!***************************************************************

!from wlcontrol.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) Run Control File

%

%*****************************************************************************

%

%

% Select resources to evaluate in timing model

% Oil Only = 1

% Gas Only = 2

% Oil and Gas = 3

@

3

% Number of wells in an exploration drilling package

@

20

% Number of drilling packages per play per year

@

15

% Number of years BEFORE ECONOMIC LIFE in which EOR is considered?

@

40

% Number of years AFTER ECONOMIC LIFE in which EOR is considered?

@

40

% Number of years BEFORE ECONOMIC LIFE in which ASR is considered?

@

5

% Number of years AFTER ECONOMIC LIFE in which ASR is considered?

@

5

% Print economic proforma & cost summary for each project? (Y/N)

@

N

% Print exploration package output? (Y/N)

@

N

% Print debug files?(Y/N)

@

Y

% SELECT EXPLORATION MODELS TO RUN

% NONE = 0

% CONVENTIONAL = 1

% UNCONVENTIONAL = 2

% BOTH = 3

@

3

% variable value, variable name, description/unit, purpose

@

90.00 !baseoil - Oil Price ($/Bbl) used to normalize tangible, intangible, 

and other costs. Used in econ_cost.

50.00 !cutoil - Cut off oil price ($/Bbl) above which 

(oilprice(iyr)-baseoil)/baseoil is the adjustment term.

% Below that price, adjustment term = (cutoil-baseoil)/baseoil

%

@

4.00 !basegas - Gas Price ($/Mcf) used to normalize tangible, intangible, 

and other costs. Used in econ_cost.

%

@

NPV !RANKVAL choice of ROR, NPV, INV - ranking criteria for the projects

%

%

% Aggregation Level for National and Regional Reports

% WELL CLASS = 1
% FUEL TYPE = 2

% WELL CLASS & FUEL TYPE = 3

@

3

%

% Start year for analysis (must be greater than or equal to the first year in the price 

track (wlprice.txt).

@

2012

%

% Number of years of analyis (maximum = 45)

@

28

%

% Write the detailed exploration probability report? (YES = 1)

@

0

%

% Write the detailed economics report for unconventional exploration? (Y/N)

@

N

%

% Maximum number of drywells per play per year (unconventional exploration only)

@

250

%

% Discovery Development Lag (number of years between discovery and first production)

@

1

%

% CO2 EOR Production Lag (number of years between first CO2 purchase and production)

@

1

%

% Volumetric EOR Cutoff Percent (if (SOC-SORW)<VEORCP, Project is Eligible for EOR)

@

20.0

%

% Write the economic prescreening reports? (Y/N)

@

N

%

% 2007 historical daily production rates (regional)

% region 1 region 2 region 3 region 4 region 5 region 6 

total

%

% 86.14 554.75 324.86 919.90 507.61 561.43 

2954.7 !oil MBbl/Day

% 0.47 7.10 4.81 1.42 0.34 0.26 

16.19 !conventional gas Bcf/Day

% 0.30 0.38 0.28 0.0 4.27 0.0 

5.23 !coalbed methane gas Bcf/D

% 0.92 0.07 0.19 1.89 0.11 0.0 

3.18 !shale gas Bcf/day

% 0.98 6.08 1.74 0.79 7.03 0.0 

16.62 !tight gas Bcf/day

% TEMPORARY -- remove after revision to data (keep HPDI reserviors and apply average 

characteristics from NRG)

% region 1 region 2 region 3 region 4 region 5 region 6 

total

% 108.14 584.75 364.86 989.90 567.61 561.43 

2954.7 !oil MBbl/Day

% 0.47 9.29 6.18 1.42 1.16 0.26 

16.19 !conventional gas Bcf/Day

% 0.34 0.46 0.34 0.0 4.67 0.0 
5.81 !coalbed methane gas Bcf/D

% 1.25 0.11 0.57 2.85 0.23 0.0 

5.01 !shale gas Bcf/day

% 1.42 7.77 2.49 0.91 7.81 0.0 

19.26 !tight gas Bcf/day

%

% 128.14 584.75 364.86 989.90 567.61 561.43 

2954.7 !oil MBbl/Day

% 0.44 7.10 4.60 0.27 0.34 0.26 

13.01 !conventional gas Bcf/Day

% 0.30 0.38 0.28 0.0 4.27 0.0 

5.23 !coalbed methane gas Bcf/D

% 0.95 0.07 0.40 3.04 0.11 0.0 

4.57 !shale gas Bcf/day

% 0.98 7.77 2.49 0.79 8.01 0.0 

20.04 !tight gas Bcf/day

% 2008 historical daily production rates (regional)

% region 1 region 2 region 3 region 4 region 5 region 6 

total

%

% 87.14 534.41 350.25 938.55 540.96 553.55 

3004.85 !oil MBbl/Day

% 0.76 4.49 4.64 2.73 0.34 0.23 

13.19 !conventional gas Bcf/Day

% 0.27 0.54 0.25 0.00 3.74 0.00 

4.81 !coalbed methane gas Bcf/D

% 0.63 0.08 1.26 4.41 0.17 0.00 

6.56 !shale gas Bcf/day

% 1.16 6.12 1.90 0.82 8.75 0.00 

18.76 !tight gas Bcf/day

% 2010 historical daily production rates (regional)

% region 1 region 2 region 3 region 4 region 5 region 6 

total

%

% 85.00 528.00 379.00 1011.00 688.00 516.00 

3207.00 !oil MBbl/Day

% 0.76 4.49 4.64 2.73 0.34 0.23 

13.19 !conventional gas Bcf/Day

% 0.27 0.54 0.25 0.00 4.74 0.00 

5.81 !coalbed methane gas Bcf/D

% 1.25 0.08 1.26 5.41 0.17 0.00 

6.56 !shale gas Bcf/day

% 1.16 6.12 1.90 0.82 8.75 0.00 

18.76 !tight gas Bcf/day

% 2012 historical daily production rates (regional)

% region 1 region 2 region 3 region 4 region 5 region 6 

total

@

95.00 950.00 502.00 1489.00 1122.00 503.00 

3207.00 !oil MBbl/Day

0.978 1.496 4.027 1.130 1.036 0.119 

8.79 !conventional gas Bcf/Day

0.353 0.271 0.164 0.071 3.882 0.00 

4.74 !coalbed methane gas Bcf/D

4.140 8.033 3.764 5.685 0.125 0.00 

21.75 !shale gas Bcf/day

0.517 5.449 1.540 0.693 7.712 0.00 

15.91 !tight gas Bcf/day

365.0 !number of days

%

%

% 2007 historical proved reserves

% oil (Bbbl) AD Gas (Tcf) Dry Conv (Tcf) Dry CBM (Tcf) Dry Tight (Tcf) Dry 

Shale (Tcf)

%

% 14.21 15.888 62.873 18.498 84.764 
26.884

% 2008 historical proved reserves

% oil (Bbbl) AD Gas (Tcf) Dry Conv (Tcf) Dry CBM (Tcf) Dry Tight (Tcf) Dry 

Shale (Tcf)

