Whiting Petroleum Corporation Announces 2011 Year-End Reserves, Provides 2012 Production and Capital Spending Guidance, and Updates 2011 Guidance
Proved Reserves Up 13.2% to a Record 345.2 MMBOE at Yr. End 2011
2012 Capital Budget of $1.6 Billion
2012 Production Guidance of 28.0 MMBOE – 29.5 MMBOE
(13%-19% Increase over 2011)
2011 Production Totals a Record 24.8 MMBOE
Q4 2011 Production Averages 70,685 BOE/d
December 2011 Production Rises to a Record 73,240 BOE/d
DENVER—As of December 31, 2011, Whiting Petroleum Corporation’s (NYSE: WLL) estimated proved reserves totaled 345.2 million barrels of oil equivalent (MMBOE), an increase of 13.2% over year-end 2010 proved reserves of 304.9 MMBOE. Approximately 86% of our 2011 year-end reserves were classified as oil/natural gas liquids and 69% were classified as proved developed. The 40.3 MMBOE increase in proved reserves replaced 164% of the Company’s 2011 production of 24.8 MMBOE.
Whiting’s total reserves at December 31, 2011 were as follows:
|(1)||Refer to “Disclosure Regarding Reserves” later in this news release for information on proved, probable and possible reserves.|
|(2)||Independently engineered by Cawley, Gillespie & Associates, Inc.|
The Company’s estimated year-end 2011 proved reserves had a pre-tax PV10% value of $7.4 billion, of which approximately 97% came from properties located in Whiting’s Rocky Mountain, Permian Basin and Mid-Continent core areas. The following table summarizes Whiting’s estimated proved reserves as of December 31, 2011 by core area.
|Proved Reserves (1)|
|Oil / NGL||Gas||Total||Value(3)|
|(MMBbl)(2)||(Bcf)||(MMBOE)||% Oil(2)||(In MM)|
|(1)||Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the month NYMEX price for each month within the 12 months ended December 31, 2011, pursuant to SEC and FASB guidelines. The NYMEX prices used were $96.19/Bbl and $4.12/Mcf.|
|(2)||Oil includes natural gas liquids.|
|(3)||Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. As of December 31, 2011, our discounted future income taxes were $2,132.2 million and our standardized measure of after-tax discounted future net cash flows was $5,272.5 million. We believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our proved oil and natural gas reserves.|
2012 Capital Budget of $1,600 Million and Production Guidance of 28.0 MMBOE – 29.5 MMBOE
Whiting forecasts a capital budget of $1,600 million in 2012, which should approximate its 2012 estimated discretionary cash flow. Whiting expects to allocate $1,236 million of the 2012 capital budget to exploration and development activity, $136 million for land, and $228 million for facilities. Based on this level of capital spending, we forecast production of 28.0 MMBOE – 29.5 MMBOE for 2012, an increase of 13% – 19% over our 2011 production of 24.8 MMBOE.
Our 2012 capital budget is currently allocated among our major development areas as indicated in the table below:
|Total Northern Rockies||851||218||124||53%|
|Total Central Rockies||50||11||11||3%|
|Total Gulf Coast||0||0%|
|Exploration Expense (1)||56||3%|
|(1)||Comprised primarily of exploration salaries, lease delay rentals and seismic activities.|
|(2)||These multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis not a well basis.|
Outlook for Fourth Quarter and Full-Year 2011
We have adjusted our fourth quarter and 2011 production guidance to reflect later arrival dates in mid through late November of our increased number of service rigs. As noted in our third quarter 2011 financial and operating results news release on November 2, 2011, Whiting had 66 wells in the Sanish field area shut-in awaiting service work. We anticipated reducing this to 20 by December 31, 2011. Due to later service rig arrival dates in the fourth quarter, we reduced the number of shut-in wells to 44 as of December 31, 2011. Our production rate for December was 73,240 barrels of oil equivalent (BOE) per day.
As of January 31, 2012, we expect to have placed an additional 10 previously shut-in wells back on production. As we further reduce the remaining number of shut-in wells, we expect production to respond positively, consistent with our forecast for average 2012 full year production between 76,700 BOE – 80,500 BOE per day, an increase of 13% – 19% over the 2011 average of 67,890 BOE per day.
