OKLAHOMA CITY, Jan. 28, 2011 (GLOBE NEWSWIRE) -- GMX RESOURCES INC. (NYSE:GMXR) today announced the Company has recently signed three additional purchase and sale agreements ("PSA") and one letter of intent ("LOI"). In combination with the PSA announced in the press release dated January 20, 2011, we now have signed four PSAs and one LOI with private companies for a total of approximately 67,724 net acres of horizontal oil resources within the core development areas of the Bakken / Sanish-Three Forks Formation in the Williston Basin (Bakken) and the Niobrara Formation in the Denver Julesburg (DJ) Basin. The 67,724 net acres is comprised of approximately 26,087 net acres in the Williston Basin, North Dakota and Montana targeting the Bakken / Sanish–Three Forks Formation and approximately 41,637 acres in the DJ Basin in Wyoming targeting the Niobrara Formation. The Company previously announced an acquisition of Bakken/Sanish-Three Forks acreage for approximately $1.8 million in cash and up to 2,669,513 shares of stock, which is included within this announcement. Capital One Southcoast served as financial advisor to the Company on the transactions. The Company expects to close these transactions in February and March, 2011.
Ken L. Kenworthy Jr., Chief Executive Officer, said, "These combined transactions are transformational for GMXR, providing us with 342 additional horizontal drilling locations in the most actively developed oil resource play in the USA and one of the most promising emerging oil resource plays. These acquisitions now reposition GMXR into three significant Basins with two oil resource developments and two natural gas resource developments which include the largest natural gas resource basin in the U.S. The Company will now manage its capital allocation to the highest risk-adjusted rate of return for either oil or natural gas across over 700 net horizontal locations in these three resource plays, a multi-year inventory using three FlexRig3™ rigs. We believe our horizontal Haynesville/Bossier experience, our knowledge from resource consortiums participations, data exchange relationships and our technical team's Rockies experience will be instrumental in the successful development of the Bakken and Niobrara horizontal resources. The Company plans to raise capital to fund the development of these new opportunities. Operationally, we currently plan to winterize two of our three available FlexRig3™ rigs, and run one rig each in the Bakken and Niobrara while maintaining our one-rig program in the Haynesville/Bossier development. We also plan to participate in and/or initiate our own 3D seismic shoot, join consortiums and create data sharing relationships with other operators. The Company has hired local consultants in the area to help execute its plans, and as we expand our developments, we intend to establish GMXR field offices in the areas."
Bakken/Sanish-Three Forks - Williston Basin
GMXR's 26,087 total net acre leasehold for these acquisitions is primarily in five distinct areas, all of which are within the Bakken 'thermal maturity window'. The consideration to be paid by us for the three Bakken transactions includes the issuance of shares of the Company's common stock. Two of the transactions, totaling 8,290 net acres (including 1,629 acres under the LOI), reflect an average purchase price of $4,665 per acre, with approximately 67% paid in common stock to be priced based on the volume weighted average closing price for the 15 consecutive trading days prior to and including the third trading day prior to the closing date (expected in early March, 2011), with a minimum price of $5.50 and a maximum price of $6.50 per share (approximately 4,296,723 shares assuming a valuation of $6.00 per share, with a maximum of 4,687,773 shares issuable based on a $5.50 per share floor). The leases have a average of 82% net revenue interest and are fee (freehold), all taken within the past 12 months. The leases generally have three-year primary terms, and many of the fee leases have options to renew for two more years. The third transaction, previously announced January 20, 2011, totals 17,797 net acres for a purchase price of $1,000 per acre. Approximately 90% of the consideration will be paid in common stock (a total of up to 2,669,513 shares), based on a valuation of $6.00 per share, subject to certain adjustments at the option of the seller to take cash. The leases have a minimum 80% net revenue interest and are a mix of fee (freehold), state, and federal leases, all taken within the past 12 months. The leases generally have five to 10-year primary terms, and many of the fee leases have options to renew for five more years. The total acreage from the Bakken transactions represents the potential for 81.5 net wells using four wells per 1,280-acre spaced units.
