OKLAHOMA CITY, May 9, 2011 (GLOBE NEWSWIRE) -- GMX RESOURCES INC., (NYSE:GMXR), reports today on the financial and operating results for the first quarter ending March 31, 2011.
The Company has scheduled a conference call for Tuesday, May 10, 2011 at 8:00 a.m. CDT (9:00 a.m. EDT) to discuss the first quarter financial and operating results. To access the call, dial (877) 303-9132 or (408) 337-0136 prior to the conference call start time. Please reference conference code 58995312. A replay of the call will be available after 11:00 a.m. EDT on May 10, 2011 through May 24, 2011 and can be accessed using the following number and pass code. Toll free: (800) 642-1687 or (706) 645-9291. Replay conference code 58995312. In addition, a replay of the call will be archived on our Company website under investor relations / events and presentations. A presentation pertaining to this call will be available on the Company's website no later than 6:00 a.m. CDT, May 10, 2011.
Michael J. Rohleder, President said, "The first quarter of 2011 was transformational for GMXR with the announcement of our entry into oil resource plays in the Bakken and Niobrara and our subsequent capital markets transactions that were successfully completed in early February. We raised $105 million in an equity offering and entered the high yield market with a $200 million aggregate principal amount of senior notes. We used $50 million of the proceeds to tender for a portion of the 2013 convertible bonds outstanding, reducing that issue to $72.8 million. These capital market transactions allowed us to purchase significant positions in the top oil play in the U.S.(the Bakken) and in a top emerging oil play in the U.S. (the Niobrara), realign our balance sheet and move 80% of our debt past the maturity date of our bank revolver. We believe we have enough liquidity in place to fund our capital expenditures for the next two years, and we expect to be cash flow positive in early 2013. Transformation to more oil production is the key in our ability to accomplish that goal. We are focused on accelerating our operational start up in North Dakota organizing four GMXR-operated 1280 acre units in the Lewis and Clark play with a total of sixteen well locations. We have about a 50% average working interest in these units and expect to be drilling in late June or early July. We will commit more than half of our total capital expenditures in 2012 to the oil plays up from zero in 2010. Increasing the oil percentage of our production will have the obvious economic benefits driven by the huge value gap that exists between oil and natural gas and it will significantly change the NAV of the company. It is a game changer for the company and its shareholders."
"Specifically related to Q1 2011 performance, our production reached a record 6.0 BCFE for the quarter, up 13% from last quarter and 89% from the first quarter of 2010 but our realized natural gas prices declined 27% as compared to the first quarter of 2010 creating a negative impact on our earnings per share, cash flow per share, EBITDA and creating a non-cash impairment charge of approximately $48 million. LOE and G&A costs went down 51% and 48%, respectively, from the first quarter 2010 on a per unit basis and down slightly on an absolute dollar basis reflective of our continued emphasis on cost control and production improvement. We are accelerating our transition to oil production, but increasing well performance and decreasing costs in the Haynesville / Bossier play remains a fundamental part of our near term strategy. We drilled and completed four successful long lateral (~6,500') Haynesville/Bossier horizontal wells during the quarter. Haynesville/Bossier drilling and completion costs appear to have peaked in Q3 2010, and we are experiencing a slightly more competitive market in East Texas, especially with respect to completion services. We are well hedged in 2011 and 2012 with 70% of our expected production hedged at over $6.00. We are beginning to hedge gas production in 2013 and have already protected approximately 17% of our estimated natural gas production at $5.40 per Mmbtu."
Operational and Financial Highlights for the Three Months Ended March 31, 2011
- Net loss applicable to common shareholders was $(54.5 million) or $(1.29) per share for the three months ending March 31, 2011.
- As detailed below, non-GAAP adjusted net loss applicable to common shareholders per share (1) was $(0.07) for the three months March 31, 2011.
- Lease operating expenses were $0.48 per Mcfe for the three months ended March 31, 2011 compared to $0.97 per Mcfe for the first quarter in 2010 which is a $0.49 per Mcfe decrease.
- General and administrative expenses were $1.17 per Mcfe for the three months ended, March 31, 2011 compared to $2.25 per Mcfe for the first quarter in 2010.
