Spreadsheet: gerald_nemec__11988__KA_assump011112
Sheet: Sheet1

 | EXHIBIT B: KEY PROJECT ASSUMPTIONS
 | General Assumptions |  |  | Comment
 | TERM
 | Model Start Value Date |  | 2001-11-09 00:00:00 | Date for model run
 | Term of Transaction (yrs) |  | 25
 | EOR
 | EOR Start Date (Re-pressurization) |  | 2002-02-01 00:00:00
 | Re-pressurization Duration (months) |  | 6
 | EOR Duration (months) |  | 48 | Injection/withdrawl cycle = 4x per year
 | EOR Stop Date |  | 2006-08-01 00:00:00
 | Bbls / Mcf |  | 6
 | Assumed API Gravity of Oil |  | 25
 | 20 year Oil Swap Price ($/Bbl) less basis from NYMEX |  | 19.55 | Market price for 20 year oil swap less basis from NYMEX
 | Oil Basis ($/Bbl) - Crude Desk |  | -2.5 | Cost of trucking oil to market
 | % Oil Revenues - EOR (net of royalty interest) |  | 0.75 | Revenue adjustment for royalty interest
 | % Oil Revenues - Storage (net of royalty interest) |  | 0.75 | Revenue adjustment for royalty interest
 | STORAGE
 | Injection Gas Basis ($/Mcf) |  | -0.11 | Cost of transport from GLO supply point to storge facility
 | Pad Gas (mmBtu) |  | 371000
 | [NAME] (mmBtu/d) |  | 10000
 | Withdraw Rate (mmBtu/d) |  | 38000
 | Max Working Capacity (mmBtu) |  | 575780
 | Upgrade on EOR gas withdraw (% mmBtu injected) |  | 1.1 | Due to enrichment of gas
 | Summer/Winter Spread Historical Value (nominal $ in 2001) |  | 0.49 | See separate sheet showing historical spreads
 | Discount rate for Historical Summer/Winter Spread Value (%) |  | 0.2 | Inflation rate used to increase historical spreads to 2001 values
 | Summer/Winter Spread Projected Value (nominal $ in 2006) |  | 0.38 | Average of PV spreads over storage term (based on ENA price curves)
 | Discount rate for Projected Summer/Winter Spread Value (%) |  | 0.2 | Discount rate used to determine 2006 value for spreads over storage term
 | CAPITAL PRICE
 | Date of Initial Capital Investment |  | 2002-02-01 00:00:00
 | Cost of Equity Captial (% per yr) |  | 0.2 | Required rate of return on invested capital
 | GAS USE COST
 | Percent Pad Gas Recoverable (balance is unrecoverable) |  | 0.5 | Unrecoverable pad gas is treated as an asset - depreciated over 25 yrs
 | Interest rate charged for the use of recoverable pad gas  (% per yr) |  | 0.2 | Cost for using recoverable pad gas
 | Capital cost for unrecoverable pad gas (% per yr) |  | 0.2 | Return required on unrecoverable gas investment
 | EOR OPERATING COSTS
 | G&A Expenses (% of Revenues) |  | [   ]% | Covers project related admin/accounting/reporting
 | Base Oil Marketing Fee ($/Bbl) |  | [     ] | Covers ENA's base cost of service (salary+ systems+ expenses)
 | Monthly Fixed LOE's EOR |  | 37.15001027972811
 | Overhead |  | 5
 | Labor/Benefits |  | 5
 | Insurance |  | 1.5
 | Chemicals / Treating |  | 0.5
 | Small Tools and Supplies |  | 0.5
 | Reparis and Maintenance |  | 1
 | Compression Rentals |  | 10
 | Compression Fuel (60 mcf/d @ curve) |  | 5.810010279728111
 | Compression Oil |  | 1.5
 | Electricity |  | 1.5
 | [NAME]
 | Engineering / Consulting |  | 1.5
 | Workover
 | [NAME]. (@ 10%) |  | 3.34 | Contingency
 | STORAGE OPERATING COSTS
 | G&A Expenses (% of Revenues) |  | [   ]% | Covers project related admin/accounting/reporting
 | Base Gas Marketing Fee ($/mmBtu) |  | [     ] | Covers ENA's base cost of service (salary+ systems+ expenses)
 | Monthly Fixed LOE's Storage |  | 17.34853165618841
 | Overhead |  | 5
 | Labor/Benefits |  | 5
 | Insurance |  | 1.5
 | Chemicals / Treating |  | 0.5
 | Small Tools and Supplies |  | 0.5
 | Reparis and Maintenance |  | 1
 | Compression Rentals |  | 10
 | Compression Fuel (60 mcf/d @ curve) |  | 6.008531656188411
 | Compression Oil |  | 1.5
 | Electricity |  | 1.5
 | [NAME]
 | Engineering / Consulting |  | 1.5
 | Workover
 | LUAF (.5 % of injection qty) |  | 0.005
 | [NAME]. (@ 10%) |  | 3.34 | Contingency
 | TAXES
 | Oil Severance Tax Rate (% of Revenues) |  | 0 | Based on GLO's ownership
 | Oil Ad Valorem Tax Rate (% of Revenues) |  | 0 | Based on GLO's ownership
 | Federal Income Tax Rate |  | 0.35 | Does not apply to GLO
 | Capital Cost Assumptions | Unit Cost | Total Cost | Comment
 | PHASE I:  EOR
1 | Land and Legal | 145 | 145 | Purchase ROW and complete permitting (?)