The five distinct areas within the Bakken "thermal maturity" window for our acreage consist of:
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Southeast McKenzie County (approximately 5,959 acres), with both Middle Bakken ("MB") and Sanish Three Forks ("S3") targets ranging from 55' to 120' of thickness. The McKenzie County acreage position has 18.6 net long lateral locations on 4 wells per 1,280 acre density and is in the Elk Horn-Little Knife Trend to the west of the Nesson-Little Knife Anticlines and to the east-northeast of the Billings Anticline. It represents an area of south-southeast extension out of the Rough Rider-Greater Williston activity by other companies.
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Stark County / Dunn County, North Dakota (approximately 8,653 acres) offer a mix of MB & S3 Halo with 40' to 105' of thickness. Stark-Dunn position has 27 net long lateral locations with four wells per 1,280 acre density and is a further extension of the Elk Horn-Little Knife and Bailey Trends (or Heart River).
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Williams County North Dakota / Sheridan County, Montana (approximately 2,909 acres, including 1,629 acres under the LOI) represents 9.1 net long lateral locations with four wells per 1,280 acre density and are a northern extension of the Greater Williston or Rough Rider Trend that has seen extensive permitting ahead of recent success by other public companies. It is prospective for the Middle Bakken and Sanish-Three Forks intervals as lateral targets.
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Eastern Dunn County North Dakota (approximately 702 acres) offers locations prospective for MB & S3 with a thickness range of 90' to 135'. Dunn County positions have 2.1 net long lateral locations with four wells per 1,280 acre density and are a Middle Bakken extensional play from the Heart Butte Area. It should be positioned similar to the Parshall Field trapped against the barrier of thermally immature Bakken Shale.
- Richland / Wibaux Counties Montana (approximately 6,360 acres) are virtually all S3 Halo with 30' to 60' of thickness. The Richland / Wibaux Counties in Montana position has 19.9 net long lateral locations with four wells per 1,280 acre density that are virtually all within the Sanish-Three Forks halo with the thermally mature Upper Bakken sitting unconformably on the Sanish-Three Forks. GMXR views it as a northwestern extension of the Lewis & Clark play.
In addition, Southern Billings County, North Dakota (approximately 1,503 acres) offers S3 potential, with 4.7 net long lateral locations with 4 wells per 1,280 acre density that are prospective for the Sanish-Three Forks halo.
In addition to the cost of these acquisitions, the Company is budgeting capital expenditures in the Williston Basin to be $31.5 million in 2011 to establish a presence and begin our drilling program (of which we expect to pay $16.6 million in 2011 and $14.9 million in 2012). The Company plans to drill 10,000' laterals using one of our FlexRig3™ rigs beginning in the third quarter of 2011, and drilling continuously thereafter. Our initial acreage contains 81.5 net long lateral locations using four wells per 1,280 acre density. GMXR plans to continue leasing and has successfully recruited experienced Bakken land staff, brokerage, and title teams to augment its current land staff capacities and competencies.
Niobrara- DJ Basin
GMXR's entry into the Niobrara involves two transactions for approximately 41,637 net acres in southwestern Goshen, southeastern Platte and north central Laramie Counties in Wyoming, with a 80% net revenue interest. One of the sellers has retained a 90-day option to reacquire a 50% working interest in approximately 16,000 acres, at our initial cost. The fee leases generally have five-year primary terms, and many have options to extend the lease another five years. Approximately 20% of the total net acres are new federal leases with ten-year terms. The 41,637 net acres provides GMXR with a development potential of an estimated 260 net wells using four wells per 640 acre unit.