The following tables provide guidance for the fourth quarter and full-year 2011 and first quarter and full-year 2012 based on current forecasts, including Whiting’s full-year 2012 capital budget of $1,600 million.
|Lease operating expense per BOE||$||12.60 – $ 12.80||$||12.30 – $ 12.40|
|General and admin. expense per BOE||$||3.40 – $ 3.50||$||3.40 – $ 3.50|
|Interest expense per BOE||$||2.50 – $ 2.60||$||2.50 – $ 2.60|
|Depr., depletion and amort. per BOE||$||19.50 – $ 19.70||$||18.80 – $ 19.00|
|Prod. taxes (% of production revenue)||7.85% – 7.95%||7.45% – 7.55%|
|Oil price differentials to NYMEX per Bbl||$||9.10 – $ 9.20||$||10.10 – $ 10.30|
|Gas price premium to NYMEX per Mcf (1)||$||1.10 – $ 1.20||$||0.80 – $ 0.90|
|(1) Includes the effect of Whiting’s fixed-price gas contracts.|
|Estimated production (MMBOE)||6.60 – 6.80||28.00 – 29.50|
|Lease operating expense per BOE||$||13.00 – $ 13.30||$||13.10 – $ 13.50|
|General and admin. expense per BOE||$||3.70 – $ 3.90||$||3.70 – $ 3.90|
|Interest expense per BOE||$||2.55 – $ 2.75||$||2.50 – $ 2.70|
|Depr., depletion and amort. per BOE||$||20.00 – $ 20.50||$||20.50 – $ 20.90|
|Prod. taxes (% of production revenue)||7.8% – 8.0%||7.9% – 8.2%|
|Oil price differentials to NYMEX per Bbl||$||9.50 – $ 10.50||$||9.50 – $ 10.50|
|Gas price premium to NYMEX per Mcf (1)||$||0.70 – $ 1.00||$||0.70 – $ 1.00|
|(1) Includes the effect of Whiting’s fixed-price gas contracts.|
Whiting’s fourth quarter and full-year 2011 conference call is scheduled for 11:00 a.m. EST on February 23, 2012.
About Whiting Petroleum Corporation
Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that acquires, exploits, develops and explores for crude oil, natural gas and natural gas liquids primarily in the Rocky Mountain, Permian Basin, Mid-Continent, Gulf Coast and Michigan regions of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota and its Enhanced Oil Recovery fields in Oklahoma and Texas. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit www.whiting.com.
This news release contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this news release, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
These risks and uncertainties include, but are not limited to: declines in oil or natural gas prices; impacts of the global recession and tight credit markets; our level of success in exploitation, exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures, including our ability to obtain CO2; inaccuracies of our reserve estimates or our assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; risks related to our level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations and acquisitions; federal and state regulatory initiatives relating to the regulation of hydraulic fracturing; the potential impact of federal debt reduction initiatives and tax reform legislation being considered by the U.S. Federal government that could have a negative effect on the oil and gas industry; availability of drilling and service rigs; our ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; our ability to successfully complete potential asset dispositions; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry in the regions in which we operate; risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors” in our Annual Report on Form 10-K for the period ended December 31, 2010. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.
Disclosure Regarding Reserves
In this news release, we use the terms proved, probable and possible reserves as defined in SEC rules. Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.
High Plains Gas Announces First Quarter 2012 Construction Division Update
GILLETTE, Wyo.–High Plains Gas, Inc. (OTC: HPGS) announced today that its combined construction subsidiaries, HPG Services and Miller Fabrication, have invoiced over $5 million in completed construction, fabrication, and maintenance services that were performed in the fourth quarter of 2011. The majority of the projects consisted of natural gas facility construction, fabrication services for upstream/midstream energy companies, and ongoing contracts that provide roustabout services for area energy producers.
“The team we have assembled to expand our construction division is exceeding our expectations. There are many projects coming up for bid in the coming year and we believe our team has been able to establish our construction unit as a regional leader in the services and construction industry. We look forward to continuing this growth trajectory through 2012, as we feel that we are well positioned between various energy plays – including the Bakken/Three Forks play in North Dakota and the emerging Niobrara shale play located in Northwest Colorado and Southeast Wyoming. We expect to see our revenue growth accelerate as we move through the year, based on the work we have lined up and the projects we are currently in the process of bidding,” commented Brandon Hargett, High Plains Gas CEO.