 | GAS INTERCONNECTS
1 | Build 8" Pipeline from HPL (~5 miles) | 1947.6175 | 1947.6175
 | Pipeline | 1034.4
 | Hot tap valves | 15.7
 | Measurement | 325
 | Job Cost @ 12% (60 days) | 25.479
 | Overhead | 136.513
 | Taxable Gross-Up @ 25% | 410.5255
0 | Build 8" Pipeline from from El Paso | 762.5
 | Pipeline | 285
 | Hot tap valves
 | Measurement | 325
 | Job Cost @ 12% (60 days)
 | Overhead
 | Taxable Gross-Up @ 25% | 152.5
0 | Build 8" Pipeline from CPS | 2953.96 | 0
 | Pipeline | 1720
 | Hot tap valves | 15.7
 | Measurement | 325
 | Job Cost @ 12% (60 days) | 42.113
 | Overhead | 225.641
 | Taxable Gross-Up @ 25% | 625.506
 | Total Gas Interconnects
 | SURFACE FACILITIES
1 | Install Surface Facilities: | 300 | 300
3 | 36"x10' Hor 2P sep
3 | 24"x10' Ver 2P sep
2 | 6'x20' Heat Treater
3 | 400 bbl oil tanks
4 | 500 bbl FG wtr tanks
1 | Triplex SWD pump and SW injection line to SWD well | 20 | 20
1 | 2-Compressor pads/facility site | 175 | 175
1 | Injection manifold | 75 | 75
1 | Production manifold | 60 | 60
1 | Install injection flowlines to 2 wells: #1,7 | 100 | 100
1 | Install productions flowlines to 6 wells: #2,3,5,6,8,9,10 | 70 | 70
0 | Compressor | 750 | 0
1 | Install gas lift injection flowlines to 2 wells: #2,5 | 15 | 15
 | Total Surface Facilities
 | SUB-SURFACE FACILITIES
 | Workovers
1 | Casing Inspection Logs-3 wells | 20 | 20
 | Injectors:
1 | Install packer and wellhead on well #1GML | 41 | 41
1 | Install packer and wellhead on well #7M | 49 | 49
 | Producer:
1 | Install GLV's and packer on well #2D | 36 | 36
1 | Install packer on well #3KG | 36 | 36
1 | Install GLV's and packer on well #5KG | 46 | 46
1 | Install packer on well #6K | 37 | 37
1 | Install packer on well #8JG | 46 | 46
1 | Install CIBP and packer on well #9JG | 45 | 45
 | SWD
1 | Reenter and convert Dugi #3 to SWD well | 45 | 45
1 | [NAME] well #10 vertical | 350 | 350
 | Total Sub-Surface Facilities
 | Total Phase I |  | 3658.6175
 | Contingency (@10%) |  | 365.86175
 | Total Phase I w/ Contingency |  | 4024.47925
 | PHASE II: GAS STORAGE
 | SURFACE FACILITIES
1 | Dehydr (50 mmcfd) | 40 | 40
1 | [NAME] | 35 | 35
1 | Automation | 15 | 15
 | ST Pipeline
1 | Plant Office | 30 | 30
 | Automation / Monitoring
1 | Plant Office | 150 | 150
9 | Wells | 15 | 135
1 | Regulatory Consulting | 20 | 20
 | Total Surface Facilities
 | Total Phase II |  | 425
 | Contingency |  | 42.5
 | Total Phase II w/ Contingency |  | 467.5
 | TOTAL PROJECT |  | 4491.97925
 | Revenue Allocation Assumptions |  |  | Comment
 | OIL REVENUE ALLOCATION (EOR PERIOD)
 | % GLO Allocation of oil revenue net of project operating costs |  | 0.2
 | % PNP Allocation of oil revenue net of project operating costs
 | % ENA at risk marketing performance payment |  | 0 | Based on marketing performance vs. agreed price index
 | OIL REVENUE ALLOCATION (STORAGE PERIOD)
 | % GLO Allocation of oil revenue net of project operating costs |  | 0.2
 | % PNP Allocation of oil revenue net of project operating costs
 | % ENA at risk marketing performance payment |  | 0 | Based on marketing performance vs. agreed price index
 | STORAGE REVENUE ALLOCATION (STORAGE PERIOD)
 | % GLO Allocation of oil revenue net of project operating costs |  | 0.2
 | % PNP Allocation of oil revenue net of project operating costs
 | % ENA at risk marketing performance payment |  | 0 | Based on marketing performance vs. agreed price index
 | HISTORICAL GAS PRICES/SPREADS
 |  | [NAME]. May/June | Feb | Spread of May/June vs. Feb
 | Year | (2001 $) | (2001 $) | (prices expressed in 2001 $ based on inflation assumptions)
 | 1980
 | 1981
 | 1982
 | 1983
 | 1984
 | 1985
 | 1986
 | 1987
 | 1988
 | 1989
 | 1990
 | 1991
 | 1992
 | 1993
 | 1994
 | 1995
 | 1996
 | 1997
 | 1998
 | 1999
 | 2000