Following the acquisitions, the Company is budgeting 2011 capital expenditures in the DJ Basin of approximately $53.6 million to establish a presence and begin its drilling program (of which we expect to pay $29.5 million in 2011 and $24.1 million in 2012). GMXR plans to continue leasing and has successfully recruited experienced land staff, brokerage, and title teams for the DJ Basin to augment its current competencies. GMXR's operational plan is to deploy a third party rig in July 2011 to drill several vertical test wells down to 8,000' – 9,000' feet, to log and study the results, and when the sublease of one of our FlexRigs expires at the end of 2011, to have this rig winterized and then deploy it to drill 8,000' – 9,000' vertical and 5,000 - 10,000' laterals.
Reserve Estimates and Impairment Charges
The Company's Total Proved Reserves at December 31, 2010 are 319.3 BCFE, a decrease of approximately 10% from December 31, 2009 Total Proved Reserves of 355.3 BCFE. The Company previously announced on January 20, 2011 year-end Haynesville/Bossier reserves were 234.1 BCFE, an increase of 208.2 BCFE compared to year-end 2009; this was an increase of 804%. In addition the PV-10 value of the reserves at year-end 2010 was $151.9 million up from $32.8 million at year-end 2009.
The Company announces today its 2010 year-end Cotton Valley Sand, Travis Peak, and other non Haynesville/Bossier reserves are 85.2 BCFE, a decrease of 244.1 BCFE compared to year-end 2009 reserves of 329.4 BCFE. In order to comply with the SEC guidelines that require all E & P operators to report their reserves consistent with their next five-year capital expenditure and drilling plans, we removed all of our Cotton Valley Sand vertical well PUDs which totaled 219.6 BCFE of the decrease. Due to the Company's focus on developing the new acreage in the Bakken and Niobrara oil resource plays, and the prolific nature of the Haynesville/Bossier gas resource, we do not currently expect to reactivate a Cotton Valley Sand vertical drilling program within the next five years. Additionally, 6.7 BCFE of the decrease from year end 2009 was the 2010 production from the Cotton Valley Sand producing wells, and 17.9 BCFE decrease was an adjustment to the long term performance curves of the producing wells as well as other reporting and revision changes.
As a result of the decision to write off the entire Cotton Valley Sands PUD inventory, the Company expects to recognize a non-cash impairment charge in Q4 2010 of approximately $139 million covering both an estimated $130 million ceiling test adjustment and an estimated $9 million write-down in connection with the reclassification of certain assets to assets held for sale. In addition, the Company recognized approximately $1 million related to the estimated cost to sell these assets. The assets held for sale include three conventional drilling rigs, compressors designed for low pressure gathering service, large diameter pipeline pipe, and related valves and similar equipment that were all purchased prior to 2009 in connection with the then existing multi rig long term Cotton Valley Sand vertical drilling program focus.
James A. Merrill, CFO, said, "We have completed our reserve report work for the Cotton Valley Sand with MHA Petroleum Consultants and made a decision that writing off our PUD inventory was the most prudent approach even though they were marginally economic. Our intellectual and monetary capital will be targeted at the highest value opportunities that allow us to diversify our basin and commodity risks through the development of our new Bakken and Niobrara oil resource opportunities and our Haynesville/Bossier gas resource. We had a very large upgrade in our Haynesville/Bossier reserves from the DeGolyer and MacNaughton work. At year-end 2010 the Company has added 55.6 BCFE in Proved Developed reserves and 152.6 BCFE in Proved Undeveloped reserves in the Haynesville/Bossier up from 23.5 BCFE and 2.4 BCFE, respectively, last year. Our expectations are that the Cotton Valley Sands would be more economical as a horizontal development plan, however our immediate focus and attention is the development of the Bakken, the Niobrara, and the Haynesville/Bossier resources. The impairment charge is a non-cash charge and has no effect on our cash flow, EBITDA or non-GAAP earnings per share."
