Attached files
| file | filename |
|---|---|
| 10-K/A - FORM 10-K (AMENDMENT NO.1) - Tiger Oil & Energy, Inc. | t71440_10ka.htm |
| EX-32.2 - EXHIBIT 32.2 - Tiger Oil & Energy, Inc. | ex32-2.htm |
| EX-99.5 - EXHIBIT 99.5 - Tiger Oil & Energy, Inc. | ex99-5.htm |
| EX-99.4 - EXHIBIT 99.4 - Tiger Oil & Energy, Inc. | ex99-4.htm |
| EX-99.1 - EXHIBIT 99.1 - Tiger Oil & Energy, Inc. | ex99-1.htm |
| EX-31.1 - EXHIBIT 31.1 - Tiger Oil & Energy, Inc. | ex31-1.htm |
| EX-31.2 - EXHIBIT 31.2 - Tiger Oil & Energy, Inc. | ex31-2.htm |
| EX-99.6 - EXHIBIT 99.6 - Tiger Oil & Energy, Inc. | ex99-6.htm |
| EX-99.2 - EXHIBIT 99.2 - Tiger Oil & Energy, Inc. | ex99-2.htm |
| EX-32.1 - EXHIBIT 32.1 - Tiger Oil & Energy, Inc. | ex32-1.htm |
Exhibit 99.3
| Proved | ||||||||||||||||||||
|
2008 Actual
|
Developed
Producing |
Developed
Nonproducing |
Undeveloped
|
Total
Proved |
||||||||||||||||
|
Future Gross Revenue
|
76,974.15 | 905,479 | 2,716,441 | - | 3,621,920 | |||||||||||||||
|
Production and Ad Valorem Taxes @ 7.5%
|
5,773.06 | 67,911 | 203,733 | - | 271,644 | |||||||||||||||
|
Operating Expenses
|
3,600.00 | 36,000 | 36,000 | - | 72,000 | |||||||||||||||
|
Capital Costs
|
- | - | - | - | - | |||||||||||||||
|
Abandonment
|
- | 12,000 | 12,000 | - | 24,000 | |||||||||||||||
|
Future Net Revenue
|
67,601 | 789,568 | 2,464,708 | - | 3,254,276 | |||||||||||||||
|
Present Worth at 10 Percent
|
710,611 | 2,218,237 | - | 2,928,848 | ||||||||||||||||
|
Jett Rink 18.5% WI
|
12,506 | 131,463 | 410,374 | 541,837 | ||||||||||||||||
| Proved | ||||||||||||||||||||
|
2009 Actual
|
Developed
Producing |
Developed
Nonproducing |
Undeveloped
|
Total
Proved |
||||||||||||||||
|
Future Gross Revenue
|
32,441.29 | 828,505 | 2,716,441 | - | 3,544,946 | |||||||||||||||
|
Production and Ad Valorem Taxes @ 7.5%
|
2,433.10 | 56,365 | 203,733 | - | 260,098 | |||||||||||||||
|
Operating Expenses
|
3,600.00 | 32,400 | 36,000 | - | 68,400 | |||||||||||||||
|
Capital Costs
|
- | - | - | - | - | |||||||||||||||
|
Abandonment
|
- | 12,000 | 12,000 | - | 24,000 | |||||||||||||||
|
Future Net Revenue
|
26,408 | 727,740 | 2,464,708 | - | 3,192,448 | |||||||||||||||
|
Present Worth at 10 Percent
|
654,966 | 2,218,237 | - | 2,873,203 | ||||||||||||||||
|
Jett Rink 18.5% WI
|
4,886 | 121,169 | 410,374 | 531,543 | ||||||||||||||||
On June 10, 2010, the Company obtained a valuation report for each of the two leases from Richard F. Mooney, a petroleum geologist/geophysicist, based on reported well data and available production history (the “Reports”). The following is a discussion of the Reports with respect to such leases.
Two wells were drilled in 2006, the Shilo #1, NE/4 SW/4 NE/4 NE/4 and the Shilo #2, SE/4 SW/4 NW/4 NE/4. The wells were drilled by a now defunct operator, Mr. Dempsey Todd Shelton, of Tulsa. The Shilo #1 originally produced 550 MCFG/D w/no water from a 10 foot Dutcher section (2940’ ─ 2950’). From June, 2007 through November, 2009, (the available production history of the well) this well produced a cumulative 61,087 MCFG at an average monthly rate of 2068 MCFG/month and 374 BO. Logs were not available for this well, but pertinent reservoir characteristics are well known. Dutcher sands typically have porosities of 15 ─ 25 %. Although the well made no water, a water saturation of 25% was assumed (again, the values for this reservoir average 14 ─ 33% in producing sands). Allowing for a 10 acre drainage, this reservoir volumetrics calculates to 588,060 cubic feet of available reservoir. This translates to a 104,738 barrel capacity, or 1,047,380 MCFG capacity. Deducting the gas already produced leaves a volume of 986,287 MCFG in place. Industry standard is a 33% primary recovery rate, leaving 284,542 MCFG available for primary recovery. If $3/MCFG is assumed (gas is presently @ $4/MCFG), this represents a potential of $853,627 revenue for a net 100% revenue interest, or @ $85,363 for a 10% revenue interest. Initial reservoir shut-in pressure was 875 psi (11/64 choke). The reservoir was perf’d and given a light acid job, but not frac’d. Historically, the production went from a high of 3,361 MCFG/M in January, 2008, and tapered off in late 2009 to a low of 625 MCFG/M in November, 2009. This probably is more representative of the quality of the operator than reservoir quality. This well, with a light frac and acid job and an ongoing program of pressure maintenance will potentially resume the volume of production formerly seen.
The Shilo #2 produced from the Bartlesville sand at 2410’ ─ 2414’. Initial production was 55MCFG + 2 BO + ¼ BW per day. Initial shut-in pressure was reported @ 800 psi and the reservoir flow via a 16/64 choke. No production history is available for this well, but applying volumetric analysis as above (porosity is assumed @ 15% and water saturation @ 33%), then a reservoir volume of 175,111 cubic feet of volume is estimated in 10 acres. This translates to a volumetric equivalent of 31,189 barrels. The gas to oil ratio is roughly 27:1 and the gas equivalent is 5.5 barrels. This means original oil in place would be 10,292 barrel - equivalent by primary recovery, or about 9,924 MCFG and 368 BO from this reservoir. This represents a potential 100% revenue interest of $29,772 for gas and $22,080 for oil. A 10% revenue interest would be $2,977 and $2,208, respectively. This well also was perf’d and acidized, but not frac’d. A light frac and follow-up acid job may increase potential production.
Oklahoma Corporation Commission Orders # 523196 (Bartlesville) and #30640 (Dutcher) place spacing at 40 acres on this acreage. This would increase drainage area potential by a factor of 4 to the above calculations, increasing potential of a 10% revenue interest in the Shilo #1 to $341,452 and the Shilo #2 to a potential of $20,740. Actual value of the leases will be increased by the equipment remaining in place on the lease.