@

14.21 15.507 59.070 21.875 89.902 

21.846

%

%

% Adjustments to historical inferred reserves

% region 1 region 2 region 3 region 4 region 5 region 6 

total

@

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 !crude oil (BBbl)

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 !associated dissolved Gas (Tcf)

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 !conventional shallow non-associated gas (Tcf)

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 !conventional deep non-associated gas (Tcf)

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 !tight gas (Tcf)

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 !coalbed methane (Tcf)

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 !shale gas (Tcf)

%

%%%%

!*****************************************************************************

!from wltechnology.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS)

% Technology Control File

%

% Contains the default and impact specific values for the technology, economic,

% access, and filter levers. FORMATTED FILE

%

% File structure: first column contains the default values. The subsequent

% columns contain the OVERWRITE values for each impact. All other values for

% the impact are set to the default values. NOTE: THE IMPACTS MUST BE MUTUALLY

% EXCLUSIVE. AT MOST, ONLY ONE IMPACT WILL BE APPLIED TO A RESERVOIR.

%

% Lever Order: Lever Description: Value Format:

% F-1 to F-26 Process Filters Character*1 (Y or N)

% F-24 to F-31 Petrophysical Parameter Filters Real f10.1

% F-32 to F-38 Regional Filters Character*1 (Y or N)

% F-39 to F-88 State Filters Character*1 (Y or N)

% F-89 to F-91 Resource Access Filters Character*1 (Y or N)

% T-1 to T-6 Technology Penetration Curve Levers T-1,T-2,T-4 : Integer i10, 

Others : Real f10.2

% T-7 to T-23 Technology Parameter Levers Real f10.3

% E-1 to E-21 Cost Change Levers Real f10.3

% E-22 to E-36 Cost to Apply Levers Real f10.3

%

% V-1 to V-41 Technology Factor Variables Unformatted

%

%*****************************************************************************

%

% Number of impacts (excluding Default)

@

17

%xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx1

234567890x1234567890x1234567890x1234567890

%% primary co2 steam 

polymer infill profmod horcont horprof undcoil undcgas unctoil 
und tht unt cbm und shl dev shl dev tht dev cbm