The following table summarizes GMXR's Proved Reserves as of December 31, 2010 for Haynesville/Bossier and Cotton Valley Sands + Others:
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SEC Pricing Proved Reserves – 2010 SEC Pricing(2) |
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| 2010 | 2009 | |||
| PV-10(1) | PV-10(1) | |||
| Proved Developed | BCFE | ($ in Millions) | BCFE | ($ in Millions) |
| Haynesville/Bossier | 79.1 | $ 128.4 | 23.5 | $ 31.7 |
| Cotton Valley Sands + Other | 85.2 | $ 98.0 | 109.8 | $ 114.2 |
| Total Proved Developed | 164.3 | $ 226.4 | 133.3 | $ 145.9 |
| Proved Undeveloped | ||||
| Haynesville/Bossier | 155.0 | $ 23.5 | 2.4 | $ 1.1 |
| Cotton Valley Sands +Other | 0.0 | $ 0.0 | 219.6 | $ 41.6 |
| Total Proved | 319.3 | $249.9 | 355.3 | $ 188.6 |
| (1) PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue before income tax of the Company's estimated proved reserves. The PV-10 value is different than the standardized measure of discounted estimated future net cash flows, which is calculated after income taxes. The Company believes the PV-10 is a useful measure for evaluating the relative monetary significance of their proved reserves. Investors may use the PV-10 as a basis for comparison of the relative size and value of the Company's reserves to its peers. | ||||
| (2) The proved reserves as of December 31, 2010 are calculated based on current SEC guidelines. The commodity prices used in the estimate were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price during the period from January 2010 through December 2010. For natural gas volumes, the average Henry Hub spot price of $4.38 per million British thermal units (MMBTU) was adjusted for energy content, transportation fees, regional price differences, and system shrinkage. For crude oil, the average West Texas Intermediate posted price of $79.43 per barrel was adjusted for quality, transportation fees, and regional price differentials. | ||||
The Haynesville/Bossier estimated proved reserves reported above are based on a report by the independent petroleum engineering consulting firm of DeGolyer and MacNaughton ("D&M"). The Company has maintained the services of MHA Petroleum Consultants for our Cotton Valley Sand and other non-Haynesville/Bossier reserves.
Liquidity and Financial Update
As of December 31, 2010, we had cash and cash equivalents of $2.4 million and $92 million drawn on our $130 million borrowing base, resulting in available liquidity of $40.4 million. For 2010, we have funded our operating expenses and capital expenditures through operating cash flows and draws on our revolving bank credit facility. Prior to 2010, we have historically generated cash through the same means, as well as financing from the issuance of debt, preferred stock and common stock.
As a result of additional completions in the fourth quarter of 2010, our production for the month of December was 2.1 BCFE. This increase in December's production reduced our estimated monthly per unit cost for lease operating expense and general and administrative expense (excluding $1.2 million non-recurring estimated selling costs described above). We expect our fourth quarter 2010 Adjusted EBITDA to be modestly higher than our third quarter 2010 results.
We continually review our drilling and capital expenditure plans, and we may change the amount we spend based on industry conditions and the availability of capital. In 2010, our capital expenditures were an estimated $195-200 million, substantially all of which was primarily used for drilling and completing Haynesville/Bossier Horizontal wells, Haynesville/Bossier acreage acquisitions, land related activities and infrastructure. We plan to continue operating one H&P FlexRig3™ rig in the Haynesville/Bossier gas resource play and expect to drill 10 wells and complete 12 wells in 2011. We are also exploring opportunities to joint venture with a non-operating partner to continue to develop our Haynesville/Bossier acreage.
Our previously announced 2011 capital expenditure budget for new wells was $110 million and based on a one-rig Haynesville/Bossier horizontal drilling program.