About the Company
High Plains Gas, Inc. is a Gillette, Wyoming based company involved in the active ownership and management of two entities within the energy industry. High Plains Gas, LLC, a wholly owned subsidiary of High Plains Gas, Inc., is actively engaged in the acquisition, development and production of natural gas primarily in the Powder River Basin. In 2011, the Company formed a subsidiary, HPG Services, LLC, focused on providing construction, fabrication, and maintenance services to the energy industry, primarily in the Western United States. In October 2011, HPG Services acquired BGM Buildings, a regional construction company focusing on the erection of steel buildings for use throughout the energy and mining industries. Also in late 2011, HPG Services acquired Miller Fabrication LLC, a regional construction and fabrication firm focusing on providing field services to the energy industry in the Western United States. The combination of HPG Services, BGM Buildings, and Miller Fabrication has allowed HPG Services to become a regional leader able to provide clients with a full array of services for the energy and mining industries. For additional information on High Plains Gas, please visit the Company’s website at http://www.highplainsgas.com/.
Statements made about our future expectations are forward-looking statements and subject to risks and uncertainties as described in our most recent filings made with the US Securities and Exchange commission, and are subject to change at any time. Our actual results could differ materially from these forward-looking statements. We undertake no obligation to update publicly any forward-looking statement.
Vanguard Natural Resources Announces Pricing of Its Public Offering of 7,137,255 Million Common Units
HOUSTON–Vanguard Natural Resources, LLC (NYSE: VNR) (the “Company”) today announced the pricing of its public offering of 7,137,255 common units representing limited liability company interests in the Company, of which 3,137,255 common units are being offered by Denbury Onshore, LLC, the selling unitholder (the “Selling Unitholder”), at a price of $27.71 per unit. The underwriters have been granted a 30-day option to purchase up to an additional 1,070,588 common units from the Company at the public offering price less the underwriting discount. The offering is expected to close on January 24, 2012, subject to customary closing conditions.
The Company expects to receive net proceeds of approximately $106.4 million (or approximately $134.9 million if the underwriters exercise their option to purchase an additional 1,070,588 common units), after deducting underwriting discounts and estimated offering expenses, from the offering and intends to use the net proceeds from the offering to repay indebtedness outstanding under its term loan facility and senior secured revolving credit facility. The Company will not receive any of the proceeds from the common units sold by the Selling Unitholder.
Wells Fargo Securities, Citigroup, BofA Merrill Lynch, Barclays Capital, UBS Investment Bank and RBC Capital Markets are joint book-running managers for the offering. An investor may obtain a free copy of the prospectus supplement and accompanying base prospectus relating to the offering by visiting EDGAR on the SEC website at www.sec.gov. When available, a copy of the prospectus supplement and accompanying base prospectus relating to the offering also may be obtained from:
|Wells Fargo Securities|
|Attn: Equity Syndicate Dept.|
|375 Park Avenue|
|New York, NY 10152|
|Phone: (800) 326-5897|
|Attn: Prospectus Department|
|Brooklyn Army Terminal|
|140 58th Street, 8th Floor|
|Brooklyn, NY 11220|
|Phone: (800) 831-9146|
|BofA Merrill Lynch|
|Attn: Prospectus Department|
|4 World Financial Center|
|New York, NY 10080|
|c/o Broadridge Financial Solutions|
|1155 Long Island Avenue|
|Edgewood, NY 11717|
|Phone: (888) 603-5847|
|UBS Investment Bank|
|Attn: Prospectus Department|
|299 Park Avenue|
|New York, NY 10171|
|Phone: (888) 827-7275|
|RBC Capital Markets, LLC|
|Attn: Equity Syndicate|
|Three World Financial Center|
|200 Vesey Street, 8th Floor|
|New York, NY 10281-8098|
|Phone: (877) 822-4089|
The shelf registration statement relating to these securities has previously been filed with the Securities and Exchange Commission and automatically deemed effective. This press release does not constitute an offer to sell or a solicitation of an offer to buy common units or any other securities, nor shall there be any sale of these securities in any jurisdiction in which such an offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. The offering of these securities may be made only by means of the prospectus supplement and the related base prospectus.
