was $51.6 million. We anticipate funding approximately $100 million of cash capital expenditures in 2012 with cash on hand and asset sales or other potential capital market activities. In July 2012, we announced our intent to monetize a portion of our East Texas Cotton Valley Sand assets which would be used to fund our 2012 and 2013 capital expenditure budget. Our 2012 capital expenditure budget will focus on our Bakken development plans particularly in McKenzie and Billings Counties of North Dakota. In the Bakken, we are currently running one drilling rig. Based on available liquidity, we plan to add a second rig in the Bakken during the third or fourth quarter of 2012. In the Niobrara, we will continue to evaluate our seismic work and surrounding well results from other operators which may facilitate a partial sale or joint venture on our Niobrara acreage.
During the first half of 2012, we entered into separate exchange agreements with various holders of our 5.00% Convertible Notes. Pursuant to these agreements, as consideration for the surrender by the holders of $20,753,000 aggregate principal amount of the 5.00% Convertible Notes, we issued to the holders an aggregate of 11,271,510 shares of our common stock, par value $0.001 per share (the "Common Stock"), along with cash consideration relating to accrued and unpaid interest. These issuances of the Common Stock were effected pursuant to Section 3(a)(9) of the Securities Act of 1933. We continue to evaluate additional options for refinancing and repayment of these notes to address their maturity in February 2013.
In order to protect us against the financial impact of a decline in oil and natural gas prices, we have an active hedging program. In March 2012, we executed fixed price natural gas swaps against the NYMEX for the period of July 2012 through December 2013. For the last six months of 2012, we swapped 2.57 Bcf at $2.60 and for all of 2013 we swapped 4.24 Bcf at $3.50. In connection with these swaps, we also entered into a basis swap in which we locked in a natural gas price differential between the NYMEX and the Houston Ship Channel at $0.08. The combination of these trades effectively locks in a sales price to GMXR of $2.52 for 2.57 Bcf during the six nine months of 2012, and $3.42 for 4.24 Bcf during 2013. In May 2012, we added a $3.20-$2.50 natural gas costless collar for 0.58 Bcf of production over the last six months of 2012. In addition, we added a $3.68 swap with a $3.00 sold put to create an enhanced natural gas swap for approximately 1 Bcf of 2013 production.
In March 2012, we executed fixed price crude oil swaps against the NYMEX for July 2012 through December 2013. For the last six months of 2012, we swapped 24,907 barrels at $106.40 and for all of 2013 we created a $106.40-$65.50 put spread for 41,975 barrels. For 2014, we executed a costless three-way collar for 35,528 barrels with a ceiling of $114.10, a floor of $100 and a sold put of $80. We also bought $100-$90 put spreads for 19,421 barrels for the last six months of 2012, $100 puts for 26,654 barrels in 2013, and $95-$75 put spreads for 19,893 barrels in 2014. In May 2012, we swapped 30,360 barrels of crude oil at $96.50 for the last six months of 2012, executed a $90-$70 crude oil put spread for 38,325 barrels in 2013, and a $90-$70 crude oil put spread for 36,500 barrels in 2014.
Our strategy is to use swaps and costless collars to protect our flowing proved developed production, and use puts and put spreads to establish floors for our proved undeveloped production. Since the forward prices for oil are less than the current prices for oil, our structure allows us to preserve the optionality benefits of oil price increases. As we bring on new wells, we plan to increase our hedges to establish floors and protect revenues.
GMXR is a resource play rich E&P company. Oil shale resources are located in the Williston Basin, North Dakota & Montana targeting the Bakken Petroleum System and in the DJ Basin, Wyoming targeting the Niobrara Petroleum System; both plays are estimated 90% oil. Our natural gas resources are located in the East Texas Basin, in the Haynesville/Bossier gas shale and the Cotton Valley Sand Formation, where the majority of our acreage is contiguous, with infrastructure in place and substantially all held by production. We believe these oil and natural gas resource plays provide a substantial inventory of operated, high probability, repeatable, organic growth opportunities. The Company's multiple basin strategy provides flexibility to allocate capital to achieve the highest risk adjusted rate of return, with both oil and natural gas resources throughout our portfolio. Please visit www.gmxresources.com for more information on the Company.