% 

Impact Values

% Lever Lever Description Default 1 3 

4 5 6 7 8 9 10 16 

17 18 19 20 21 22 23

@

F - 1 Filter Oil Decline Curve Y N N 

N N N N N N N N 

N N N N N N N

F - 2 Filter Primary Production(Undisc.)(Oil&Gas) Y Y N 

N N N N N N Y N 

N N N N N N N

F - 3 Filter Waterflooding Y N N 

N N N N N N N N 

N N N N N N N

F - 4 Filter CO2 Flooding Y N Y 

N N N N N N N N 

N N N N N N N

F - 5 Filter Steam Flooding Y N N 

Y N N N N N N N 

Y N N N N N N

F - 6 Filter Polymer Flooding Y N N 

N Y N N N N N N 

N N N N N N N

F - 7 Filter Infill Drilling Y N N 

N N Y N N N N N 

N N N N N N N

F - 8 Filter Profile Modification Y N N 

N N N Y N N N N 

N N N N N N N

F - 9 Filter Horizontal Continuity Y N N 

N N N N Y N N N 

N N N N N N N

F - 10 Filter Horizontal Profile Y N N 

N N N N N Y N N 

N N N N N N N

F - 11 Filter Undiscovered Conventional Oil Y N N 

N N N N N N Y N 

N N N N N N N

F - 13 Filter Conventional Radial Flow Gas Y N N 

N N N N N N N N 

N N N N N N N

F - 14 Filter Water Drive Y N N 

N N N N N N N N 

N N N N N N N

F - 15 Filter Tight Sands Y N N 

N N N N N N N N 

N N N N N Y N

F - 16 Filter Wet Coal/Shale Gas Y N N 

N N N N N N N N 

N N N N N N N

F - 17 Filter Dry Coal/Shale Gas Y N N 

N N N N N N N N 

N N N N N N N

F - 18 Filter Undiscovered Conventional Gas Y N N 

N N N N N N N Y 

N N N N N N N

F - 12 Filter Undiscovered Unconventional Oil Y N N 

N N N N N N N N 

Y N N N N N N

F - 19 Filter Undiscovered Tight Gas Y N N 

N N N N N N N N 

N Y N N N N N

F - 20 Filter Undiscovered Coal Bed Methane Y N N 

N N N N N N N N 
N N Y N N N N

F - 21 Filter Undiscovered Shale Gas Y N N 

N N N N N N N N 

N N N Y N N N

F - 22 Filter Developing Shale Gas Y N N 

N N N N Y N N N 

N N N N Y N N

F - 23 Filter Developing Tight Gas Y N N 

N N N N N N N N 

N N N N N Y N

F - 24 Filter Developing Coalbed Methane Y N N 

N N N N N N N N 

N N N N N N Y

F - 25 Filter Oil Reservoirs Y Y Y 

Y Y Y Y Y Y Y N 

Y N N N N N N

F - 26 Filter Gas Reservoirs Y N N 

N N N N N N N Y 

N Y Y Y Y Y Y

F - 24 Minimum Depth 0.0 0.0 0.0 

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

0.0 0.0 0.0 0.0 0.0 0.0 0.0

F - 25 Maximum Depth 100000.0 100000.0 100000.0 

100000.0 100000.0 100000.0 100000.0 100000.0 100000.0 100000.0 100000.0 

100000.0 100000.0 100000.0 100000.0 100000.0 100000.0 100000.0

F - 26 Minimum API Gravity 0.0 0.0 0.0 

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

0.0 0.0 0.0 0.0 0.0 0.0 0.0

F - 27 Maximum API Gravity 70.0 70.0 70.0 

70.0 70.0 70.0 70.0 70.0 70.0 70.0 70.0 

70.0 70.0 70.0 70.0 70.0 70.0 70.0

F - 28 Minimum Permeability 0.0 0.0 0.0 

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

0.0 0.0 0.0 0.0 0.0 0.0 0.0

F - 29 Maximum Permeability 5000.0 5000.0 5000.0 

5000.0 5000.0 5000.0 5000.0 5000.0 5000.0 5000.0 5000.0 

5000.0 5000.0 5000.0 5000.0 5000.0 5000.0 5000.0

F - 30 Minimum Production Rate (BOE/Day) 0.0 0.0 0.0 

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

0.0 0.0 0.0 0.0 0.0 0.0 0.0

F - 31 Maximum Production Rate (BOE/Day) 100000.0 100000.0 100000.0 

100000.0 100000.0 100000.0 100000.0 100000.0 100000.0 100000.0 100000.0 

100000.0 100000.0 100000.0 100000.0 100000.0 100000.0 100000.0

F - 32 Filter Region 1: East Coast Y Y Y 

Y Y Y Y Y Y Y Y 

Y Y Y Y Y Y Y

F - 33 Filter Region 2: Gulf Coast Y Y Y 

Y Y Y Y Y Y Y Y 

Y Y Y Y Y Y Y

F - 34 Filter Region 3: Midcontinent Y Y Y 

Y Y Y Y Y Y Y Y 

Y Y Y Y Y Y Y

F - 35 Filter Region 4: Southwest Y Y Y 

Y Y Y Y Y Y Y Y 

Y Y Y Y Y Y Y

F - 36 Filter Region 5: Rocky Mountain Y Y Y 

Y Y Y Y Y Y Y Y 

Y Y Y Y Y Y Y

F - 37 Filter Region 6: West Coast Y Y Y 

Y Y Y Y Y Y Y Y 

Y Y Y Y Y Y Y

F - 38 Filter Region 7: Northern Great Plains Y Y Y 

Y Y Y Y Y Y Y Y 

Y Y Y Y Y Y Y

T - 1 First Year of Technology Commercialization 2010 2010 2010 

2010 2010 2010 2010 2010 2010 2010 2010 
2010 2010 2010 2010 2010 2010 2010

T - 2 Number of Years to Commercialize 0 14 15 

13 15 14 14 14 15 14 15 

14 15 14 15 14 14 13

T - 3 Ultimate Market Penetration (Fraction) 0.000 0.600 0.610 

0.600 0.610 0.590 0.590 0.600 0.600 0.600 0.610 

0.600 0.610 0.600 0.610 0.610 0.610 0.600

T - 4 Market Pen.Curve:1-cnvx,2-cncv,3-sgmd,4-lnr 1 2 4 

3 2 4 2 4 2 2 4 

2 4 4 4 4 4 4

T - 5 Probability of Successful R&D (Fraction) 0.000 0.480 0.510 

0.490 0.500 0.500 0.510 0.510 0.490 0.480 0.480 

0.480 0.490 0.490 0.480 0.480 0.480 0.500

T - 6 Probability of Implementation (Fraction) 0.000 0.440 0.430 

0.440 0.440 0.440 0.420 0.440 0.450 0.440 0.450 

0.440 0.450 0.430 0.450 0.450 0.460 0.440

T - 7 Change in Drilling Failure Rt (Fraction) 0.000 0.030 0.030 

0.030 0.030 0.030 0.030 0.030 0.030 0.030 0.030 

0.030 0.030 0.030 0.030 0.030 0.030 0.030

T - 8 Change in Exploration Success Rate (Frac) 1.000 1.030 1.030 

1.030 1.030 1.030 1.030 1.030 1.030 1.030 1.030 

1.030 1.030 1.030 1.030 1.030 1.030 1.030

T - 9 Pay Continuity Enhancement 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.420 

1.000 1.500 1.000 1.000 1.000 1.500 1.000

T - 10 Vertical Skin Factor 2.500 2.500 2.500 

2.500 2.500 2.500 2.500 2.500 2.500 2.500 2.500 

2.500 2.500 2.500 3.000 3.000 2.500 3.000

T - 11 Continuity Increase 1.000 1.000 1.000 

1.000 1.000 1.010 1.000 1.023 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

T - 12 Productivity Index Increase 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

T - 13 Recovery Efficiency Increase 1.000 1.080 1.000 

1.090 1.000 1.000 1.000 1.000 1.000 1.080 1.070 

1.080 1.050 1.050 1.070 1.080 1.040 1.050

T - 14 Volumetric Sweep Efficiency Increase 1.000 1.000 1.042 

1.000 1.060 1.000 1.060 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

T - 15 Injection Rate Increase (Fraction) 1.000 1.000 1.380 

1.000 1.123 1.000 1.000 1.250 1.020 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

T - 16 Mobility Ratio Reduction (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

T - 17 DUMMY TECH 1 - WAG RATIO -APPLIED TO CO2EOR 1.500 1.500 2.170 

1.500 1.500 1.500 1.500 1.500 1.500 1.500 1.500 

1.500 1.500 1.500 1.500 1.500 1.500 1.500

T - 18 DUMMY TECH 2 - RECVRY limit EFF:PRIMARY OIL 0.450 0.450 0.450 

0.450 0.450 0.450 0.450 0.450 0.450 0.450 0.450 

0.450 0.450 0.450 0.450 0.450 0.450 0.450

T - 19 DUMMY TECH 3 - VERTICAL SKIN FACTOR FOR GAS 3.000 3.000 3.000 

3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 

3.000 3.000 3.000 3.000 3.000 3.000 3.000

T - 20 DUMMY TECH 4 - FRACTURE HALF LENGTH (FT) 1000.000 1000.000 1000.000 

1000.000 1000.000 1000.000 1000.000 1000.000 1000.000 1000.000 0.000 

0.000 1000.000 1000.000 1000.000 1000.000 1000.000 1000.000

T - 21 DUMMY TECH 5 - FRACTURE CONDUCTIVITY (FT) 1000.000 1000.000 1000.000 

1000.000 1000.000 1000.000 1000.000 1000.000 1000.000 1000.000 1000.000 

0.000 1000.000 1000.000 5350.000 6200.000 1000.000 1000.000

T - 22 CO2 Derating Factor 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

T - 23 Oil Derating Factor 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 
1.000 1.000 1.000 1.000 1.000 1.000 1.000

T - 24 Rsrvr Char (0-No,Other-cost/BOE) 0.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 1 Change in Drilling Cost (Fraction) 1.000 0.960 1.060 

1.060 1.060 1.060 0.960 1.050 1.050 0.960 1.070 

0.960 1.070 1.060 1.070 1.050 1.050 1.060

E - 2 Change in Stimulation Cost (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 3 Change in Completion Cost (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 4 Chng in Faclty Cost (oil and Gas)(Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 4 Change in Secondary Conversion Cost (Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 5 Change in Injector Conversion Cost (Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 6 Change in Facilities Upgrade Cost (Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 7 Change in Workover Cost (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 8 Chng in Prod Wtr Handling Plnt Cost (Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 9 Chng in Chemical Handling Plant Cost(Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 10 Change in Polymer Handling Plant Cost(Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 11 Chng in CO2 Injtn/Recyle Plant Cost (Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 12 Change in Steam Generation Costs (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 13 Change in Fixed Annual O & M Costs (Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 14 Change in Variable Annual O&M Costs (Frac) 1.000 0.960 0.960 

0.960 0.960 1.000 1.000 1.000 1.000 0.960 1.000 

0.960 1.000 1.000 1.000 1.000 1.000 1.000

E - 15 Change in G & A Costs (Fraction) 1.000 1.000 1.100 

1.100 1.100 1.100 1.100 1.100 1.100 1.000 1.000 

1.000 1.100 1.100 1.000 1.000 1.100 1.000

E - 16 Chng in Annual Costs for Scndr Prods (Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 17 Change in Lifting Costs (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 18 Change in Secondary Workover Costs (Frac) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 19 Change in Injection Costs (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 20 Change in Injectant Costs (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 
1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 21 Change in Compression Costs (Fraction) 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000

E - 22 Change in Oil O&M cost ($/Bbl) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.001 0.000 0.000 0.000

