CATHEDRAL RESOURCES
23015 Lodgepoint Drive
Katy, Texas 77494
www.cathedralresources.net
(281) 787-6138
ORBIS (R & S) Leases
Bastrop & Caldwell Co., Texas
Proved Developed Producing
And
Proved Undeveloped
Reserve Evaluation
March 19, 2007
prepared for
Mr. Rowland Carey
USA-Superior Energy Holdings, Inc.
President, CEO
Houston, Texas
By
Claud D. Pickard, P.E.
Page
EXECUTIVE SUMMARY 3
- --------- -------
DISCUSSION 5
- ----------
PROVED DEVELOPED PRODUCING (PDP) RESERVES 6
Orbis Property Estimated Reserves and NPV 7
PROVED UN-DEVELOPED (PUD) RESERVES 7
Austin Chalk 7
Geology 7
PVT Data 8
Primary Depletion Drainage Area Calculations 8
Estimated Infill PDP Reserves and NPV 10
CONCLUSIONS 11
- -----------
REFERENCES 14
- ----------
TABLES
- ------
1 EXPENSE SUMMARY 15
2 PDP RESERVES vs. EXPENSE / WELL - LEASE COUNT 16
3 TANK PVT DATA 17
4 ULTIMATE CUM. PRODUCTION & DRAINAGE AREAS 18
5 PUD RESERVES & NPVs 19
Page
FIGURES
- -------
1 ORBIS vs. WTI OIL PRICE 20
2 CATHEDRAL RESOURCES OIL & GAS PRICE HISTORY 20
3 WELL / LEASE LOCATION & STRUCTURE MAP 21
4 DIP CROSS SECTION 22
5 STRIKE CROSS SECTION A-Al 23
6 PVT REPORT (VOIGHT #7- CORE REPORT) 24
7 AUSTIN CHALK NORMALIZED PRODUCTION CURVE 25
8 AUSTIN CHALK ULTIMATE CUMULATIVE PRODUCTION MAP 25
9 AUSTIN CHALK PROPOSED PUD LOCATIONS 26
10 CASH FLOW POSITIVE AUSTIN CHALK PUD LOCATIONS 27
APPENDIX A List of Wells / Leases Requiring Proved Developed Producing
- ---------- Reserve Analysis
APPENDIX B Project Decline Curves
- ----------
APPENDIX C Project Cash Flows
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Page 2
EXECUTIVE SUMMARY
As per a Consulting Agreement (February 20, 2007) between USA-Superior Energy
Holdings, Inc. (Superior) and Cathedral Resources, an engineering evaluation was
performed by Cathedral Resources to forecast Proved Developed Producing (PDP)
reserves for properties (identified in Appendix A) operated by Orbis Energy,
Ltd. (Orbis) in Bastrop and Caldwell Counties, Texas, and Probable UnDeveloped
(PUD) reserves for the Austin Chalk Bateman Field. The effective date of the
evaluation being established as February 28, 2007.
To determine the PDP reserves for the existing producing properties, historical
production/injection data for each property was downloaded from IHS Energy or
supplied by Superior and plotted using Il-IS Energy's PowerTools program.
Hyperbolic and/or exponential decline projections of historical trends were
established to forecast the future production for each property. Overall,
monthly operating expenses for six months during 2006 from the P & L statement
were provided by Orbis, Since the expense data was not provided by lease/well,
averages were calculated to provide an expense cost by barrel of oil produced or
by producing well. Several sensitivities to expenses were developed due to
questions surrounding the actual number of active producing wells.
Oil prices (averages for all leases from the same six month period in 2006) were
compared to WTI posted prices for the same period to determine any corrections
due to gravity or transportation indicating the use of WTI posted prices without
correction is prudent for the evaluation. Two sensitivities to the February,
2007 oil price (WTI -$61 .79/STB and Historic Trend Pricing $44.50/STB) were
calculated for each well/lease expense case.