The GMX RESOURCES INC. logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=5158
This press release includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. They include statements regarding the Company's financing plans and objectives, drilling plans and objectives, related exploration and development costs, number and location of planned wells, reserve estimates and values, statements regarding the quality of the Company's properties and potential reserve and production levels. These statements are based on certain assumptions and analysis made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes appropriate in the circumstances, including the assumption that there will be no material change in the operating environment for the Company's properties. Such statements are subject to a number of risks, including but not limited to commodity price risks, drilling and production risks, risks relating to the Company's ability to obtain financing for its planned activities, risks related to weather and unforeseen events, governmental regulatory risks and other risks, many of which are beyond the control of the Company. Reference is made to the Company's reports filed with the Securities and Exchange Commission for a more detailed disclosure of the risks. For all these reasons, actual results or developments may differ materially from those projected in the forward-looking statements.
| GMX Resources Inc. and Subsidiaries | ||
|
Consolidated Balance Sheets |
||
| June 30, 2012 | December 31, 2011 | |
| ASSETS | (Unaudited) | |
| CURRENT ASSETS: | (In thousands, except share data) | |
| Cash and cash equivalents | $32,122 | $102,493 |
| Restricted cash | 4,325 | 4,325 |
| Short-term investments | 6,008 | — |
| Accounts receivable – interest owners | 5,952 | 8,607 |
| Accounts receivable – oil and natural gas revenues, net | 4,705 | 7,082 |
| Derivative instruments | 1,929 | — |
| Inventories | 326 | 326 |
| Prepaid expenses and deposits | 1,583 | 2,655 |
| Assets held for sale | 410 | 2,045 |
| Total current assets | 57,360 | 127,533 |
| OIL AND NATURAL GAS PROPERTIES, BASED ON THE FULL COST METHOD | ||
| Properties being amortized | 1,105,167 | 1,062,801 |
| Properties not subject to amortization | 162,783 | 147,224 |
| Less accumulated depreciation, depletion, and impairment | (1,003,510) | (871,346) |
| 264,440 | 338,679 | |
| PROPERTY AND EQUIPMENT, AT COST, NET | 63,159 | 65,858 |
| DERIVATIVE INSTRUMENTS | 1,451 | — |
| OTHER ASSETS | 8,382 | 10,131 |
| TOTAL ASSETS | $394,792 | $542,201 |
| LIABILITIES AND EQUITY | ||
| CURRENT LIABILITIES: | ||
| Accounts payable | $11,582 | $13,550 |
| Accrued expenses | 15,911 | 17,835 |
| Accrued interest | 4,956 | 3,256 |
| Revenue distributions payable | 5,609 | 5,980 |
| Short-term derivative instruments | 1,141 | — |
| Current maturities of long-term debt | 51,256 | 26 |
| Total current liabilities | 90,455 | 40,647 |
| LONG-TERM DEBT, LESS CURRENT MATURITIES | 362,987 | 426,805 |
| DEFERRED PREMIUMS ON DERIVATIVE INSTRUMENTS | 608 | — |
| OTHER LIABILITIES | 8,415 | 7,476 |
| 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, 6,000,000 shares authorized, 3,176,734 shares issued and outstanding as of June 30, 2012 and December 31, 2011 (aggregate liquidation preference $79,418 as of June 30, 2012 and December 31, 2011) | 3 | 3 |
| Common stock, par value $.001 per share – 250,000,000 shares authorized, 74,451,790 shares issued and outstanding as of June 30, 2012 and 63,085,432 shares issued and outstanding as of December 31, 2011 | 74 | 63 |
| Additional paid-in capital | 709,829 | 690,986 |
| Accumulated deficit | (796,073) | (649,341) |
| Accumulated other comprehensive income, net of taxes | 7,764 | 14,029 |
| Total GMX Resources' equity | (78,403) | 55,740 |
| Noncontrolling interest | 10,730 | 11,533 |
| Total equity | (67,673) | 67,273 |
| TOTAL LIABILITIES AND EQUITY | $394,792 | $542,201 |
| GMX Resources Inc. and Subsidiaries | ||||
| Consolidated Statements of Operations | ||||
| (Unaudited) | ||||
| Three Months Ended | Six Months Ended | |||
| June 30, | June 30, | |||
| 2012 | 2011 | 2012 | 2011 | |
| (In thousands, except share and per share data) | ||||
| OIL AND GAS SALES | $16,283 | $32,858 | $33,684 | $62,235 |
| EXPENSES: | ||||