- Adjusted EBITDA (1) of $19.0 million for the three months ended March 31, 2011, compared to $11.8 million for the first quarter 2010.
- Discretionary cash flow (1) of $11.8 million for the three months ended March 31, 2011, compared to $8.8 million for the first quarter 2010.
- Production for first quarter of 2011 was 6.0 Bcfe, a new Company record, up 13% and 89% respectively from the fourth and first quarters of 2010.
- Well costs for first quarter of 2011 averaged approximately $8.7 million, which was $.0.2 million less than the fourth quarter 2010 costs of $8.9 million.
- The Company completed a total of four H/B Hz wells during the first quarter of 2011 which is ahead of our expectations of bringing one new well to service per month in 2011.
- Successfully completed offerings for $200 million in senior notes, $105 million in common stock and the tendering for $50 million of the 2013 senior convertible notes.
- To date for 2011, the Company has closed on four purchase and sale agreements to acquire approximately 65,000 acres in the Bakken and Niobrara formations.
- The Company opened a regional office in Denver, Colorado and successfully recruited two experienced land operations managers to facilitate our expansion into the Bakken and Niobrara oil plays.
- The Company is the anchor order on a 200 square mile 3D seismic shoot by Ion Geophysical Corp. with the first phase covering our blocked up acreage in northern Laramie Co., Wyoming and the Company as agreed to participate in a 3D seismic shoot with Devon Energy in Goshen Co., Wyoming.
Financial Results for the Three Months Ended March 31, 2011
The Company reported a net loss applicable to common shareholders of $54.5 million ($1.29 per basic and fully diluted share) for the three months ended March 31, 2011, compared to a net income applicable to common shareholders of $3.8 million ($0.14 per basic and fully diluted share) for the first quarter in 2010.
Adjusted net income (loss) applicable to common shareholders, a non-GAAP measure adjusting for items set forth below, was $(3.0 million) or $(0.07) per basic and fully diluted share for the three months ended March 31, 2011, compared to $1.3 million or $0.05 per basic and fully diluted share for the first quarter of 2010. Adjusted net income (loss) is provided as a supplemental financial measure. We believe adjusted net income (loss) provides additional information regarding our operating financial performance.
Adjusted net income (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.
The following table summarizes certain key operating and financial results for the three months ended March 31, 2011 compared to the three months ended March 31, 2010.
Summary Operating Data
Results of Operations for the Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2010
Oil and Natural Gas Sales. Oil and natural gas sales during the three months ended March 31, 2011 increased 38% to $29.4 million compared to the first quarter of 2010. Ineffectiveness of derivative gains recognized in oil and gas sales of $0.4 million and $0.5 million for the three months ended March 31, 2011 and 2010, respectively, is the result of a difference in the fair value of our cash flow hedges and the fair value of the projected cash flows of a hypothetical derivative based on our expected sales point. The increase in oil and natural gas sales was due to an 89% increase in production on a Bcfe-basis and a 22% increase in oil prices, offset by a 27% decrease in the average realized price of natural gas and a 10% decrease in the average realized price in natural gas liquids ("NGLs"), excluding ineffectiveness of hedging activities. The average price per barrel of oil, per gallon of natural gas liquid and Mcf of natural gas received (exclusive of ineffectiveness from derivatives) in the three months ended March 31, 2011 was $92.34, $0.85 and $3.67, respectively, compared to $75.47, $0.94 and $4.69, respectively, in the three months ended March 31, 2010. Our realized sales price for natural gas, including the effect of hedges of $0.80 and $1.45, for the three months ended March 31, 2011 and 2010, respectively, was approximately 109% and 117% of the average NYMEX closing contract price for the respective periods. In the first quarter of 2011 and 2010, the conversion of natural gas to NGLs produced an upgrade of approximately $0.25 per Mcf and $0.90 per Mcf, respectively, for every Mcf of natural gas produced. This upgrade in value was previously included in the realized price of our natural gas sales.
