Attached files
| file | filename |
|---|---|
| 10-K/A - FORM 10-K AMENDMENT - MAGNUM HUNTER RESOURCES CORP | mhr_10ka.htm |
| EX-99.1 - CAWLEY LETTER MARCH 2 - MAGNUM HUNTER RESOURCES CORP | magnum_ex9901.htm |
| EX-31.1 - CERTIFICATION - MAGNUM HUNTER RESOURCES CORP | mhr_10ka-ex3101.htm |
| EX-32 - CERTIFICATION - MAGNUM HUNTER RESOURCES CORP | mhr_10ka-ex3200.htm |
| EX-31.2 - CERTIFICATION - MAGNUM HUNTER RESOURCES CORP | mhr_10ka-ex3102.htm |
| EX-99.4 - DEGOLYER LETTER - MAGNUM HUNTER RESOURCES CORP | mhr_10ka-ex9104.htm |
| EX-99.3 - CAWLEY LETTER MARCH 9 - MAGNUM HUNTER RESOURCES CORP | mhr_10ka-ex9103.htm |
Exhibit 99.2
March 5, 2010
Mr. Jim Denny
Magnum Hunter Resources Corporation
777 Post Oak Blvd., Suite 910
Houston, Texas 77056
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Re:
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Evaluation Summary – SEC Price Case
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Magnum Hunter Resources Corp. Interests
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Total Proved Reserves
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Certain Properties in North Dakota
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As of December 31, 2009
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Dear Mr. Denny:
As requested, this report was prepared on March 5, 2010 for Magnum Hunter Resources Corporation (“MHR”) for the purpose of submitting our summary level reserve estimates and forecasts of economics attributable to the subject interests. We evaluated 100% of the MHR reserves, which are located throughout 14 fields in North Dakota. This report, with an effective date of December 31, 2009, was prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). The results of this evaluation are presented in the accompanying tabulations, with a composite summary of the main SEC Pricing values presented below:
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Proved
Developed
Producing
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Proved
Undeveloped
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Total
Proved
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Net Reserves
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Oil
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- Mbbl
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1,410.1
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1,561.4
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2,971.5
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Gas
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- MMcf
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571.8
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184.6
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756.4
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Revenue
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Oil
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- M$
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76,591.1
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84,535.4
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161,126.5
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Gas
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- M$
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943.0
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269.1
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1,212.1
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Severance Taxes
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- M$
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3,980.1
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4,254.5
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8,234.6
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Ad Valorem Taxes
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- M$
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0.0
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0.0
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0.0
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Operating Expenses
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- M$
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33,685.7
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15,662.8
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49,348.5
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Other Deductions
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- M$
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0.0
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0.0
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0.0
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Investments
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- M$
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0.0
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15,674.1
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15,674.1
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Net Operating Income
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- M$
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39,868.2
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49,213.1
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89,081.3
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Discounted @ 10%
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- M$
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22,521.2
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23,159.2
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45,680.4
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Magnum Hunter Resources Corporation Interests
March 5, 2010
Page 2
The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc. (“CG&A”).
Presentation
This report presents three (3) different pricing scenarios, which include the main SEC Pricing case and two price sensitivity cases. The main SEC Pricing case is divided into three reserve category sections: Total Proved (“TP”), Proved Developed Producing (“PDP”) and Proved Undeveloped (“PUD”). Within each reserve category section are Tables I, Summary Plots and Tables II. The Tables I present composite reserve estimates and economic forecasts for the particular reserve category or property grouping. The Summary Plots are composite rate-time history-forecast curves for the corresponding Table I. Following certain Summary Plots are Table II “oneline” summaries that present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow for the individual properties that make up the corresponding Table I.
The two price sensitivity cases are presented in the Appendix and are described in more detail below. For a more detailed explanation of the report layout, please refer to the Table of Contents following this letter. The data presented in the composite Tables I are explained in page 1 of the Appendix. The methods employed in estimating reserves are described in page 2 of the Appendix.
Hydrocarbon Pricing
As required by the SEC, December 31, 2009 oil and gas prices of $61.18/STB and $3.866/MMBTU, respectively, were calculated and applied to all properties unescalated. As requested by MHR, two additional price sensitivity cases were prepared and are presented in the Appendix. Price Sensitivity #1 oil and gas prices of $79.36/STB and $5.805/MMBTU, respectively, were applied based on closing prices as quoted on December 31, 2009. Price Sensitivity #2 oil and gas prices were applied based on a NYMEX future strip price deck as quoted on December 31, 2009 and provided below.