Individual economics are calculated by lease and then summed. Depending on the
number of actual operating wells, the operating expense per produced barrel of
oil and or the actual forecasted oil price, the Net PDP reserves identified in
this study vary between 80,000 and 302,000 STBO, have an un-discounted Net
Present Value (NPV) value between $10,000 and $6,312,000 and a ten percent per
annum discounted N PV (Industry Standard) between $10,000
Paqe 3
and $1,254,000. The lack of clarity around the exact expenses and actual number
of active "economic" wells is disturbing. It is highly recommended that more
accurate information is collected and used to determine actual reserves and
value for this property.
With respect to the Proved UnDeveloped reserves and valuation, geologic and
petrophysical data for the analysis was derived from Thompson's report of the
Bateman field area a core report supplied by Superior; the Voight #7 report
(Fig. 6. PVT data reported in the Voight #7 core report was validated and
expanded to provide information needed for recovery efficiency/drainage area
calculations. Voidage calculations determined the pressure depletion average
recovery factor to be 6 percent. Using decline curve analysis to determine the
ultimate cumulative oil production for each existing well and the recovery
factor of 6 percent, the average drainage area for the field is estimated at +/-
I acre with a maximum of 3.7 acres. The low permeability of the Austin Chalk
(0.5md) will reduce the overall recovery efficiency resulting in a larger
drainage area for each well, and using a 50 percent loss of efficiency increases
the average drainage radius to almost 2 (Two) acres with a maximum of 7.3 acres.
To verify these calculations, a composite production curve for all wells within
the Bateman Austin Chalk field was developed by normalizing the production
starting date which indicates an average ultimate recovery of +7- 12,500 STBO
and provides an average drainage radius of 1.25 acres with 50 percent recovery
sensitivity of 2.5 acres. Rough calculations indicate the Bateman field covers
+7- 525 acres with +/- 50 wells providing a current development of +/- 10.5 acre
spacing. The average drainage area of 1-2 acres discussed earlier would appear
to support the ability to infill drill on 5 acre spacing.
A map of ultimate cumulative production by well shows a definite trend of
increasing recovery from West to East (similar to the dip of the field). The
trend suggests a potential "Gravity Drainage" component or a thinning of pay
across the crest of the structure. In either case, infill locations on the
Western side of the field will probably have lower recoveries and value. To
confirm the apparent trend, an average ultimate recovery and normalized decline
for each infill location was determined. Including an infill development cost of
$200,000, un-discounted and 10% discounted cash flows were developed for each
location. Only seven of the thirteen identified locations contained reserves in
excess of +7- 11,750 STBO (which is associated with
Page 4
positive un-discounted cash flows). Cumulatively, the seven locations have a
positive undiscounted NPV of $436,400. However, none of the infill locations
have positive 10% discounted NPVs which indicate the PUD reserves are very risky
and highly price sensitive. For this reason, none of the PUD locations can be
recommended for development.
DISCUSSION
----------
As per Consulting Agreement (February 20, 2007) between USA-Superior Energy
Holdings, Inc. (Superior) and Cathedral Resources, an engineering evaluation was
performed by Cathedral Resources to forecast Proved Developed Producing (PDP)
reserves for properties (identified in Exhibit A) operated by Orbis Energy, Ltd.
(Orbis) in Bastrop and Caldwell Counties, Texas, and Probable UnDeveloped (PUD)
reserves for the Austin Chalk Bateman Field. All information, including but not
limited to:
o Mark E. Thompson's' report of the "Stratigraphy of the Dale Lime and its
Relation to Structure at Bateman Field, Bastrop Co., Texas",
o Sporadic geophysical data including the Wyvonne Voight #7 Core Analysis,
o Individual well water injection volumes,
o Lease data and maps,
o Over-all lease operating expenses, and
o Working and Royalty interests,
provided by Superior were deemed "accurate" and by default were not verified or
modified for the study. Production data by lease/well were derived from iHS
Energy's production database. The reserves derived in this study are classified
as "Proved" and are judged with reasonable certainty to be recoverable in the
future using current technologies with due consideration to sensitivities in
operating expenses and actual commodity pricing. However, since forecasting
future oil and/or gas production rates is an interpretive and subjective
process, Cathedral Resources makes no warranty as to the actual future
performance of the evaluated properties.