Production of oil for the three months ended March 31, 2011, was consistent with the three months ended March 31, 2010 at 22 MBbls. During the first quarter of 2011, we began to separate and report the production and revenue from our NGLs, compared to prior periods in which we had included the production and revenues in our natural gas production and sales amounts. NGLs production for the three months ended March 31, 2011 decreased to 2,515 Mgals compared to 4,018 Mgals for the three months ended March 31, 2010, a decrease of 37%. This decrease was due to a decline in production in our non-Haynesville production, which have a higher NGL content versus our Haynesville/Bossier ("H/B") horizontal wells. Natural gas production for the three months ended March 31, 2011 increased to 5,551 MMcf compared to 2,492 MMcf for the three months ended March 31, 2010, an increase of 123%. The increase in natural gas production resulted from production related to 34.1 net producing H/B horizontal wells that were on-line during the first quarter of 2011 compared to 14.9 net producing H/B horizontal wells online during the first quarter of 2010. During the first quarter of 2011, we brought on-line four H/B horizontal wells and production from H/B horizontal wells accounted for 76% of total production for the three months ended March 31, 2011 compared to 47% in the same period in 2010.
For the three months ended March 31, 2011, as a result of hedging activities but excluding derivative ineffectiveness, we recognized an increase in natural gas sales of $4.4 million compared to an increase in natural gas sales of $3.6 million in the first quarter of 2010. In the first quarter of 2011, hedging, excluding ineffectiveness, increased the average natural gas sales price by $0.80 per Mcf compared to an increase in natural gas sales price of $1.45 per Mcf in the first quarter of 2010. The Company did not recognize any oil related hedging activities in oil and natural gas liquid sales in the three months ended March 31, 2011 and 2010.
Lease Operations. Lease operations expense decreased $0.2 million, or 7%, for the three months ended March 31, 2011 to $2.9 million, compared to $3.1 million for the three months ended March 31, 2010. Lease operations expense on an equivalent unit of production basis decreased $0.49 per Mcfe in the three months ended March 31, 2011 to $0.48 per Mcfe, compared to $0.97 per Mcfe for the three months ended March 31, 2010. The decrease in lease operations expense on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented by us during 2010 which lowered overall lease operating expense. With little to no incremental increase in lease operations cost from a Cotton Valley vertical well, the significantly larger amount of production from a H/B horizontal well will result in lower per unit lease operations costs. The overall decrease in lease operations expense is primarily related to a decrease in the three months ended March 31, 2011 in well workovers and repairs of approximately $0.4 million compared to three months ended March 31, 2010.
Production and Severance Taxes. The State of Texas grants an exemption of severance taxes for wells that qualify as "high cost" wells. Certain wells, including all of our H/B wells, qualify for full severance tax relief for a period of ten years or recovery of 50% of the cost of drilling and completions, whichever is less. As a result, refunds for severance tax paid to the State of Texas on wells that qualify for reimbursement are recognized as accounts receivable and offset severance tax expense for the amount refundable. Production and severance taxes decreased 46% to $0.4 million in the three months ended March 31, 2011 compared to $0.7 million in the three months ended March 31, 2010.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $6.4 million, or 100%, to $12.8 million in the three months ended March 31, 2011 compared to $6.4 million for the three months ended March 31, 2010. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.87 per Mcfe in the three months ended March 31, 2011 compared to $1.63 per Mcfe in the three months ended March 31, 2010. This increase in the rate per Mcfe is due to the percentage increase in oil and gas properties subject to amortization exceeding the percentage growth in reserves for the three months ended March 31, 2011.
Impairment of oil and natural gas properties and assets held for sale. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. 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. Any excess of the net book value is generally written off as an expense. Due to natural gas representing 92% of the Company's total production, a decrease in natural gas prices can significantly impact the Company's ceiling test. During the first quarter of 2011, the 12-month average of the first day of the month natural gas price decreased 6% from $4.38 per Mmbtu at December 31, 2010 to $4.10 per MMbtu at March 31, 2011. As a result of the Company's ceiling test as of March 31, 2011 and 2010, the Company recorded impairment expense of $48.1 million and $0, respectively.