Including the acquisition costs for the Bakken and Niobrara acreage transactions, and payments for completion costs related to Haynesville/Bossier HZ wells drilled in 2010, cash that will be invested in capital expenditures in 2011 total $238.2 million and are allocated as follows:
| Acquisition of Bakken & Niobrara Acreage | $ 68.3 Million |
| New 2011 Haynesville/Bossier HZ Wells | $ 94.3 Million |
| New Bakken HZ Wells | $ 16.6 Million |
| New Niobrara Vertical & HZ Wells | $ 29.5 Million |
| Payment of Costs of 2010 H/B Wells | $ 29.5 Million |
| Total Capex | $ 238.2 Million |
The capital expenditures for the Bakken and Niobrara in 2011 are lower than the projected annual run rate due to the commencement of drilling in late Q3 of 2011. For 2012, we currently plan to make capital expenditures of approximately $222 million with allocations of 42% in the Haynesville/Bossier Shale, 26% in the Bakken Formation and 31% in the Niobrara Formation. While we have currently budgeted for these purposes, the ultimate amount of capital we expend may differ materially depending on the market conditions and the success of our drilling results during 2011.
In order to protect the Company against the financial impact of a decline in natural gas prices and to achieve the above drilling program, the Company has an active rolling three year hedging program. The Company has 14.9 TBtu and 16.7 TBtu of natural gas hedged in 2011 and 2012, respectively, at average hedge floor prices of $6.11 and $6.08 per MMBtu. The Company has also sold put options that would reduce the average hedge floor price if the monthly natural gas contract settlement price is below $4.27 for 2011 and $4.13 for 2012. If the monthly natural gas contract settlement is below the average sold put price, the Company will receive the monthly natural gas contract settlement price plus $1.84 in 2011, and $1.94 in 2012. The Company has not hedged any crude oil or natural gas production in 2013 but is currently considering adding additional hedges.
The following table summarizes the outstanding crude oil and natural gas derivative contracts we had in place as of December 31, 2010:
| Effective Date | Maturity Date |
Notional Amount Per Month |
Remaining Notional Amount as of December 31, 2010 |
Additional Put Options |
Floor | Ceiling |
| Natural Gas (MMBtu): | ||||||
| 1/1/2011 | 12/31/2012 | 155,337 | 3,728,100 | $ -- | $ 7.00 | |
| 1/1/2011 | 12/31/2011 | 188,781 | 2,265,372 | $ -- | $ 8.00 | |
| 1/1/2011 | 3/31/2011 | 200,000 | 600,000 | $ 5.00 | $ 7.00 | $ 7.25 |
| 1/1/2011 | 3/31/2011 | 200,000 | 600,000 | $ -- | $ 8.90 | |
| 4/1/2011 | 10/31/2011 | 200,000 | 1,400,000 | $ 5.00 | $ 6.50 | $ 8.30 |
| 11/1/2011 | 3/31/2012 | 200,000 | 1,000,000 | $ 5.50 | $ 7.00 | $ 10.10 |
| 1/1/2011 | 12/31/2012 | 1,021,666 | 24,520,000 | $ 4.00 | $ 6.00 | $ -- |
| 1/1/2011 | 12/31/2012 | 167,612 | 4,022,697 | $ 4.50 | $ 6.25 | $ -- |
| Crude Oil (Bbls): | ||||||
| 1/1/2011 | 12/31/2011 | 3,042 | 36,500 | $ -- | $ 100.00 |
2011 Production Guidance
We are forecasting that during the shift toward more oil focused drilling; we estimate full year 2011 production will be 25.0 - 26.0 BCFE, which is estimated to be 8% oil and natural gas liquids in Q1, then trending up to be 12% in Q4 of 2011, and averaging 9% for the full year of 2011.
When available, copies of the preliminary prospectus supplement and related prospectus may be obtained by contacting Morgan Stanley & Co. Incorporated, Attention: Prospectus Department, 180 Varick Street, New York, New York 10014, email: prospectus@morganstanley.com, or by calling 1-866-718-1649 or Credit Suisse Securities (USA) LLC, Attention: Prospectus Department, One Madison Avenue, New York, New York 10010, or by calling 1-800-221-1037. The Company's registration statement, preliminary prospectus supplement and prospectus are also available on the SEC website at www.sec.gov.
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.