E - 23 Change in Gas O&M cost ($/mcf) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 24 Change in Water Production O&M cost ($/Bbl) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 25 Change in Injection Cost ($/unit) 0.000 0.000 0.000 

0.000 2.000 0.000 0.000 0.000 2.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 26 Cost to Apply Drilling Tech (Well) (K$) 0.000 41.580 69.730 

34.690 32.380 121.930 22.210 174.590 29.990 41.580 209.360 

41.580 218.580 101.270 209.360 180.570 188.040 112.370

E - 27 Cost to Apply Stimulation Tech (Well) (K$) 0.000 1.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 1.000 40.000 

1.000 0.000 34.230 39.500 1.000 0.000 0.000

E - 28 Cost to Apply Completion Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 29 Cst to App Faclts Tech (Well) (Oil&Gas)(K$) 0.000 44.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 44.000 38.290 

44.000 30.300 34.930 38.290 47.170 0.000 36.330

E - 30 Cost to Apply 2nd Convrn Tech (Well) (K$) 0.000 0.000 32.460 

0.000 247.120 0.000 0.000 0.000 194.610 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 31 Cost to Apply Injctr Convn Tech (Well) (K$) 0.000 0.000 4.000 

0.000 7896.000 53.000 0.000 1.000 9.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 32 Cost to Apply Facs Upgrade Tech (Well) (K$) 0.000 0.000 0.000 

44.083 0.000 0.000 210.825 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 33.690 0.000

E - 33 Cost to Apply Workover Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 34 Cst to App Fixed Annual O&M Tech (Well)(K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 35 Cst to App Vrbl Annual O&M Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 36 Cost to Apply G & A Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 37 Cost to Apply 2nd Producer Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 38 Cost to Apply Lifting Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 39 Cost to Apply 2nd Workover Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 40 Cost to Apply Injection Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 41 Cost to Apply Compression Tech (Well) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 42 Cost to Apply Drilling Tech (Prj) (K$) 0.000 641.670 225.000 

225.000 0.000 482.500 225.000 482.500 470.000 641.670 1560.070 
641.670 2170.830 1792.220 1294.440 1542.220 2217.220 1875.560

E - 43 Cost to Apply Stimulation Tech (Prj) (K$) 0.000 0.000 9188.000 

0.000 200.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 250.000 20.830 0.000 0.000 0.000

E - 44 Cost to Apply Completion Tech (Prj) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 45 Cost to Apply Fac Tech (Prj) (Oil&Gas)(K$) 0.000 0.000 0.000 

0.000 966.000 0.000 1200.833 0.000 0.000 0.000 256.250 

0.000 0.000 668.750 256.250 250.000 770.000 607.140

E - 46 Cost to Apply 2nd Conversion Tech (Prj)(K$) 0.000 0.000 745.139 

0.000 0.000 0.000 0.000 0.000 194.610 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 47 Cost to Apply Injctr Cnvrsn Tech (Prj) (K$) 0.000 0.000 1896.250 

0.000 0.000 0.000 0.000 25.000 2005.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 48 Cost to Apply Faclts Upgrade Tech (Prj)(K$) 0.000 1177.080 0.000 

2112.500 939.583 0.000 0.000 0.000 0.000 1177.080 0.000 

1177.080 755.000 0.000 0.000 0.000 0.000 0.000

E - 49 Cost to Apply Workover Tech (Prj) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 50 Cost to Apply Fxd Annual O&M Tech (Prj)(K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 51 Cost to Apply Var Annual O&M Tech (Prj)(K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 52 Cost to Apply G & A Tech (Prj) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 53 Cost to Apply 2ndry Producer Tech (Prj)(K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 54 Cost to Apply Lifting Tech (Prj) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 55 Cost to Apply 2ndry Workover Tech (Prj)(K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 56 Cost to Apply Injection Tech (Prj) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

E - 57 Cost to Apply Compression Tech (Prj) (K$) 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

0.000 0.000 0.000 0.000 0.000 0.000 0.000

!*****************************************************************************

!technology lever equations

%*****************************************************************************

@ A B C D E Lever Description of 

Lever

0.000 0.000 0.000 0.000 0.000 V - 1 Pay Continuity 

Enhancement

0.2746 -0.0982 0.000 0.000 0.000 V - 2 Vertical Skin 

Factor

0.000 0.000 0.000 0.000 0.000 V - 3 Continuity Increase

0.000 0.000 0.000 0.000 0.000 V - 4 Productivity Index 

Increase

0.000 0.000 0.000 0.000 0.000 V - 5 Recovery 

Efficiency Increase

0.000 0.000 0.000 0.000 0.000 V - 6 Volumetric Sweep 

Efficiency Increase

0.000 0.000 0.000 0.000 0.000 V - 7 Injection Rate 

Increase (Fraction)

0.000 0.000 0.000 0.000 0.000 V - 8 Mobility Ratio 

Reduction (Fraction)
0.0623 0.1378 0.000 0.000 0.000 V - 9 DUMMY TECHNOLOGY 

VARIABLE 1 - WAG RATIO - CO2 EOR

-0.4255 0.4581 0.000 0.000 0.000 V - 10 DUMMY TECHNOLOGY 

VARIABLE 2 - EQUATION FOR POLYMER INJECTION RATE CHANGE (OIL)