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SEC Pricing
Average 2009
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Sensitivity Case #1
Flat 12-31-09 Pricing
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Sensitivity Case #2
Strip 12-31-09 Pricing
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WTI Cushing
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Henry Hub
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WTI Cushing
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Henry Hub
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NYMEX
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NYMEX
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Cash
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Spot
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Cash
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Spot
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Futures
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Futures
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Year
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$/STB
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$/MMBTU
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$/STB
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$/MMBTU
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$/STB
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$/MMBTU
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2010
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61.18 | 3.866 | 79.36 | 5.805 | 81.94 | 5.790 | ||||||||||||||||||
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2011
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“ | “ | “ | “ | 85.81 | 6.336 | ||||||||||||||||||
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2012
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“ | “ | “ | “ | 87.83 | 6.527 | ||||||||||||||||||
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2013
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“ | “ | “ | “ | 89.31 | 6.669 | ||||||||||||||||||
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2014+
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“ | “ | “ | “ | 91.09 | 6.843 | ||||||||||||||||||
All economic factors were held constant in accordance with SEC guidelines. Oil and gas price differentials were calculated and applied by Field. Oil price differentials may include adjustments for basis differential, transportation and/or crude quality corrections. Gas price differentials may include adjustments for basis differential, transportation, shrinkage and/or heating value (BTU content).
Expenses and Taxes
Operating expenses and capital expenditures were not escalated in compliance with SEC guidelines. Initial lease operating expenses (column 22) were forecast on a per-field basis, with values ranging from $663 to $2,553 per well per month depending upon the field. In addition to the per-well operating costs field-wide “fixed LOE” cases were created for each of the fields. Field-wide LOE was allocated by reserve category based on gross reserves (Mboe). Gas marketing fees were applied on a per-field basis with values ranging from $0.46 to $0.84 per MCF depending upon the field.
Magnum Hunter Resources Corporation Interests
March 5, 2010
Page 3
Gross capital expenditures were applied as follows: $1,200,000 for a new single-lateral horizontal well; $2,400,000 for a new dual-lateral horizontal well; $700,000 for a new vertical well (producer or injector); $200,000 for conversion of a producer to injector. PRC is obligated to pay 100% of PRC plus Eagle Operating (“joint”) interests until a cumulative of $45,000,000 in capital has been spent. Based on this, it has been estimated that PRC will pay the joint interest AFE’s for all capital costs through February, 2011.
For all producing wells except for those at Lake View and West Greene fields, we applied a stripper well severance tax of 5% of oil revenue for the life of the property. For horizontal wells in fields/units designated as “stripper” properties, we applied a 5% severance tax for the life of each property. For horizontal wells in fields not designated as “stripper” properties we applied the standard 11.5%. Gas severance taxes were applied at current state rates of $0.15 per Mcf for each gas producing property. No ad valorem taxes were applied for North Dakota properties.
Development Plans
This report models the development of 14 North Dakota oil fields for secondary recovery operations. All fields are currently productive, with multiple fields undergoing various degrees of water injection. The general development plan is to begin or continue water injection in each field, re-pressure each reservoir to initial conditions, drill horizontal and/or vertical producing wells, and continue production and water injection for the remaining life of each property. Water injection in each field will be enhanced or begin by converting existing vertical producing wells to injectors or drilling new wells as water injectors. Water sources include produced water from the Madison reservoir and water source wells producing from the Delaware formation.
Horizontal well production profiles and reserves were modeled based upon a study of analogous horizontal wells in fields undergoing water injection operations. This study pointed to an ultimate recovery of 200,000 barrels of oil (BO) per lateral. This was supplemented with details specific to each field, such as reservoir quality, average vertical well recoveries, and cumulative recoveries to date. Re-pressurization of a pressure-depleted reservoir, estimated to take approximately two to three years upon commencement of injection, was based upon a study of analogous fields undergoing secondary recovery operations.
Development plans were provided by MHR and the proved portion of the projected reserves were modeled in this report in accordance with SEC guidelines. The development plans included the current and/or projected unit boundaries, the number of planned injectors, the number of planned new producing wells, and the timing of key development milestones. Success for each secondary recovery program will depend upon proper execution of the above noted projects, including the injection of sufficient water volumes to offset produced liquids and to increase and maintain reservoir pressures.
Miscellaneous
An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included. The reserves and economics presented herein are unrisked, and represent 100% of the MHR proved reserves.
The proved reserve classifications used herein conform to the definitions of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties in effect as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
Magnum Hunter Resources Corporation Interests
March 5, 2010
Page 4
All estimates represent our best judgment based on the data available at the time of preparation. The reserve estimates were based on interpretations of factual data furnished by your office and available from our files. Oil and gas prices, expense data, tax values and ownership interests were also supplied by you and were accepted as furnished. Additionally, historical well/lease/unit production was provided by you and was accepted as furnished. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data
This report was prepared for the exclusive use of Magnum Hunter Resources Corporation. Third parties should not rely on this report without the written consent of the above and Cawley, Gillespie & Associates, Inc. We are independent registered professional engineers and geologists. We do not own an interest in the properties or Magnum Hunter Resources Corporation and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work papers and related data are available for inspection and review by authorized, interested parties.
Yours very truly,
/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693