Attached files
| file | filename |
|---|---|
| 8-K/A - MONGOLIA HOLDINGS, INC. | cnsv_8ka.htm |
| EX-99.3 - MONGOLIA HOLDINGS, INC. | cnsv_ex99-3.htm |
| EX-99.2 - MONGOLIA HOLDINGS, INC. | cnsv_ex99-2.htm |
| EX-10.1 - MONGOLIA HOLDINGS, INC. | cnsv_ex10-1.htm |
| EX-99.1 - MONGOLIA HOLDINGS, INC. | cnsv_ex99-1.htm |
AMERICAN ENERGY ADVISORS, INC.
June 21, 2010
Consolidation Services, Inc.
2300 W. Sahara Ave, Ste 800
Las Vegas, NV 89102
Attn: Mr. Gary Kucher, President
Re: Leland Energy Funds, Various counties, Kentucky; Fentress Co., Tennessee
A reserve analysis for the various working interests owned by Consolidation Services, Inc. (“CSI”) in the subject areas was performed. Projections of the reserves and future net revenue to the evaluated interests were based on economic parameters and operating conditions considered applicable as of April 1, 2010 This report has been prepared pursuant to the guidelines of the United States Securities and Exchange Commission ("SEC") by American Energy Advisors, Inc.
The effective date of the evaluation is: April 1, 2010.
Reserves and future revenue net to CSI’s interests in all various Funds are estimated to be as follows. Summaries by Fund follow the body of this report:
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Consolidation Services, Inc.
Unescalated Pricing
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Estimated
Net Reserves
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Estimated
Future Net Revenue
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Effective 4/1/2010
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Net to various WI amd NRI
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Reserve Category
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Oil &
Condensate
(MBO)
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Gas
(MMCF)
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Not
Discounted
(M$)
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Discounted
@ 10%
(M$)
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Proved Developed Producing:
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83.270 | 0.000 | 2,684.990 | 1,222.010 | ||||||||||||
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Proved Non-Producing:
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30.290 | 1,041.690 | 2,220.280 | 669.330 | ||||||||||||
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Proved Undeveloped:
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34.110 | 0.000 | 737.730 | 163.610 | ||||||||||||
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Total Proved:
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147.670 | 1,041.690 | 5,643.000 | 2,054.950 | ||||||||||||
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Probable:
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62.030 | 0.000 | 1,121.980 | 85.130 | ||||||||||||
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Total Not Proved:
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62.030 | 0.000 | 1,121.980 | 85.130 | ||||||||||||
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Total All Reserve Categories:
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209.700 | 1,041.690 | 6,764.980 | 2,140.080 | ||||||||||||
Oil reserves are expressed in barrels, one of which is equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet ("Mcf") and are evaluated at the appropriate temperature and pressure base.
The reserves and future revenue estimated in this report are for all known potential reserve categories.
Pursuant to applicable SEC rules, the future net revenue is discounted at an annual rate of ten percent to determine the discounted future net revenue. Revenue discounted at 10% is shown only to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
15635 Alton Pkwy., Ste. 295 ● Irvine, CA 92618 ● Ph: 949-242-3636 ● Fax: 949-242-3635
Email: aeasal@aol.com
Consolidation Services, Inc. – Kentucky and Tennessee Fields
Reserve Analysis
Page 2
Cash flow projections include deductions for appropriate state and local production taxes, but do not include any credits or liabilities associated with federal or state income taxes.
All working and net revenue interests used were as presented by CSI.
Following is a summary of the evaluation criteria used for the reserve analysis:
Proved Developed Producing (PDP) – historical production for each of the wells in the subject areas was gathered where available from public data sources and from check stubs from historical oil sales. Actual production or historical sales data for most wells was available through May, 2010. Where adequate history was available, the projections were performed by history matching the existing data and extrapolating this historical data without volumetric limits. A “settled” average exponential decline rate of 3% per year was utilized for all oil wells. If historical data was not available, a 3% flat exponential decline “average type curve” based on other curves in the area was used.
In addition, the ultimate recoveries of each well were compared for reasonability to the estimated volumetric recoveries for undeveloped locations, and held to those expected recoveries if required.
Proved Developed Non-Producing (PDNP) – the shut-in oil wells in the Kentucky fields were each reviewed with the field operator for production potential, and if applicable, assigned reserves based on either extrapolation of historical data prior to being shut in, or the 3% flat decline curved described above under “PDP”. Capital expenditures necessary to resume production, if any, were provided by the field operator. If a capital expenditure was not necessary to place a well back on production, such as on the Cundiff lease where the current shut-in wells are waiting for salt water disposal well mechanical integrity testing, no costs were entered.
The shut in gas wells in Kentucky and Tennessee were not individually reviewed with the field operator. However, they were assigned reserves based on extrapolation of historical data prior to being shut in. If no such data existed, no reserves were assigned.
Each well is currently completed “open-hole”, and all are planned to be further completed by running 4 ½” casing, cementing, and fractured, as is the procedure for thousands of completed wells in the same area.
Shut in gas well production from all gas wells was assumed to resume on July 1, 2011 based on information provided by CSI. CSI plans to produce the wells for up to a year and then finish the completions. An initial rate after final completion of 30 MCFD was utilized and considered an average rate for the area, which declines rapidly at first, and then produces an estimated 100,000 MCF at a nominal decline over a 40+ year period. The capital expenditure necessary to resume production (swab back on for $300 per well), and the completion cost of approximately $45,000 per well were provided by the field operator. A “settled” average exponential decline rate of 3% per year was utilized for all gas wells.
Proved Behind Pipe (PBP) – No behind-pipe reserves were assigned.