0.5291 0.000 0.000 0.000 0.000 V - 11 DUMMY TECHNOLOGY 

VARIABLE 3 - IMPACT OF HCPV CHANGE (DEFAULT = 0.4 CO2/0.6 H2O) - ASSUMES WAG = 1.6

10.549 1.4605 0.0099 0.000 0.000 V - 12 DUMMY TECHNOLOGY 

VARIABLE 4 - CO2 EOR SWEEP EFFICIENCY

0.7746 3.9727 0.000 0.000 0.000 V - 13 DUMMY TECHNOLOGY 

VARIABLE 5 - HORIZONTAL PROFILE SWEEP EFFICIENCY

-0.008 8.2457 0.000 0.000 0.000 V - 14 DUMMY TECHNOLOGY 

VARIABLE 6 - CONTINUITY ADJUSTMENT - INFILL

-0.000021 2.987 0.000 0.000 0.000 V - 15 DUMMY TECHNOLOGY 

VARIABLE 7 - CONTINUITY ADJUSTMENT - HORIZONTAL CONTINUITY

0.2903 0.0012 0.000 0.000 0.000 V - 16 DUMMY TECHNOLOGY 

VARIABLE 8 - INJECTION RATE ADJUSTMENT - INFILL

0.0147 0.0592 0.000 0.000 0.000 V - 17 DUMMY TECHNOLOGY 

VARIABLE 9 - INJECTION RATE ADJUSTMENT - HORIZONTAL CONTINUITY

0.0364 0.1683 0.000 0.000 0.000 V - 18 DUMMY TECHNOLOGY 

VARIABLE 10- INJECTION RATE ADJUSTMENT - HORIZONTAL PROFILE

-0.0017 0.000 0.000 0.000 0.000 V - 19 DUMMY TECHNOLOGY 

VARIABLE 11- VERTICAL SKIN CHANGE - UND. CONV. GAS

-0.0009 -0.0079 0.000 0.000 0.000 V - 20 DUMMY TECHNOLOGY 

VARIABLE 12- VERTICAL SKIN CHANGE - UND. CBM - VOLUME FACTOR

0.0128 0.0306 -0.1506 0.000 0.000 V - 21 DUMMY TECHNOLOGY 

VARIABLE 13- VERTICAL SKIN CHANGE - UND. CBM - RATE FACTOR

-0.0009 -0.0079 0.000 0.000 0.000 V - 22 DUMMY TECHNOLOGY 

VARIABLE 14- VERTICAL SKIN CHANGE - UND. SHL - VOLUME FACTOR

0.0128 0.0306 -0.1506 0.000 0.000 V - 23 DUMMY TECHNOLOGY 

VARIABLE 15- VERTICAL SKIN CHANGE - UND. SHL - RATE FACTOR

-0.0009 -0.0079 0.000 0.000 0.000 V - 24 DUMMY TECHNOLOGY 

VARIABLE 16- VERTICAL SKIN CHANGE - DEV. CBM - VOLUME FACTOR

0.0128 0.0306 -0.1506 0.000 0.000 V - 25 DUMMY TECHNOLOGY 

VARIABLE 17- VERTICAL SKIN CHANGE - DEV. CBM - RATE FACTOR

-0.0009 -0.0079 0.000 0.000 0.000 V - 26 DUMMY TECHNOLOGY 

VARIABLE 18- VERTICAL SKIN CHANGE - DEV. SHL - VOLUME FACTOR

0.0128 0.0306 -0.1506 0.000 0.000 V - 27 DUMMY TECHNOLOGY 

VARIABLE 19- VERTICAL SKIN CHANGE - DEV. SHL - RATE FACTOR

-0.2293 0.7137 -0.4813 0.000 0.000 V - 28 DUMMY TECHNOLOGY 

VARIABLE 20- PAY CONTINUITY CHANGE - UND. CONV. GAS - VOLUME FACTOR

0.1527 -0.5973 0.817 -0.3699 0.000 V - 29 DUMMY TECHNOLOGY 

VARIABLE 21- PAY CONTINUITY CHANGE - UND. CONV. GAS - RATE FACTOR

-0.0829 0.2561 -0.1664 0.000 0.000 V - 30 DUMMY TECHNOLOGY 

VARIABLE 22- PAY CONTINUITY CHANGE - UND. THT GAS - VOLUME FACTOR

0.0543 -0.2125 0.2907 -0.1316 0.000 V - 31 DUMMY TECHNOLOGY 

VARIABLE 23- PAY CONTINUITY CHANGE - UND. THT GAS - RATE FACTOR

-0.0829 0.2561 -0.1664 0.000 0.000 V - 32 DUMMY TECHNOLOGY 

VARIABLE 24- PAY CONTINUITY CHANGE - DEV. THT GAS - VOLUME FACTOR

0.0543 -0.2125 0.2907 -0.1316 0.000 V - 33 DUMMY TECHNOLOGY 

VARIABLE 25- PAY CONTINUITY CHANGE - DEV. THT GAS - RATE FACTOR

2.0E-9 5.0E-6 0.000 0.000 0.000 V - 34 DUMMY TECHNOLOGY 

VARIABLE 26- FRACTURE CONDUCTIVITY CHANGE - UND. CBM

2.0E-9 5.0E-6 0.000 0.000 0.000 V - 35 DUMMY TECHNOLOGY 

VARIABLE 27- FRACTURE CONDUCTIVITY CHANGE - UND. SHL

2.0E-9 5.0E-6 0.000 0.000 0.000 V - 36 DUMMY TECHNOLOGY 

VARIABLE 28- FRACTURE CONDUCTIVITY CHANGE - DEV. CBM

2.0E-9 5.0E-6 0.000 0.000 0.000 V - 37 DUMMY TECHNOLOGY 

VARIABLE 29- FRACTURE CONDUCTIVITY CHANGE - DEV. SHL

0.0000218 0.000 0.000 0.000 0.000 V - 38 DUMMY TECHNOLOGY 

VARIABLE 30- FRACTURE CONDUCTIVITY CHANGE - UND. THT

0.0000218 0.000 0.000 0.000 0.000 V - 39 DUMMY TECHNOLOGY 

VARIABLE 31- FRACTURE CONDUCTIVITY CHANGE - DEV. THT

0.000157 -0.151244 0.000 0.000 0.000 V - 40 DUMMY TECHNOLOGY 

VARIABLE 32- FRACTURE LENGTH CHANGE - UND. THT

0.000157 -0.151244 0.000 0.000 0.000 V - 41 DUMMY TECHNOLOGY 

VARIABLE 33- FRACTURE LENGTH CHANGE - DEV. THT

%
%

!***************************************************************

!from wlcost.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) Cost Data File

%

% Sections:

% 1. Resource/Process Independent Capital Costs

% 2. Resource/Process Specific Capital Costs

% 3. Fixed Operating Costs

% 4. Variable Operating Costs

% 5. Other Cost Parameters

% 6. Process Discount Rates

% 7. Consumer Price Indices

% 8. Oil & Gas Sale Controls

%

%*****************************************************************************

%

%

%

% Section 1: Resource/Process Independent Capital Costs

@

9 C Number of regions

%

% A. Vertical Drilling and Completion for Oil

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------------- Depth: < 2,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 4999.99 129496.0 0.0 

0.05829 5.68E-07

1a 0.00 4999.99 129496.0 0.0 

0.05829 5.68E-07

2 0.00 4999.99 178663.0 0.0 

0.02658 5.11E-07

3 0.00 4999.99 51254.6 0.0 

0.03847 -9.46E-07

4 0.00 4999.99 178663.0 0.0 

0.02658 5.11E-07

5 0.00 4999.99 92910.8 0.0 

0.02405 3.12E-06

6 0.00 4999.99 423198.0 44.24 

0.03268 3.38E-07

7 0.00 4999.99 105574.5 478.74 

-0.00832 6.12E-07

8 0.00 4999.99 7239.88 0.000008068 

0.000001153 0.0000000009

% --------------------- Depth: 2,000 - 4,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 5000.00 9999.99 129496.0 0.0 

0.05829 5.68E-07

1a 5000.00 9999.99 129496.0 0.0 

0.05829 5.68E-07

2 5000.00 9999.99 178663.0 0.0 

0.02658 5.11E-07

3 5000.00 9999.99 51254.6 0.0 

0.03847 -9.46E-07

4 5000.00 9999.99 178663.0 0.0 

0.02658 5.11E-07

5 5000.00 9999.99 92910.8 0.0 

0.02405 3.12E-06

6 5000.00 9999.99 423198.0 44.24 
0.03268 3.38E-07

7 5000.00 9999.99 105574.5 478.74 

-0.00832 6.12E-07

8 5000.00 9999.99 7239.88 0.000008068 

0.000001153 0.0000000009

% --------------------- Depth: 4,000 - 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 10000.00 14999.99 129496.0 0.0 

