Magnum Reports Proved, Probable and Possible Reserves

Source: www.gulfoilandgas.com 8/21/2013, Location: North America

Magnum Hunter Resources Corporation (the "Company" or "Magnum Hunter") announced that its combined estimated proved, probable and possible reserves ("3P Reserves") were 119.3 MMBoe and its estimated contingent resources were an additional 728.9 MMBoe as of June 30, 2013. Magnum Hunter's 3P Reserves at June 30, 2013 were prepared by a third-party engineering consultant, Cawley Gillespie & Associates, Inc. ("Cawley"), and include the Marcellus and Williston Basin/Bakken/Sanish Shale reserves, however, no Utica Shale reserves were included. The contingent resource estimate is an internal analysis prepared by Magnum Hunter that includes the Company's Utica Shale potential on its vast lease acreage holdings.

The Williston Basin/Bakken/Sanish Shale and Marcellus Shale probable and possible reserves were estimated at 49.8 MMBoe and 11.7 MMBoe, respectively, as of June 30, 2013. The contingent resources based on Magnum Hunter's internal analysis as of June 30, 2013 were comprised of 44.4 MMBoe in the Williston Basin/Bakken/Sanish Shale, 142.9 MMBoe in the Marcellus Shale, 496.2 MMBoe in the Utica Shale, and 45.4 MMBoe in the Devonian Shale.

Proved Reserves Overview
As previously reported, Magnum Hunter's total proved reserves, excluding the Eagle Ford Shale properties divestment which occurred in April 2013, decreased by 6% to 57.8 MMBoe (51% crude oil and NGLs; 61% proved developed producing) at June 30, 2013 as compared to 61.6 MMBoe (57% crude oil and NGLs; 56% proved developed producing) at December 31, 2012(a). This decline was primarily due to higher lease operating expenses ("LOE") in the Williston Basin which moved certain proved undeveloped reserves into the probable category. Proved developed reserves increased by 3% from year-end 2012 to 35.4 MMBoe as of June 30, 2013 as a result of the Company's continued execution of its development drilling program. Aggregate proved undeveloped reserves decreased slightly primarily due to higher LOE costs related to rental equipment, manpower and field fuel use. The Company anticipates LOE costs in the Williston Basin to decrease over time due to increased efficiencies at the field level, including electrification of certain fields.

As of June 30, 2013, no proved reserves had been booked in Magnum Hunter's significant leasehold acreage position owned in the Utica Shale in the Appalachian Basin (80,000+ net acres) where the Company has initiated an active drilling program. The Company also expects a significant increase in reserves during the second half of the year due to "pad" related drilling in Appalachia for both the Utica and Marcellus Shales. Given the Company's successful drilling results to-date, as well as those of other operators in the vicinity of its leasehold acreage, Magnum Hunter believes that a substantial portion of its Utica Shale acreage will be added to proved reserves over time as more wells are drilled and delineated in this region. The Appalachian Basin accounted for 65% of Magnum Hunter's proved reserve volumes at June 30, 2013, the Williston Basin accounted for 34% and other legacy assets, including our remaining assets in South Texas, accounted for the remaining 1%. At mid-year 2013, 50% of the Company's proved reserves by volume were natural gas, 38% were crude oil and 12% were NGLs.

The present value of estimated future cash flows discounted at an annual rate of 10% ("PV-10") of the Company's proved reserves at June 30, 2013 decreased to $666.4 million from $753.4 million at December 31, 2012, excluding the Eagle Ford Shale divestment (See Non-GAAP Financial Measures and Reconciliations below)(a). Under the Securities and Exchange Commission ("SEC") guidelines, the commodity prices used in the June 30, 2013 and December 31, 2012 PV-10 estimates were based on the 12-month un-weighted arithmetic average of the first day of the month prices for the period July 1, 2012 through June 1, 2013 and for the period December 30, 2011 through November 30, 2012, 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 $91.60 per barrel was used to calculate PV-10 at June 30, 2013, which was down 3.3% from the average price of $94.71 per barrel used to calculate PV-10 at December 31, 2012. For natural gas volumes, the average Henry Hub spot price of $3.46 per million British thermal units ("MMBTU") was used to calculate PV-10 at June 30, 2013, which was up 26% from the average price of $2.75 per MMBTU used to calculate PV-10 at December 31, 2012. All prices were held constant throughout the estimated economic life of the properties.

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