For the impairment charge recorded in the first quarter of 2011, $14.5 million of the $48.1 million charge was related to the acquisition cost of East Texas and North Louisiana undeveloped acreage outside the primary development area being subject to the full cost method ceiling test and was based on the Company's decision during the first quarter of 2011 not to develop the acreage totaling 9,750 net acres before the expiration of the related leases in 2011. The Company's decision not to develop the acreage was based on analysis completed in the first quarter of 2011 after looking at off-set wells, anticipated future gas prices, infrastructure costs, the Company's liquidity position and focus on exploration and development of the newly acquired acreage in Bakken and Niobrara areas. Previously disclosed potential undrilled locations associated with our primary development Haynesville/Bossier acreage has excluded consideration of this acreage and therefore does not have an impact on our undrilled location opportunities to continue the Company's growth in our primary Haynesville/Bossier production. Additionally, there are no proved reserves recorded by the Company associated with these acres. We have determined the cost of these undeveloped leases should be transferred to properties being amortized and subject to our full cost ceiling test for the three months ended March 31, 2011.
Our East Texas primary development area is located in central and eastern Harrison and Panola counties that is near acreage actively being drilled by other operators and has approximately 257 undrilled Haynesville/Bossier locations. As of March 31, 2011, we had 32,700 derisked/proved net acres in the Company's primary development area represented by 18,137 net operated acres held by production, 6,337 net acres of non-operated acreage held by production and 8,226 net acres of undeveloped acreage. 14,041 net acres (not included in the March 31,2011 total) are expiring in 2011 represented by 3,406 acres in our primary development area, 9,750 acres outside our primary development area and 885 acres of non-operated acreage. Beyond 2011, we have 88 net acres expiring in 2012 and 10 net acres expiring in 2013. Based on our current drilling program, we expect to develop the acreage scheduled to expire in 2012 and beyond and therefore has been excluded from our full cost ceiling test.
General and Administrative Expense. General and administrative expense for the three months ended March 31, 2011 was $7.1 million compared to $7.2 million for the three months ended March 31, 2010, a decrease of $0.1 million or 2%. General and administrative expense per equivalent unit of production was $1.17 per Mcfe for the first quarter of 2011 compared to $2.25 per Mcfe for the comparable period in 2010. In the first quarter of 2010, the Company incurred approximately $1.5 million in severance costs of which $0.9 million or 62% was non-cash expense. Adjusting for severance costs incurred in the first quarter of 2010, general and administrative costs would have increased by $1.4 million from the first quarter of 2010 compared to 2011. The adjusted general and administrative expense per equivalent unit of production was $1.77 per Mcfe. The severance costs paid to terminated employees in the first quarter of 2010 were mostly offset by an increase in employee expenses related to the hiring of additional staff. General and administrative expenses include $1.2 million and $2.4 million of non-cash compensation expense as of the three months ended March 31, 2011 and 2010, respectively. Non-cash compensation represented 17% and 26% of total general and administrative expenses, excluding severance costs for the three months ended March 31, 2011 and 2010, 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. We expect general and administrative expenses on a per Mcfe basis to decrease as production increases, excluding any non-cash compensation expense from stock based compensation plans.
Interest. Interest expense for the three months ended March 31, 2011 was $8.0 million compared to $4.2 million for the same period in 2010. For the three months ended March 31, 2011 and 2010, interest expense includes non-cash interest expense of $2.4 million and $2.2 million, respectively. As a result of the accounting for convertible bonds, Share Lending Agreement and deferred premiums on derivative instruments, our non-cash interest expense related to these financial instruments was $1.5 million and $1.8 million for the three months ended March 31, 2011 and 2010, respectively. Cash interest expense for the three months ended March 31, 2011 and 2010 was $5.6 million and $2.0 million, respectively. The increase in cash interest expense of $3.6 million was mainly due to the $200 million of 11.375% senior notes issued in February 2011.
Income Taxes. Income tax for the three months ended March 31, 2011 was an expense of $1.4 million as compared to a benefit of $5.8 million in the same period in 2010. The income tax expense and benefit recognized in the three months ended March 31, 2011 and 2010, 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 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 to noncontrolling interest: Net income to noncontrolling interest increased to $1.4 million for the three months ended March 31, 2011 compared to $0.3 million for the three months ended March 31, 2010. The increase is due to an increase in the gathering fees earned by our majority-owned subsidiary in which the outside noncontrolling interest member is currently allocated 80% of the distributions. The gathering fees earned by the subsidiary increased as a result of an increase in production from the H/B horizontal wells that were completed and brought online.