About Vanguard Natural Resources, LLC
Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition, production and development of oil and natural gas properties. The Company’s assets consist primarily of producing and non-producing oil and natural gas reserves located in the southern portion of the Appalachian Basin, the Permian Basin, South Texas, Mississippi, Big Horn Basin in Wyoming and Montana, the Williston Basin in North Dakota and Montana and the Arkoma Basin in Arkansas and Oklahoma. More information on Vanguard can be found at www.vnrllc.com.
We make statements in this news release that are considered forward-looking statements within the meaning of the Securities Exchange Act of 1934. These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this news release are not guarantees of future performance, and we cannot assure you that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk Factors” section in our SEC filings and elsewhere in those filings. All forward-looking statements speak only as of the date of this news release. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise.
Magnum Hunter Announces Year-End 2011 Total Proved Oil & Gas Reserves 44.9 Million Barrels of Oil Equivalent
Proved Reserves Up 235% From Year-End 2010; Present Value (PV 10) Up 254% From Year-End 2010; Company Wide Resource Potential Exceeds 537.9 Million Barrels of Oil Equivalent
HOUSTON, TX–(January 17, 2012) – Magnum Hunter Resources Corporation (NYSE: MHR) (NYSE Amex: MHR-PrC) (NYSE Amex: MHR-PrD) (the “Company” or “Magnum Hunter”) announced today a 235% increase in the quantity of the Company’s estimated total proved reserves at December 31, 2011 as compared to December 31, 2010. The present value of estimated future cash flows, before income taxes, of the Company’s estimated total proved reserves as of year-end 2011, discounted at 10% (“PV-10”), also increased 254% as compared to twelve months ago at year-end 2010.
Magnum Hunter’s total proved reserves increased by 31.5 million barrels of oil equivalent (Boe) to 44.9 million Boe (48% crude oil & ngl; 50.9% proved developed producing) as of December 31, 2011 as compared to 13.4 million Boe (51% crude oil & ngl; 44% proved developed producing) at December 31, 2010. The Company’s reserve life (R/P ratio) based on the previously announced year-end exit production rate of approximately 12,500 Boe per day was 9.8 years as of December 31, 2011.
The present value (PV-10) of the Company’s proved reserves at December 31, 2011 increased by $452.5 million or 254% to $630.3 million from $178 million at December 31, 2010. Under SEC guidelines, the commodity prices used in the December 31, 2010 and December 31, 2011 PV-10 estimates were based on the 12-month unweighted arithmetic average of the first day of the month price for the periods January 1, 2010 through December 31, 2010, and for the periods January 1, 2011 through December 31, 2011, respectively, adjusted by lease for transportation fees and regional price differentials. For crude oil and ngl volumes, the average West Texas Intermediate posted price of $96.19 per barrel at December 31, 2011, was up 21% from the average price of $79.43 per barrel at December 31, 2010. For natural gas volumes, the average price of the Henry Hub spot price of $4.11 per million British thermal units (“MMBTU”) at December 31, 2011 was down (6%) from the $4.37 per MMBTU at December 31, 2010. All prices were held constant throughout the estimated economic life of the properties.
Note: PV-10 is a non-GAAP financial measure and should not be considered as an alternative to the standardized measure of discounted future net cash flows as defined under GAAP; see “Non-GAAP Measures: Reconciliation to Standardized Measure” below for the Company’s definition of PV-10 and a reconciliation to the standardized measure.
The Company’s December 31, 2011 total proved reserves of 44.9 million Boe reflect an organic growth of 52.7% from the Company’s pro forma proved reserves of 29.4 million Boe as of December 31, 2010, when excluding the proved reserves related to the Company’s acquisition of NGAS Resources, Inc. and NuLoch Resources, Inc., which occurred on April 13, 2011 and May 3, 2011, respectively. Magnum Hunter’s full year 2011 organic extensions and discoveries and other additions from drilling activities replaced the Company’s full year 2011 estimated production by a factor of 6.7 times. When also including fiscal year 2011’s property acquisition activities as outlined above, the replacement of estimated production factor for the entire fiscal year 2011 increased by approximately 10.8 times.
The estimates of Magnum Hunter’s total proved reserves as of December 31, 2010 and December 31, 2011 were prepared solely by the Company’s third-party engineering consultants, Cawley Gillespie & Associates, Inc. and, for certain of the December 31, 2011 proved reserves, AJM Deloitte.