Proved Undeveloped (PUD) – PUD reserves were only assigned to one Kentucky oil lease located in the Gradyville Oilfield: Kenneth Block in the Block Production Fund. Most of the oil wells produce primarily from the Knox Dolomite at an average depth of 1,550’ to 1,650’. The Knox typically exists as three 10’ to 12’ thick dolomite benches separated by shale, with average reservoir characteristics of: 12% to 20% intercrystaline and vugular porosity, fracture permeability, 25% to 50% water saturation, and minimal gas. Oil gravity averages 46° API.
Consolidation Services, Inc. – Kentucky and Tennessee Fields
Reserve Analysis
Page 3
Wells are completed naturally and open-hole, and are sometimes treated with an acid wash. Initial production can be as high as 30 BOPD, but falls off rapidly and within 2 to 24 months settles at 0.75 to 1.5 BOPD. Production thereafter declines at a minimal 2% to 3% per year for 30+ years. Average estimated ultimate recovery ranges 5,000 BO to 10,000 BO depending on structural location and formation quality. According to the field operator, there may be minimal water drive.
There is occasional production from the Murfreesboro and Sunnybrook Formations in addition to the Knox Dolomite, but PUD reserves were not assigned for this potential.
Drilling locations were identified by spotting wells on 5-acre spacing, which is typical in the Gradyville Field, within the Block lease outline on a structure map above an identified structural production limit. To create a representative projection for the reserves “assigned” to each development location identified, an analog curve was created by time normalization of well histories for wells that were drilled in 2007 to 2009 in the Gradyville Field that currently produce from the Knox Dolomite. In addition, a comparison of the analog projection was made to a volumetric estimate of recovery from the Knox assuming recovery factors of 5% to 10% of original oil in place.
Following is the analog curve used for development wells:
Initial Oil rate = 600 BOPM
Declines to 180 BOPM in 60 days
Initial Hyperbolic decline after 60 days, d = 99.9%/yr.
Hyperbolic exponent, b = 2.2
Settled exponential decline (end limit) = 3%.
Without economic parameters applied the analog projection results in an ultimate recovery of approximately 9,500 BO.
The estimated cost to drill and complete a Block well is $105,000. CSI plans to drill one well per month beginning October, 2010, except that no wells are drilled from December to February due to winter weather conditions.
Probable Undeveloped (PROB) – Additional Gradyville Field Knox development locations were identified as offsets to existing producing wells in other drilling funds, but using lease base maps without a structure map and therefore without knowledge of structural location. These locations (and numerous others) are already “staked” and planned for drilling by CSI.
The same development analog described above that was used for PUD locations was utilized for PROB locations.
The estimated cost to drill and complete a Block or Posey lease well is $105,000. All other lease wells are estimated to each cost $150,000. CSI plans to drill one well per month beginning April, 2011, except that no wells are ever drilled from December to February due to winter weather conditions.
Product Prices: SEC regulations require future revenues for oil and gas properties to be projected on the basis of product prices averaged over the 12 month period prior to the effective date of the report without escalation or reduction.
Gas Pricing – The NYMEX Henry Hub gas price on the April 1, 2010 effective date was $4.09/Mcf.
Gas Price differential – The gas price differential to NYMEX Henry Hub for these areas ranged as follows: a discount of $.90/Mcf for the Gernt leases in Tennessee, a bonus of
Consolidation Services, Inc. – Kentucky and Tennessee Fields
Reserve Analysis
Page 4
$0.43/Mcf for the DeWees lease in Kentucky, and a discount of $0.36/Mcf for all other gas wells in Tennessee and Kentucky.
Oil Pricing – The NYMEX published oil price for light, sweet crude on the April 1, 2010 effective date was $70.62/BO.
Oil Price differential - The oil price differential to NYMEX for these areas ranged as follows: a 1.4% discount for Downey, Cundiff, and Whittle leases, and a 2.7% discount for all other oil leases.
Taxes: Kentucky and Tennessee’s severance tax is 4.5% of revenue from oil and gas. These tax rates were utilized for the report. There are no county ad valorem taxes.
Operating Costs:
Monthly well operating cost: Average lease operating costs were provided by the operator of the Kentucky fields. These were allocated, where applicable, to individual producing wells by monthly producing rate. Average operating cost was determined to range $275 to $350/month per well.
An average operating cost of $175/mo per well was provided for the gas wells.
Oil Sales transportation cost: The oil purchaser transports oil from the various Gradyville Field leases approximately 160 miles to the closest refinery, and the trucking cost is $7.50/BO. This cost is allocated to both royatly and working interest owners, and was applied to all oil wells.
Gas Sales transportation cost: The cost to compress and sell gas into the existing gas lines ranges from $.10/MCF to $.30/MCF depending on gas volume.
Equipment Value: No value was placed on well equipment.
Abandonment: The assumption was made that equipment salvage would pay for well abandonment.
Report Qualifications
THE ESTIMATED FUTURE REVENUES AND PRESENT VALUE OF THESE
REVENUES ARE NOT REPRESENTED AS MARKET VALUE.
Actual individual lease performance may vary from the projections, particularly in comparison to the total composite production from all properties.
American Energy Advisors, Inc. is completely independent of CSI and any of its officers or key personnel. Neither I nor anyone closely associated with me or American Energy Advisors, Inc. have any relationship with, or ownership of, CSI Interests that would impair such independence.
American Energy Advisors, Inc. was paid on an hourly basis for its services by CSI.
If you require additional information or assistance, please do not hesitate to call.
Sincerely:
/s/ Stephen A. Lieberman, P.E.