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 natural gas prices, we have entered into natural gas swaps, three-way collars and put spreads.
As of March 31, 2011, we had cash and cash equivalents of $77.6 million and working capital of $78.3 million. Through the period ended March 31, 2011, we have funded our operating expenses and capital expenditures through positive operating cash flows, as well as from $105.3 million raised from the issuance of 22,173,518 common shares in February 2011, $6.9 million raised from the issuance of 300,638 shares of our 9.25% Series B Cumulative Preferred Stock and $193.7 million, net of original issue discount, from the issuance of our 11.375% senior notes due 2019. The outstanding balance of our bank credit facility at the time of the offerings of $110 million was fully repaid, and we completed a $50 million tender offer for a portion of our 5.00% convertible senior notes due 2013. The remaining proceeds from the offerings will be used to fund the Niobrara and Bakken acreage acquisitions and future capital expenditures.
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 three months of 2011, our capital expenditures were $73.9 million, net of additions to oil and gas properties from issuance of common stock for the Bakken and Niobrara acreage acquisitions, of which $69.3 million was primarily used for drilling and completing H/B horizontal wells, Niobrara and Bakken acreage acquisitions, land related activities and infrastructure. Cash expenditures related to the purchase price of the previously announced Niobrara and Bakken acreage acquisitions totaled $29.7 million for the first quarter of 2011.
In order to protect us against the financial impact of a decline in natural gas prices, we have an active, rolling three-year hedging program. As of March 31, 2011, we have natural gas hedges in place of 11.5 Bcf for our remaining estimated natural gas production for 2011 at an average hedge floor price of $6.12 per Mcf. In addition, we have 16.7 Bcf and 1.1 Bcf of natural gas hedged in 2012 and 2013, respectively, at average hedge prices of $6.08 and $5.25 per Mcf. As of March 31, 2011, we have also sold put options that would reduce the average hedge floor price if the monthly natural gas contract settlement price is below $4.17 for 2011, $4.13 for 2012 and $3.75 for 2013. If the monthly natural gas contract settlement is below the average sold put price, we will receive the monthly natural gas contract settlement price plus $1.95 in 2011, $1.95 in 2012, and $1.50 in 2013. In May 2011, we added a NYMEX natural gas swap at $5.45 for 10,000/Mmbtu per day for 2013.
The Company completed four new long lateral Haynesville/Bossier Hz wells during the first quarter of 2011 and now has 35 H/B Hz wells producing. The four new wells brought on line in the first quarter of 2011 had had an average lateral length of 6,112 feet, 15.25 stages and an average completed well cost of $8.7 million. The average cost per lateral foot for the four wells during the first quarter was $1,422 as compared to $1,706 per lateral foot in the fourth quarter of 2010.
The Bell #6H with a lateral length of 6,141 feet is the latest H/B Hz well to come online having a 30 day running daily average of 7,486 Mcf/d. The Bell #6H, while slightly shorter in length than our target length (6,460'), demonstrates continued improvement in well performance and is in line with expectations we have for our H/B Hz long lateral program. The Company previously announced that the Bosh Heisman #17H had a 30 and 60 day running daily average of 7,144 and 6,886 Mcf/d and today we report that the 90 day average is 6,427 Mcf/d. The Company's first long lateral well, the Mia Austin #6H, continues to perform as expected with a 150 day average of 5,916 Mcf/d.
The Company announced on our year-end 2010 update call planned tests to evaluate the zones below the Haynesville in response to reports indicating that an offset operator had produced oil from area reported to be below the Haynesville. In 2006, the Company drilled or caused to be drilled 19 vertical test wells through the Smackover (below the Haynesville). The only oil-bearing formation known to produce below the Smackover in east Texas is the Norphlet, which historically, resides at the top of the Lou Ann Salt. Only three of the deep tests were drilled to the salt; however, open-hole logs could not survey the full interval. These wells were subsequently completed as Cotton Valley Sands vertical wells. The Company has identified some of these wells that would suitable for re-entry. We have begun that process and anticipate having an update on the results during second or third quarter of 2011.