0.05829 5.68E-07

1a 10000.00 14999.99 129496.0 0.0 

0.05829 5.68E-07

2 10000.00 14999.99 178663.0 0.0 

0.02658 5.11E-07

3 10000.00 14999.99 51254.6 0.0 

0.03847 -9.46E-07

4 10000.00 14999.99 178663.0 0.0 

0.02658 5.11E-07

5 10000.00 14999.99 929103.8 0.0 

0.02405 3.12E-06

6 10000.00 14999.99 423198.0 44.24 

0.03268 3.38E-07

7 10000.00 14999.99 105574.5 478.74 

-0.00832 6.12E-07

8 10000.00 14999.99 7239.88 0.000008068 

0.000001153 0.0000000009

% --------------------------- Depth: > 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 15000.00 99999.00 129496.0 0.0 

0.05829 5.68E-07

1a 15000.00 99999.00 129496.0 0.0 

0.05829 5.68E-07

2 15000.00 99999.00 178663.0 0.0 

0.02658 5.11E-07

3 15000.00 99999.00 51254.6 0.0 

0.03847 -9.46E-07

4 15000.00 99999.00 178663.0 0.0 

0.02658 5.11E-07

5 15000.00 99999.00 92910.8 0.0 

0.02405 3.12E-06

6 15000.00 99999.00 423198.0 44.24 

0.03268 3.38E-07

7 15000.00 99999.00 105574.5 478.74 

-0.00832 6.12E-07

8 15000.00 99999.00 7239.88 0.000008068 

0.000001153 0.0000000009

%%

% B. Cost to Equip a Primary Producer

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 62709.378 2.377 

0.0 0.0

1a 0.00 99999.00 62709.378 2.377 

0.0 0.0

2 0.00 99999.00 51315.403 0.340 

0.0 0.0

3 0.00 99999.00 45821.717 2.793 

0.0 0.0

4 0.00 99999.00 51315.403 0.340 

0.0 0.0

5 0.00 99999.00 62709.378 2.377 
0.0 0.0

6 0.00 99999.00 106959.788 0.910 

0.0 0.0

7 0.00 99999.00 62709.378 2.377 

0.0 0.0

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

%

% C. Vertical Drilling and Completion for Gas

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------------- Depth: < 2,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 4999.99 197455.0 19.31 

0.04012 0.0

1a 0.00 4999.99 197455.0 19.31 

0.04012 0.0

2 0.00 4999.99 318883.0 0.0 

0.01903 1.13E-06

3 0.00 4999.99 355179.0 54.21 0.0 

1.20E-06

4 0.00 4999.99 91618.176 376.1968 

-0.0624 5.04E-06

5 0.00 4999.99 219733.0 0.0 

0.03227 2.60E-06

6 0.00 4999.99 385533.0 0.0 

0.01799 1.01E-06

7 0.00 4999.99 267620.0 30.62 

0.04941 0.0

8 0.00 4999.99 172.88 0.000008068 

0.000001153 0.0000000009

% --------------------- Depth: 2,000 - 4,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 5000.00 9999.99 197455.0 19.31 

0.04012 0.0

1a 5000.00 9999.99 197455.0 19.31 

0.04012 0.0

2 5000.00 9999.99 318883.0 0.0 

0.01903 1.13E-06

3 5000.00 9999.99 355179.0 54.21 0.0 

1.20E-06

4 5000.00 9999.99 91618.176 376.1968 

-0.0624 5.04E-06

5 5000.00 9999.99 219733.0 0.0 

0.03227 2.60E-06

6 5000.00 9999.99 385533.0 0.0 

0.01799 1.01E-06

7 5000.00 9999.99 267620.0 30.62 

0.04941 0.0

8 5000.00 9999.99 172.88 0.000008068 

0.000001153 0.0000000009

% --------------------- Depth: 4,000 - 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 10000.00 14999.99 197455.0 19.31 

0.04012 0.0

1a 10000.00 14999.99 197455.0 19.31 

0.04012 0.0

2 10000.00 14999.99 318883.0 0.0 

0.01903 1.13E-06

3 10000.00 14999.99 355179.0 54.21 0.0 
1.20E-06

4 10000.00 14999.99 91618.176 376.1968 

-0.0624 5.04E-06

5 10000.00 14999.99 219733.0 0.0 

0.03227 2.60E-06

6 10000.00 14999.99 385533.0 0.0 

0.01799 1.01E-06

7 10000.00 14999.99 267620.0 30.62 

0.04941 0.0

8 10000.00 14999.99 172.88 0.000008068 

0.000001153 0.0000000009

% --------------------------- Depth: > 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 15000.00 99999.000 197455.0 19.31 

0.04012 0.0

1a 15000.00 99999.000 197455.0 19.31 

0.04012 0.0

2 15000.00 99999.000 318883.0 0.0 

0.01903 1.13E-06

3 15000.00 99999.000 355179.0 54.21 0.0 

1.20E-06

4 15000.00 99999.000 91618.176 376.1968 

-0.0624 5.04E-06

5 15000.00 99999.000 219733.0 0.0 

0.03227 2.60E-06

6 15000.00 99999.000 385533.0 0.0 

0.01799 1.01E-06

7 15000.00 99999.000 267620.0 30.62 

0.04941 0.0

8 15000.00 99999.000 172.88 0.000008068 

0.000001153 0.0000000009

%

%

% D. Dry Hole

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------------- Depth: < 2,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 4999.99 170558.0 256.99 

-0.04343 5.90E-06

1a 0.00 4999.99 170558.0 256.99 

-0.04343 5.90E-06

2 0.00 4999.99 118791.0 126.23 

-0.00106 2.32E-06

3 0.00 4999.99 163850.0 17.95 

0.02272 -3.50E-07

4 0.00 4999.99 22628.7 262.76 

-0.06499 6.53E-06

5 0.00 4999.99 288057.0 0.0 

0.01814 3.86E-06

6 0.00 4999.99 106996.0 687.31 

-0.159 1.15E-05

7 0.00 4999.99 122508.0 645.44 

-0.01473 3.24E-06

8 0.00 4999.99 172.88 0.000008068 

0.000001153 0.0000000009

% --------------------- Depth: 2,000 - 4,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 5000.00 9999.99 170558.0 256.99 

-0.04343 5.90E-06

1a 5000.00 9999.99 170558.0 256.99 
-0.04343 5.90E-06

2 5000.00 9999.99 118791.0 126.23 

-0.00106 2.32E-06

3 5000.00 9999.99 163850.0 17.95 

0.02272 -3.50E-07

4 5000.00 9999.99 22628.7 262.76 

-0.06499 6.53E-06

5 5000.00 9999.99 288057.0 0.0 

0.01814 3.86E-06

6 5000.00 9999.99 106996.0 687.31 

-0.159 1.15E-05

7 5000.00 9999.99 122508.0 645.44 

-0.01473 3.24E-06

8 5000.00 9999.99 172.88 0.000008068 

0.000001153 0.0000000009

% --------------------- Depth: 4,000 - 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 10000.00 14999.99 170558.0 256.99 