Page 5
Cathedral Resources is an independent petroleum engineering firm with respect to
Superior or Orbis as defined in the SPE's "Standard Pertaining to the Estimating
and Auditing of Oil and Gas Reserves", and owns no interest nor is employed by
Superior or Orbis on a retainer or contingent basis.
PROVED DEVELOPED PRODUCING (P1W) RESERVES
-----------------------------------------
The oil prices (averages for all leases from the same six month period in 2006)
were compared to WTI posted prices for the same period to determine any
corrections due to gravity or transportation. Figure 1 is a comparison of the
prices and indicates that the use of WTI posted prices without correction is
prudent for the evaluation. Two sensitivities to oil price for each well/lease
expense case were conducted. The first sensitivity uses the closing WTI price
posted for February, 2007 $61.79); the second, uses a projected oil price
($44.50) based on trends and Gas (Barrel Oil Equivalent -- using 6,000 to I
SCF/STB) values (Fig. 2). The two price scenarios showcase the sensitivity of
the project to oil price.
Historical production/injection data for each property was downloaded from IHS
Energy or supplied by Superior and plotted using IHS Energy's PowerTools
program. Hyperbolic and/or exponential decline projections of historical trends
were established to forecast the future production for each property. For each
economic case, the individual production declines for each well/lease were used
in conjunction with the parameters shown on Tables I through 4 and Figures 1 and
2 to develop cash flows for each lease. This data was summed for each economic
case to develop cumulative production decline curves and summary cash flows. For
each economic case, the cumulative production decline curves are shown in
Appendix B and summary remaining reserves, cash flows and net present values are
shown on the cash flow forecasts in Appendix C. The monthly operating expenses
shown on Table I are a summary of all leases each of six months during 2006 from
the P & L statement provided by Orbis. For evaluation purposes, it was assumed
that future plug and abandonment expenses will be offset by the equipment
salvage value. As stated earlier, individual economics are calculated by lease
and then summed. Since the expense data was not provided by lease/well, averages
were calculated
Page 6
(Table 1) to provide an expense cost by barrel of oil produced or by producing
well. Using the 97 wells identified as producing by iHS Energy, expenses average
$400/well/month. Using the 35 wells identified as producing by Orbis/Superior,
expenses average $1,300/well/month. Finally, using the average 1190 STBO/month,
the expenses average $39.75/STBO.
Orbis Property Estimated PDP Reserves and NPV
- ---------------------------------------------
In summary (Table 2), depending on the number of actual operating wells, the
operating expense per produced barrel of oil and or the actual forecasted oil
price, the Net PDP reserves identified in this study vary between 80,000 and
302,000 STBO, have an un-discounted Net Present Value (NPV) value between
$10,000 and $6,312,000 and a industry standard ten percent per annum discounted
NPV between $10,000 and $1,254,000. The lack of clarity around the exact
expenses and actual number of active "economic" wells is disturbing. It is
highly recommended that more accurate information is collected and used to
determine actual reserves and value for this property.
AUSTIN CHALK
PROVED UNDEVELOPED (PUD) RESERVES
---------------------------------
Austin Chalk Geology
- --------------------
A structure map1 (Fig. 3) and a dip section1 (Fig. 4) across the Bastrop Field
were provided by Superior. Cross-section A-Al (Fig. 5) is a Southwest-Northeast
trend slice through the Orbis properties was generated by using iHS Energy
formation tops and GOOGLE EARTH surface elevations. The Austin Chalk as detailed
by Thompson' "is 300 feet thick. The oil is present in the upper 180 feet within
porous zones up to 50 feet thick. While individual Austin Chalk porosity zones
cannot be correlated on a foot --by-foot basis between wells, the porosity zones
are present within distinct overall stratigraphic intervals, and therefore are
probably connected." A quick review of the cross sections included in Thompson's
report', indicated gross productive thicknesses between 30 and 50 feet thick.