| Lease operations | 2,888 | 2,836 | 5,996 | 5,733 |
| Production and severance taxes | 556 | 166 | 319 | 549 |
| Depreciation, depletion, and amortization | 6,974 | 13,304 | 14,439 | 26,093 |
| Impairment of oil and natural gas properties and assets held for sale | 91,690 | 16,861 | 120,690 | 65,181 |
| General and administrative | 6,802 | 7,605 | 13,797 | 14,683 |
| Total expenses | 108,910 | 40,772 | 155,241 | 112,239 |
| Loss from operations | (92,627) | (7,914) | (121,557) | (50,004) |
| NON-OPERATING INCOME (EXPENSES): | ||||
| Interest expense | (10,122) | (7,832) | (20,825) | (15,854) |
| Gain (loss) on conversion/extinguishment of debt | 831 | (67) | 3,612 | (176) |
| Interest and other income | 35 | 12 | 108 | 282 |
| Unrealized gain (loss) on derivatives | (11) | 5,437 | 779 | 4,992 |
| Total non-operating expense | (9,267) | (2,450) | (16,326) | (10,756) |
| Loss before income taxes | (101,894) | (10,364) | (137,883) | (60,760) |
| INCOME TAX PROVISION | (1,418) | (1,436) | (3,305) | (2,868) |
| NET LOSS | (103,312) | (11,800) | (141,188) | (63,628) |
| Net income attributable to noncontrolling interest | 982 | 1,746 | 1,870 | 3,158 |
| NET LOSS APPLICABLE TO GMX RESOURCES | (104,294) | (13,546) | (143,058) | (66,786) |
| Preferred stock dividends | 1,837 | 1,837 | 3,673 | 3,047 |
| NET LOSS APPLICABLE TO COMMON SHAREHOLDERS | $(106,131) | $(15,383) | $(146,731) | $(69,833) |
| LOSS PER SHARE – Basic | $(1.52) | $(0.28) | $(2.23) | $(1.43) |
| LOSS PER SHARE – Diluted | $(1.52) | $(0.28) | $(2.23) | $(1.43) |
| WEIGHTED AVERAGE COMMON SHARES – Basic | 69,925,895 | 55,660,978 | 65,832,321 | 48,959,825 |
| WEIGHTED AVERAGE COMMON SHARES – Diluted | 69,925,895 | 55,660,978 | 65,832,321 | 48,959,825 |
| GMX Resources Inc. and Subsidiaries | ||
| Consolidated Statements of Cash Flows | ||
| (Unaudited) | ||
| Six Months Ended | ||
| June 30, | ||
| 2012 | 2011 | |
| CASH FLOWS DUE TO OPERATING ACTIVITIES | (In thousands) | |
| Net loss | $(141,188) | $(63,628) |
| Depreciation, depletion, and amortization | 14,439 | 26,093 |
| Impairment of oil and natural gas properties and assets held for sale | 120,690 | 65,181 |
| Deferred income taxes | 3,305 | 2,867 |
| Non-cash compensation expense | 2,292 | 2,155 |
| (Gain) loss on conversion/extinguishment of debt | (3,612) | 176 |
| Non-cash interest expense | 4,163 | 4,622 |
| Non-cash change in fair value of derivative financial instruments | (779) | (4,992) |
| Non-cash derivative gain in oil and gas sales | (9,493) | — |
| Other | (28) | (722) |
| Decrease (increase) in: | ||
| Accounts receivable | 4,856 | (634) |
| Inventory and prepaid expenses | 1,166 | (231) |
| Increase (decrease) in: | ||
| Accounts payable and accrued liabilities | (3,515) | 5,474 |
| Revenue distributions payable | (358) | 1,263 |
| Net cash (used in) provided by operating activities | (8,062) | 37,624 |
| CASH FLOWS DUE TO INVESTING ACTIVITIES | ||
| Purchase, exploration and development of oil and natural gas properties | (52,974) | (192,708) |
| Proceeds from sale of oil and natural gas properties, property, equipment and assets held for sale | 1,765 | 2,189 |
| Purchase of short term investments | (6,029) | — |
| Purchase of property and equipment | (418) | (1,739) |
| Net cash used in investing activities | (57,656) | (192,258) |
| CASH FLOWS DUE TO FINANCING ACTIVITIES | ||
| Borrowings on revolving bank credit facility | — | 26,000 |
| Repayments of long-term debt | (24) | (168,035) |
| Proceeds from issuance of long-term debt | — | 193,666 |
| Proceeds from sale of common stock | — | 105,324 |
| Proceeds from sale of preferred stock | — | 25,809 |
| Dividends paid on Series B preferred stock | (1,837) | (3,047) |
| Fees paid related to financing activities | (118) | (16,132) |
| Contributions from non-controlling interest member | — | 385 |
| Distributions to non-controlling interest member | (2,674) | (6,816) |
| Net cash (used in) provided by financing activities | (4,653) | 157,154 |
| NET (DECREASE) INCREASE IN CASH | (70,371) | 2,520 |
| CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 102,493 | 2,357 |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | $32,122 | $4,877 |
| SUPPLEMENTAL CASH FLOW DISCLOSURE | ||
| CASH PAID DURING THE PERIOD FOR: | ||