The Company has closed on all purchase and sales agreements announced on January 28, 2011 with the exception of 1,629 net acres in Williams County North Dakota. This letter of intent and proposed purchase and sales agreement relating to the acquisition of 87.5% working interest and 80% net revenue interest in approximately 1,629 net acres in Williams County, North Dakota has been terminated by the Company due to title failure. The purchase price for these properties was expected to be approximately $7.3 million. The Company will continue to look opportunistically to acquire additional acreage in these prospect areas in the normal course of business.
In the Bakken, the Company expects to spud its first Bakken Three Forks well in Township 140 North, Range 98 West in northern Stark Co as early as late June or early July. The Company plans to create four 1280-acre spaced units with the potential of 16 well locations. The working interests in these units average 50%. The net revenue in these is 80 percent. Additionally, the Company is spacing two, 1280-acre units in McKenzie County. The company will also participate in three wells operated by experienced operators in the area. The average working interest in these wells will be 7%, with an average net revenue of 81.25 percent.
In the Niobrara, the Company has signed an agreement to participate in a 3D seismic shoot initiated by Devon Energy. The area of 3D seismic will cover the majority of the Company's leases in Goshen Co., Wyoming. In addition, the Company has signed an agreement with Ion Geophysical Corporation to begin shooting 3D seismic in southeast Platte Co. and north central Laramie Co. Wyoming. In all, the Company will acquire 690 square miles of 3D seismic data to aid in the proper evaluation and exploitation of its Niobrara properties. Moving to a full scale development in our Niobrara position will require a thorough understanding of the structural geometry of the Niobrara, orientation and magnitude of faults as well as the orientation of fracture sets relative to local and regional stresses. Once we have completed our modeling and mapping, the Company plans to drill up to three vertical pilot wells, core and analyze the entire Niobrara interval, and then complete the vertical pilots as our first horizontal wells in the Niobrara.
The Company is no longer subject to an option held by seller of 30,452 acres in the Niobrara to buy back 15,226 acres at a cost equal to the purchase price. As a result, the Company has all right, title, and interest in the 30,452 acre leasehold estate and an 80% net revenue interest. The Company is preparing to solicit a 25% joint venture partner based on current market rates.
The Company announced during the first quarter that we have hired Land Operations Managers for both the Bakken and Niobrara and to support these key additions to the Company and we have opened a regional office in Denver Colorado to facilitate the development of the newly acquired leases.
The Company's second quarter and full year 2011 guidance is 6.1 Bcfe and a range of 25-26 Bcfe, respectively, which represents an increase of 42% and 43-49% from the second quarter and full year 2010.
GMXR is a resource play rich E&P company with development acreage in two oil shale resources in the Williston Basin (North Dakota / Montana) targeting the Bakken & Sanish-Three Forks and the DJ Basin (Wyoming), targeting the Niobrara Formation; both plays are 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 and held by production. These oil and natural gas resources provide a robust inventory of operated, high probability, repeatable, organic growth opportunities for our company's growth. The Bakken properties contain 34 potential operated units (1,280 acre) and 136 operated locations (10,000 ft. laterals; est. 45-55% working interest), giving the Company an estimated seven-year inventory using a two-rig development program. The Niobrara properties contain 133 potential operated units (640 acre) and 532 operated locations (5,000 ft. laterals; est. 45% working interest), giving the Company a 5.5-year inventory using a two-rig development program. The Haynesville/Bossier and the Cotton Valley Sand locations include 257 net Haynesville/Bossier horizontal locations, and 100-250 net Cotton Valley Sand horizontal locations, representing an estimated 12 year inventory of development utilizing two continuous rigs. The Company believes multiple basins and both oil and natural gas resource choices will provide us flexibility to allocate capital to achieve the highest risk adjusted rate of return on our portfolio. Please visit for more information on the Company.
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 the completion of announced acquisitions, 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.
CONTACT: Alan Van Horn Manager, Investor Relations 405.254.5839