These values were confirmed from a core report
Page 7
supplied by Superior; the Voight #7 report (Fig. 6) indicates a layered porous
oil column totaling 46 feet. For the purposes of determination and plotting of
drainage areas for each Austin Chalk producer in the area, an average oil column
thickness of 40 feet was used.
Austin Chalk porosity in the field area as detailed by Thompson' "is very good
15 to 20%, the extremely low permeability of less than 0.5 md necessitates a
large sand fracture stimulation for sustained commercial production." Using the
same core report referred to earlier; the Voight #7 report (Fig. 6) indicates an
average oil column porosity of 18.7%. For the purposes of determination and
plotting of drainage areas for each Austin Chalk producer in the area, an
average porosity of 17.5% was used.
The Voight #7 report (Fig. 6) also indicates a connate water saturation of 33%,
an average initial water saturation of 39%.
Austin Chalk PVT Data
- ---------------------
PVT data reported in the Voight #7 core report includes an oil gravity of
39(degree) API, initial Oil Formation Volume Factor (Boi) of 1.13 RB/STB, and an
initial producing Gas Oil Ratio (GOR) of 160 SCF/STB. Assuming a normal pressure
gradient of 0.45 psi/ft. the initial reservoir pressure is estimated at (2300ft
* 0.45) `-~ 1050 psi/ With the initial reservoir pressure of 1050 psi, and an
API gravity of 39(degree), Ryder Scotts TANK4 model using Standings2 correlation
calculates (Table 3) an initial reservoir Formation Volume Factor (Boi) of 1 .13
RB/STB which repeats the core reported numbers. TANK using Standings correlation
(Table 4) also calculates an initial an initial solution GOR (Rsi) = 277 SCF/STB
which is almost double the reported produced GOR of 160 SCF/STB. The difference
may represent the amount of non-produced gas released into the formation during
production.
Austin Chalk Primary Depletion Drainage Area Calculations
- ---------------------------------------------------------
Voidage calculations require a known reservoir pressure for the point of
depletion being evaluated. An average pressure across the drainage area was
estimated using an estimated flowing sand face pressure with a drainage boundary
reservoir pressure equal to the initial reservoir pressure. Since the wells are
producing via rod pumps and are pounding fluid, the
Page 8
flowing sand face pressure was estimated at 0 psi and the boundary reservoir
pressure was estimated to be equal to the initial reservoir pressure of 1050
psi. Using these two data points, an average drainage area pressure can be
calculated using:
Average Drainage Area Pressure = (Initial Reservoir Pressure (Pi) +
Flowing Pressure) /2 = (1050 psi + 0 psi)/2~525 psi.
With a known current drainage area reservoir pressure of 525 psi associated with
depletion, a solution drive primary recovery can be calculated by:
Recovery Factor (RF)3 = ((t3oi-- l3of)/(Bof))
Where Boi @ 1050 psi = 1.13 RB/STB
Bof@ 525 psi = 1.06608 RB/STB
RF = ((1.13-I.06608)/(l.06608) = 0.06 6%
Reservoir drainage calculations also require cumulative production by well. To
minimize the possibility of infill drilling encountering established drainage
areas, ultimate cumulative production volumes need to be used for each well.
Decline curve analysis was used to determine the ultimate cumulative oil
production for each existing well. Table 5 details the ultimate cumulative
production shown in Figure 8. Using the reservoir and PVT data discussed
earlier, the 6% recovery factor, and ultimate cumulative oil production
estimates, drainage areas were calculated for each well in the Bateman Austin
Chalk field (Table 5). With an average ultimate production of +/- 9,000 STBO,
the average drainage area for the field is estimated at +7- 1 acre with a
maximum of 3.7 acres. These calculations inherently assume reservoir
permeability is sufficient to allow complete pressure depletion without loss of
energy due to friction and viscosity effects and would provide minimum drainage
radii. The low permeability of the Austin Chalk (0.5md) will reduce the overall
recovery efficiency resulting in a larger drainage area for each well. As a
sensitivity, assuming a 50 percent loss of efficiency increases the average
drainage radius to almost 2 (Two) acres with a maximum of 7.3 acres.