The Company’s internal engineering team has evaluated the resource potential of Magnum Hunter’s existing undeveloped lease acreage position in our three unconventional shale plays. The undeveloped acreage evaluated includes 652,419 gross acres and 347,547 net acres to Magnum Hunter’s ownership interest. The estimate of the Company’s resource potential is summarized by region as follows:
Net Unrisked Net Risked Resource Resource Potential Potential (MMboe) ------------------------- Area Reservoir (MMboe) 50% 75% Eagle Ford Hunter Eagle Ford 70 36 52 Williston Hunter Bakken / Sanish 114 57 86 Appalachia: Triad Hunter Marcellus / Utica 265 133 199 MHR Production Devonian Shale (Huron/Weir) 44 22 33 --------------- ------------ ------------ Total 493 247 370 =============== ============ ============
Currently, the total number of new drilling locations in Magnum Hunter’s inventory is approximately 4,100 of which 1,400 are identified net drilling locations in these three unconventional resource plays. The new unrisked resource potential of 537.9 million barrels of oil equivalent is approximately 51% crude oil and natural gas liquids
Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter, commented, “The ability to book new proved reserves in our three unconventional resource plays continues to grow exponentially due to the success we have been experiencing with our new well drilling efforts. It is quite remarkable to have reserve growth of 8 Million BOE in just three months of activity (up from 37 Million BOE at September 30, 2011) all from the drill bit alone and within our capital budget parameters. This reserve growth sets us up for another borrowing base increase with our Senior Bank Group which is currently in process, and is indicative of why we were successful in achieving five separate borrowing base increases last year. Once approved, this will further increase our Company’s overall liquidity. Based upon performance seen just in the first couple of weeks of 2012, we anticipate a continuation of exceptional growth in production and proved reserves which should resul t in the additional booking of new proved undeveloped drilling locations.”
About Magnum Hunter Resources Corporation
Magnum Hunter Resources Corporation and subsidiaries are a Houston, Texas based independent exploration and production company engaged in the acquisition, development and production of crude, natural gas and natural gas liquids, primarily in the states of West Virginia, Kentucky, Ohio, Texas, North Dakota and Saskatchewan, Canada. The Company is presently active in three of the most prolific unconventional shale resource plays in North America, namely the Marcellus Shale, Eagle Ford Shale and Williston Basin/Bakken Shale.
Non-GAAP Measures: Reconciliation to Standardized Measure
This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this release of the non-GAAP financial measures to the most directly comparable GAAP financial measures. These non-GAAP financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with GAAP that are presented in this release. PV-10 is the present value of the estimated future cash flows from estimated total proved reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future cash flows are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides u seful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. However, PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.
The standardized measure of discounted future net cash flows relating to Magnum Hunter Resources total proved oil and gas reserves is as follows (in thousands):
(Unaudited) As of December, 2011 --------------- Future cash inflows $ 2,435 Future production costs 767 Future development costs 330 Future income tax expense 243 --------------- Future net cash flows 1,095 10% annual discount for estimated timing of cash flows 637 --------------- Standardized measure of discounted future net cash flows related to proved reserves $ 458 =============== Reconciliation of Non-GAAP Measure PV-10 $ 630 Less: Income taxes Undiscounted future income taxes (244) 10% discount factor 72 --------------- Future discounted income taxes (172) --------------- Standardized measure of discounted future net cash flows $ 458 ===============
For more information, please view our website at http://www.magnumhunterresources.com/
The statements and information contained in this press release that are not statements of historical fact, including all estimates and assumptions contained herein, are “forward looking statements” as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward looking statements include, among others, statements, estimates and assumptions relating to our business and growth strategies, our oil and gas reserve estimates, estimates of oil and natural gas resource potential, our ability to successfully and economically explore for and develop oil and gas resources, our exploration and development prospects, future inventories, projects and programs, expectations relating to availability and costs of drilling rigs and field services, anticipated trends in our business or industry, our future results of operations, our liquidity and ability to finance our exploration and development activities, market conditions in the oil and gas industry and the impact of environmental and other governmental regulation. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may”, “will”, “could”, “should”, “expect”, “intend”, “estimate”, “anticipate”, “believe”, “project”, “pursue”, “plan” or “continue” or the negative thereof or variations thereon or similar terminology. These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among other, the following: adverse economic conditions in the United States and globally; difficult and adverse conditions in the domestic and global capital and credit markets; changes in domestic and global demand for oil and natural gas; volatility in the prices we receive for our oil and natural gas; the effects of government regulation, permitting, and other legal requirements; future developments with respect to the quality of our properties, including, among other things, the existence of reserves in economic quantities; uncertainties about the estimates of our oil and natural gas reserves; our ability to increase our production and oil and natural gas income through exploration and development; our ability to successfully apply horizontal drilling techniques and tertiary recovery methods; the number of well locations to be drilled, the cost to drill, and the time frame within which they will be drilled; drilling and operating risks; the availability of equipment, such as drilling rigs and transportation pipelines; changes in our drilling plans and related budgets; and the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. Readers are cautioned not to place undue reliance on forward-looking statements, contained herein, which speak only as of the date of this document. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, including estimates, whether as a result of new information, future events, or otherwise. We urge readers to review and consider disclosures we make in our public filings made from time to time with the Securities and Exchange Commission that discuss factors germane to our business, including our Annual Report on Form 10-K, as amended for the year ended December 31, 2010 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011, June 30, 2011 and September 30, 2011. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.