| INTEREST, Net of amounts capitalized | $11,531 | $3,336 |
| INCOME TAXES, Paid | $24 | $1 |
| NON-CASH INVESTING AND FINANCING ACTIVITIES | ||
| Debt extinguished with common stock | $20,753 | $— |
| Additions to oil and natural gas properties in exchange for common stock | $— | $31,612 |
| Decrease in accounts payable for property additions | $4,451 | $7,079 |
| Interest paid in the form of additional notes ("PIK Election") | $5,102 | $— |
| GMX Resources Inc. and Subsidiaries | ||||
| Non-GAAP Supplemental Information - Discretionary Cash Flows (1) | ||||
| (dollars in thousands) | ||||
| Three Months Ended | Six Months Ended | |||
| June 30, | June 30, | |||
| 2012 | 2011 | 2012 | 2011 | |
| Net loss | $(103,312) | $(11,800) | $(141,188) | $(63,628) |
| Non cash charges: | ||||
| Depreciation, depletion, and amortization | 6,974 | 13,304 | 14,439 | 26,093 |
| Impairment and other write-downs | 91,690 | 16,861 | 120,690 | 65,181 |
| Deferred income tax provision | 1,418 | 1,436 | 3,305 | 2,867 |
| Non-cash compensation expense | 1,459 | 996 | 2,292 | 2,155 |
| (Gain) loss on extinguishment of debt | (831) | 67 | (3,612) | 176 |
| Non-cash interest expense | 2,048 | 2,219 | 4,163 | 4,622 |
| Unrealized loss (gain) on changes in fair value of hedges | 11 | (5,437) | (779) | (4,992) |
| Non-cash derivative gains in oil and gas sales | (4,172) | — | (9,493) | — |
| Other | — | (314) | (28) | (722) |
| Net income attributable to noncontrolling interest | (982) | (1,746) | (1,870) | (3,158) |
| Preferred stock dividends | — | (1,837) | (1,837) | (3,047) |
| Non-GAAP discretionary cash flow | $(5,697) | $13,749 | $(13,918) | $25,547 |
| Net cash provided by operating activities | $(6,888) | $21,076 | $(8,062) | $37,624 |
| Adjustments: | ||||
| Changes in operating assets and liabilities | 2,173 | (3,744) | (2,149) | (5,872) |
| Net income attributable to noncontrolling interest | (982) | (1,746) | (1,870) | (3,158) |
| Preferred stock dividends | — | (1,837) | (1,837) | (3,047) |
| Non-GAAP discretionary cash flow | $(5,697) | $13,749 | $(13,918) | $25,547 |
(1) Discretionary cash flow represents cash provided by operating activities before changes in assets and liabilities less preferred dividends. Discretionary cash flow is presented because we believe it is a useful additional consideration along with net cash provided by operating activities under accounting principles generally accepted in the United States ("GAAP"). Discretionary cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash that is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors in the valuation, comparison and investment recommendations of companies within the natural gas and oil 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. The manner in which we calculate discretionary cash flow may differ from that utilized by other companies.
| GMX Resources Inc. and Subsidiaries | ||||
| Non-GAAP Reconciliations - Adjusted EBITDA (1) | ||||
| Three Months Ended | Six Months Ended | |||
| Reconciliation of GAAP "Net Income" | June 30, | June 30, | ||
| to Non-GAAP Adjusted EBITDA | 2012 | 2011 | 2012 | 2011 |
| (Dollars in Thousands) | ||||
| Net loss | $(103,312) | $(11,800) | $(141,188) | $(63,628) |
| Adjustments: | ||||
| Depreciation, depletion, and amortization | 6,974 | 13,304 | 14,439 | 26,093 |
| Certain non-cash income and adjustments for unrestricted subsidiaries | (399) | (1,490) | (1,309) | (2,592) |
| Distributions from unrestricted subsidiaries | 369 | 560 | 668 | 1,404 |
| Impairment and other write-downs | 91,690 | 16,861 | 120,690 | 65,181 |
| Deferred income tax provision | 1,418 | 1,436 | 3,305 | 2,868 |
| Interest expense | 10,122 | 7,832 | 20,825 | 15,854 |
| Change in fair value of hedges | 11 | (5,437) | (779) | (4,992) |
| Loss (gain) on extinguishment of debt | (831) | 67 | (3,612) | 176 |
| Adjusted EBITDA | $6,042 | $21,333 | $13,039 | $40,364 |
(1) Adjusted EBITDA represents earnings before interest, taxes, depletion, depreciation & amortization and includes non-cash compensation, hedging and derivative activities and other expenses. Adjusted EBITDA is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors in the valuation, comparison and investment recommendations of companies. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.