A composite production curve for all wells within the Bateman Austin Chalk field
was developed by normalizing the production starting date (Fig. 7). The
normalized decline indicates
Page 9
an average ultimate recovery of +/- 12,500 STBO and provides an average drainage
radius of 1.25 acres with 50 percent recovery sensitivity of 2.5 acres.
Rough calculations indicate the Bateman field covers +/- 525 acres with +7- 50
wells providing a current development of +/- 10.5 acre spacing. The average
drainage area of 1-2 acres discussed earlier would appear to support the ability
to infill drill on 5 acre spacing. However, caution must be stressed with regard
to using these averages. Figure 8 is a map of ultimate cumulative production by
well. The map shows a definite trend of increasing recovery from West to East
(similar to the dip of the field). The trend suggests a potential "Gravity
Drainage" component (when considering the field cross section (Fig.4) and the
delta between the initial and produced GOR5); or, this trend may suggest a
thinning of pay across the crest of the structure. In either case, infill
locations on the Western side of the field will probably have lower recoveries
and value. To confirm the apparent trend, an average ultimate recovery for each
infill location was determined by averaging the nearest direct line offset
producers identified on Figure 9.
Austin Chalk Estimated Infill PUD Reserves and NPV
- --------------------------------------------------
To provide an economic evaluation of each infill location (Fig. 9), the
normalized decline was modified (initial production rate adjusted) to provide
the appropriate expected ultimate cumulative production. As in the PDP
evaluation, it was assumed that future plug and abandonment expenses will be
offset by the equipment salvage value. Including an infill development cost of
$200,000, an oil price of $61 .97/BO, an expense rate of $30/BO, as well as,
working interest of 100% and net royalty interest of 80%, un-discounted and 10%
discounted cash flows were developed for each location.
Table 6 provides a summary of the PUD infill drilling location reserves and
NPVs. The seven PUD locations (identified on Table 6) with reserves in excess of
+/- 11,750 STBO that have positive un-discounted cash flows are located on
Figure 10. Cumulatively, the seven locations have a positive un-discounted NPV
of $436,400. However, none of the infill locations have positive 10% discounted
NPVs which indicate the PUD reserves are very risky and highly price sensitive.
For this reason, none of the PUD locations can be recommended for development.
Page 10
CONCLUSIONS
-----------
As per a Consulting Agreement (February 20, 2007) between USA-Superior Energy
Holdings, Inc. (Superior) and Cathedral Resources, an engineering evaluation was
performed by Cathedral Resources to forecast Proved Developed Producing (PDP)
reserves for properties (identified in Exhibit A) operated by Orbis Energy, Ltd.
(Orbis) in Bastrop and Caldwell Counties, Texas, and Probable UnDeveloped (PUD)
reserves for the Austin Chalk Bateman Field. The effective date of the
evaluation being established as February 28, 2007.
The following facts and conclusions were used and/or developed during the
evaluation of the Orbis property PDP reserves using decline curve analysis
project:
o Current average production for the properties under review is 1190 STBO per
month.
o Average gross operation expenses for the properties total+/- $46,600 per
month.
o WTI posted prices without correction is prudent for the base case
evaluation,
o A low oil price sensitivity of $44.50 was established from historic trend
prices and as a Barrel of Oil equivalent gas price,
o Lack of clarity around exact expenses and actual number of active
"economic" wells prevents calculation of an exact remaining reserve and
NPV. The lack of a definite producing well/lease count and associated
operating expenses by well/lease prevents the calculation of exact
remaining reserves and NPV. Therefore:
o Gross PDP reserves identified in this study vary between 1,000 and 384,000
STBO,
o Net PDP reserves identified in this study vary between 800 and 302,000
STBO,
o Un-discounted (NPV of existing production varies between $10,000 and
$6,312,000,
o Discounted NPV (at ten percent per annum) varies between $10,000 and
$1,254,000.
o Once more accurate well count and operating expense information becomes
available, more definitive reserves and valuations can be determined.