The U.S. Securities and Exchange Commission (“SEC”) requires oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. In this press release, we use the term “resource potential” to describe the Company’s internal estimates of volumes of oil and natural gas that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. This is a broader description of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. The “resource potential” disclosed in the table that appears in this press release includes both possibl e reserves and potentially recoverable volumes that cannot be classified as proved, probable or possible reserves. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the Company. We believe our estimates of unproved resources and future drillsites are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.
Samson Oil & Gas Operational Advisory
DENVER & PERTH, Australia–Samson Oil & Gas Limited (ASX: SSN; NYSE AMEX: SSN) advises on the following field operations:
Gretel II 12KA 3, Roosevelt County, MT (SSN 100%, subject to a 33.34% back-in option)
The required repair to the top drive unit was completed and DHS Rig 1 on the Gretel II well site has commenced drilling operations from the 9 5/8 inch casing shoe, which had previously been set at 1,701 feet. Current operations are drilling ahead at a depth of 7,100 feet. The forward plan is to change out the bottom hole assembly to include MWD tools at a depth of 7,500 feet to enable the core point to be accurately selected at around 8755’.
The Gretel II 12 KA 3 well is Samson’s second Bakken well in the Roosevelt Project.
HAWK SPRINGS PROJECT
Defender US33 #2-29H, Goshen County, WY (SSN 37.5% carried working interest)
The Defender US33 #2-29H workover rig arrived on location on Friday, January 13th and the existing pump was removed over the weekend. Due to adverse weather conditions, the operation has proceeded slower than expected and the replacement pump is due to be in operation today.
The Defender US33 #2-29H is the first Niobrara appraisal well in Samson’s Hawk Springs project and is being fully carried by Samson’s farmin partner.
NORTH STOCKYARD FIELD
Everett #1-15H, Williams County, ND (SSN 26% working interest)
The drill out of frac plugs has been completed, following the completion of the stimulation job that placed 1.6 million pounds of proppant in 20 stages.
The well flowed during drill out operations and during the operation to land the production tubing. The flow rate (measured hourly) varied from 528 BOPD (extrapolated) to 2,112 BOPD (extrapolated). These flows have been established from the annulus only. The forward operation is to hydraulically burst the safety disc inside the tubing which will allow the well to be put into production. This operation is expected to be completed during today. Cumulative production to date is 3,800 barrels of oil.
The Everett #1-15H well is Samson’s sixth Bakken well in the North Stockyard Field.
Samson’s Ordinary Shares are traded on the Australian Securities Exchange under the symbol “SSN.” Samson’s American Depository Shares (ADSs) are traded on the New York Stock Exchange AMEX under the symbol “SSN.” Each ADS represents 20 fully paid Ordinary Shares of Samson. Samson has a total of 1,996 million ordinary shares issued and outstanding (including 246 million options exercisable at AUD 1.5 cents), which would be the equivalent of 99.8 million ADSs. Accordingly, based on the NYSE AMEX closing price of US$2.27 per ADS on January 12, 2012 the Company has a current market capitalization of approximately US$225 million. Correspondingly, based on the ASX closing price of A$0.105 on January 12, 2012, the Company has a current market capitalization of A$206 million. The options have been valued at their closing price of A$0.094 on January 12, 2012 and translated to US$ at the current exchange of 1.0377 for purposes of inclusion in the US$ market capitalization calculation.