-0.04343 5.90E-06

1a 10000.00 14999.99 170558.0 256.99 

-0.04343 5.90E-06

2 10000.00 14999.99 118791.0 126.23 

-0.00106 2.32E-06

3 10000.00 14999.99 163850.0 17.95 

0.02272 -3.50E-07

4 10000.00 14999.99 22628.7 262.76 

-0.06499 6.53E-06

5 10000.00 14999.99 288057.0 0.0 

0.01814 3.86E-06

6 10000.00 14999.99 106996.0 687.31 

-0.159 1.15E-05

7 10000.00 14999.99 122508.0 645.44 

-0.01473 3.24E-06

8 10000.00 14999.99 172.88 0.000008068 

0.000001153 0.0000000009

% --------------------------- Depth: > 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 15000.00 99999.000 170558.0 256.99 

-0.04343 5.90E-06

1a 15000.00 99999.000 170558.0 256.99 

-0.04343 5.90E-06

2 15000.00 99999.000 118791.0 126.23 

-0.00106 2.32E-06

3 15000.00 99999.000 163850.0 17.95 

0.02272 -3.50E-07

4 15000.00 99999.000 22628.7 262.76 

-0.06499 6.53E-06

5 15000.00 99999.000 288057.0 0.0 

0.01814 3.86E-06

6 15000.00 99999.000 106996.0 687.31 -0.159 

1.15E-05

7 15000.00 99999.000 122508.0 645.44 

-0.01473 3.24E-06

8 15000.00 99999.000 172.88 0.000008068 

0.000001153 0.0000000009

%

% 

------------------------------------------------------------------------------------------

-------

%

% D.1 New!!! Drilling Cost Equations Coefficients (ADDED mAY 2013)

%

% Number of rows in following tables
@

7 Number of regions (1a uses 1 and 8 uses 5)

%

% Drilling and Completion Cost = [A*exp(-B*Depth) + C*Depth + D*Depth*Depth + 

E*exp(F*DEPTH)]* DEPTH

%

%

% ------------------------------------------- NEW Coefficients July 2013 

--------------------------------

%

% -------------------------------------------------- OIL 

-----------------------------------------------

%

%REGION A B C D E F

@

1175011.52840.0003284950.0095976360.06265268211748.886020.000302173

2177665.29640.00022433100.02936564432185.297460.00024632

30057.228848140.02282263200

4152884.48110.00030896300.02787759356715.391570.000224376

5106800.5420.00299998900.04080896617576.287730.000409701

6149098.37849.3188E-058.0512308130.03228982282024.39830.000135664

7113994.77020411.2026851070099.747360.00018766

%

%

% -------------------------------------------------- GAS 

------------------------------------------------

%

%REGION A B C D E F

@

1139453.9519017.702777030.04009167857953.917432.8256E-05

2362007.92460.00027195100.02553557768.603810.000257353

3277684.83820.0001469600.007866326160096.02610.000204878

4401334.17021.0418E-0615.438749580140711.3270.000271092

51751000.0005600.04356766664577.805530.000313095

6394451.0650.00021444900.02336499874723.774470.000237271

7388269.02590.00040562788.012556240.04647814600

%

%

% -------------------------------------------------- DRY 

------------------------------------------------

%

%REGION A B C D E F

@

1373565.49490.00033542200.010812916198571.3460.000274926

2145975.43690.0002981255.7324817190.019485239139514.3040.00024177

3295750.36960.00078845986.140548630.01386523100

4389495.93320.00041628100101481.63390.000320498

53000000.00090500.03390749794160.220380.000316633

61371262.5050.0001672530055899.522340.000369903

71302000.003409.58989660.014126494340333.67890.000211981

%

%

%

% --------------- END OF NEW DATA SECTION (D.1) --------------------------

%

% E. Workover Costs

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 1736.081 1.320 

0.0 0.0

1a 0.00 99999.00 1736.081 1.320 

0.0 0.0

2 0.00 99999.00 1949.479 0.364 
0.0 0.0

3 0.00 99999.00 -2738.051 2.507 

0.0 0.0

4 0.00 99999.00 389.821 1.204 

0.0 0.0

5 0.00 99999.00 1736.081 1.320 

0.0 0.0

6 0.00 99999.00 1326.648 1.143 

0.0 0.0

7 0.00 99999.00 1736.081 1.320 

0.0 0.0

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

%*****************************************************************************

%

%

% Section 2: Resource/Process Specific Capital Costs

@

8 C Number of Regions

%

% A. Gas Processing and Treatment Facilities

% CAPSU() = CAPACITY (LONG TONS/DAY) FOR CLAUS SULFUR RECOVERY AND

% DIRECT CONVERSION OF H2S TO SULFUR (CHELATED IRON PROCESS)

% CAPST() = CAPACITY (MMCFD) FOR NGL STRAIGHT REFRIGERATION

% CAPCR() = CAPACITY (MMCFD) FOR NGL CRYOGENIC EXPANDER PLANT

% CAPTE() = CAPACITY (MMCFD) FOR ALL OTHER PLANT TYPES BASED ON THE AVERAGES FOR TEXAS 

(REPRESENTATIVE OF THE U.S.)

% THRU() = NGL THRUPUT (USED FOR ALL IMPURITIES)