Page 11
The following facts and conclusions were used and/or developed during the
evaluation of the ORB IS/Bateman Field Austin Chalk PUD reserves.
o Current development of the Bateman Austin Chalk field averages 10.5 acre
spacing
o Average reservoir porosity is 17.5 percent o Average reservoir thickness is
40 feet.
o Average reservoir initial water saturation is 39 percent
o Using a normal pressure gradient, the original/undrained reservoir pressure
is estimated to be 1050 psia.
o Current average pressure within established drainage areas is estimated to
be +7- 575 psia,
o Reservoir contains 39(degree)API gravity crude,
o Initial reservoir formation oil volume factor was/is 1 .13 RB/STB.
o Initial reservoir solution gas-oil ratio was/is 267 SCF/STB.
o Using estimated initial and ultimate average reservoir pressures, ultimate
average recovery for established drainage areas is estimated to be 6
percent of the Original Oil In Place (OOIP).
o Using offset producing data from decline curve analysis, ultimate average
recovery for established drainage areas is estimated to be 133 to 36,800xx
STBO. The average ultimate recovery from decline curve analysis is 9,100
STBO. Drainage areas from decline curve analysis average 0.9 acres with a
maximum of 1 .9 acres.
o With normalized production data and decline curve analysis, ultimate
average recovery for infill development is estimated to be 12,500 STBO. By
adjusting the normalized decline for average offset recovery and initial
rates, the reserves varied between 6,400 and 1 7,700 STBO. Drainage areas
for the normalized drainage areas average 0.6 acres with a maximum of 2.5
acres.
o Infill development cost of each location is estimated to be $200,000
($50,000 Tangible and $150,000 Intangible).
o Average gross operation expenses total $30.O0/STBO
Page 12
o As with the PDP reserve study, WTI posted prices without correction is
prudent for the base case evaluation, therefore,
o Net PDP reserves identified in this study vary between 5,100 and 14,200
STBO,
o Un-discounted (NPV of existing production varies between -$90,000 and
$105,000 per well,
o All discounted NPV (at ten percent per annum) for all proposed locations
carried negative values,
o Negative 10% discounted NPVs indicate the PUD reserves are uneconomic,
therefore, none of the PUD locations can be recommended for development.
Thank you for the opportunity to provide you with this evaluation of your
property. Please contact us at your convenience if you have any questions
concerning this report.
Sincerest Regards,
/s/Claud D. Pickard, P.E.
- ------------------------
Claud D. Pickard, P.E.
(Texas #92986)
Cathedral Resources
www.cathedralresources.net
REFERENCES
----------
1. Thompson, M.E: "Stratigraphy of the Dale Lime and its Relation to Structure
at Bateman Field, Bastrop County, Texas", Contributions to the geology of
South Texas, 1986,, South Texas Geology Society, San Antonio, Texas,
Wilford Lee Stapp, 1986, OCLC number of 19459762, pg 356-367
2. Standing, M.B.: "Volumetric and Phase Behavior of Oil Field Hydrocarbon
Systems, (New York: Reinhold Publishing Corporation, 1952), pocket on back
cover.
3. Craft, B.C. & Hawkins, M. F. : "Applied Petroleum Reservoir Engineering",
Prentice-Hall, 1959, pg 110, eq 3.9
4. TANK, A General Purpose Material Balance Reservoir Simulator, Ryder Scott
Company, L.P. by Steve Sills, Mike Perry et al, Version 2.16, December
2002.
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