% OP_FAC()= OPERATION FACTOR

%

%REGION CAPST CAPCR CAPTE CAPSU THRU OP_FAC

%--------------------------------------------------------

@

1 55.164 72.371 64.039 110.900 46.528 0.97

2 55.164 72.371 64.039 110.900 46.528 0.97

3 55.164 72.371 64.039 110.900 46.528 0.97

4 55.164 72.371 64.039 110.900 46.528 0.97

5 55.164 72.371 64.039 110.900 46.528 0.97

6 55.164 72.371 64.039 110.900 46.528 0.97

7 55.164 72.371 64.039 110.900 46.528 0.97

8 55.164 72.371 64.039 110.900 46.528 0.97

%

% DIS_RATE = DISCOUNT RATE FOR THE PLANT

% PLT_LFE = PLANT LIFE SPAN

% N2_LIM = MAXIMUM ACCEPTABLE FRACTION OF GAS WHICH IS N2

% CO2_LIM = MAXIMUM ACCEPTABLE FRACTION OF GAS WHICH IS CO2

% H2S_LIM = MAXIMUM ACCEPTABLE FRACTION OF GAS WHICH IS H2S

% NGL_LIM = MAXIMUM ACCEPTABLE FRACTION OF GAS WHICH IS NGL

%

% DIS_RATE PLT_LFE N2_LIM CO2_LIM H2S_LIM NGL_LIM

% -------- ------- ------ ------- ------- -------

@

0.10 15.0 0.03 0.03 0.0000064 0.067

%

% B. Cost to convert a primary to secondary well

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 -115.557 57.930 

0.0 0.0

1a 0.00 99999.00 -115.557 57.930 

0.0 0.0

2 0.00 99999.00 -10733.738 68.593 
0.0 0.0

3 0.00 99999.00 -32919.310 50.796 

0.0 0.0

4 0.00 99999.00 -25175.777 48.581 

0.0 0.0

5 0.00 99999.00 -115.557 57.930 

0.0 0.0

6 0.00 99999.00 -47775.505 69.683 

0.0 0.0

7 0.00 99999.00 -115.557 57.930 

0.0 0.0

8 0.00 99999.00 0.00 0.000 

0.0 0.0

% C. Cost to convert a producer to an injector

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 24054.311 7.886 

0.0 0.0

1a 0.00 99999.00 24054.311 7.886 

0.0 0.0

2 0.00 99999.00 24640.612 9.582 

0.0 0.0

3 0.00 99999.00 9356.411 7.649 

0.0 0.0

4 0.00 99999.00 11129.339 7.186 

0.0 0.0

5 0.00 99999.00 24054.311 7.886 

0.0 0.0

6 0.00 99999.00 11125.846 10.670 

0.0 0.0

7 0.00 99999.00 24054.311 7.886 

0.0 0.0

8 0.00 99999.00 0.00 0.000 

0.0 0.0

% D. Facilities Upgrade Cost

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 37322.044 4.109 

0.0 0.0

1a 0.00 99999.00 37322.044 4.109 

0.0 0.0

2 0.00 99999.00 33665.630 6.112 

0.0 0.0

3 0.00 99999.00 19032.550 4.762 

0.0 0.0

4 0.00 99999.00 20711.761 4.350 

0.0 0.0

5 0.00 99999.00 37322.044 4.109 

0.0 0.0

6 0.00 99999.00 23746.551 6.817 

0.0 0.0

7 0.00 99999.00 37322.044 4.109 

0.0 0.0

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% E. Well Facilities Cost for Gas

% cost = A + B*depth + C*(Q) + D*(Depth*Q) ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 
D

@

1 0.00 99999.00 7922.477 6.511 

89.265 -0.00772

1a 0.00 99999.00 7922.477 6.511 

89.265 -0.00772

2 0.00 99999.00 14960.605 4.869 

28.486 -0.00179

3 0.00 99999.00 10185.916 4.506 

55.381 -0.00328

4 0.00 99999.00 3477.408 5.040 

63.866 -0.00376

5 0.00 99999.00 7922.477 6.511 

89.265 -0.00772

6 0.00 99999.00 10185.916 4.506 

55.381 -0.00328

7 0.00 99999.00 7922.477 6.511 

89.265 -0.00772

8 0.00 99999.00 0.00 0.000 0.0 

0.0

% F. Produced Water Handling Plant

% Capital Cost Estimated ($M) = a0 * RMAX1

% RMAX1 = Calculated Max Water Injection Rate / Life of Flood (MBBL/Day)

@

40 !a0

%

% G. Chemical Handling Plant

% Capital Cost($) = AFAC * a0 * RMAX**a2

% RMAX = Calulated Max Surfacant Slug Injection Rate / Life of Flood (MBBL/Day)

% AFAC a0 a2

@

0.10 1.0 0.6

%

% H. Polymer Handling Plant

% Capital Cost ($M) = a0 * a1 * RMAX**0.6

% RMAX = Max Injection Rate / Life of Project (MBBL/Day)

@

0.1 1000.0

%

% I. CO2 recycling/injection plant (Recompression and Injection)

% Capital Cost($MM) = a0 * Capacity (MMcfd)**a2

@

.177 1.45

%

% I Steam Manifolds/Pipelines

% Capital Cost (K$) = MFAC * acres

% MFAC

@

19.80

%

% J. Steam Generators

% Capital Cost (K$) = SGFAC * number of generators

% SGFAC

@

650.00

%

% K. Compression (to raise pressure to pipeline pressure) - single stage compressor

@

1200 C ($/BHP)

%

%

%*****************************************************************************

%

%

% Section 3: Fixed Operating Costs

@

8 C Number of OLOGSS Regions
%

% A. Fixed annual cost for Oil

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 7450.733 0.302 

0.0 0.0

1a 0.00 99999.00 7450.733 0.302 

0.0 0.0

2 0.00 99999.00 8249.358 1.543 

0.0 0.0

3 0.00 99999.00 6695.283 0.499 

0.0 0.0

4 0.00 99999.00 7149.949 0.263 

0.0 0.0

5 0.00 99999.00 7450.733 0.302 

0.0 0.0

6 0.00 99999.00 6316.399 0.422 

0.0 0.0

7 0.00 99999.00 7450.733 0.302 

0.0 0.0

8 0.00 99999.00 1123.00 0.000 

0.0 0.0

%

% B. Fixed annual cost for Gas

% cost = A + B*depth + C*(daily rate) + D*(depth*daily rate) ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 9163.862 3.815 

32.267 -0.00254

1a 0.00 99999.00 9163.862 3.815 

32.267 -0.00254

2 0.00 99999.00 12774.700 2.679 

7.673 -0.00046

3 0.00 99999.00 9822.820 2.755 

21.209 -0.00126

4 0.00 99999.00 6079.282 2.499 

27.653 -0.00159

5 0.00 99999.00 9163.862 3.815 

32.267 -0.00254

6 0.00 99999.00 9822.820 2.755 

21.209 -0.00126

7 0.00 99999.00 9163.862 3.815 

32.267 -0.00254

8 0.00 99999.00 1629.00 0.000 0.0 

0.0

% C. Annual cost for secondary production

% --------------------- All Depth Categories ---------------------

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 53857.063 5.888 

0.0 0.0

1a 0.00 99999.00 53857.063 5.888 

0.0 0.0

2 0.00 99999.00 55732.748 7.277 

0.0 0.0

3 0.00 99999.00 28208.703 6.680 

0.0 0.0

4 0.00 99999.00 30509.302 6.118 
0.0 0.0

5 0.00 99999.00 53857.063 5.888 

0.0 0.0

6 0.00 99999.00 35893.465 9.499 

0.0 0.0

7 0.00 99999.00 53857.063 5.888 

0.0 0.0

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

%

%*****************************************************************************

%

%

% Section 4: Variable Operating Costs

@

24 C Number of Processes

% A. Process Specific O & M Costs

% OIL GAS WAT INJ

% ($/BBL) ($/MCF) ($/BBL) ($/BBL)

% ----- ----- ----- -----

@

0.94 0.48 0.27 0.00 00 Decline Curve Model

2.83 0.94 0.94 0.00 01 Primary

1.17 0.00 1.42 2.37 02 Water Flooding

0.94 0.00 0.05 0.00 03 CO2 Flooding

3.32 0.00 0.05 0.00 04 Steam Flooding

1.17 0.00 0.05 0.00 05 Polymer Floosing

0.94 0.48 0.94 0.00 06 Infill Drilling

1.17 0.00 0.05 0.00 07 Profile Modification

0.94 0.48 0.94 0.94 08 Horizontal Continuity

0.94 0.48 0.94 0.00 09 Horizontal Profile

2.83 0.94 0.94 0.00 10 Undiscovered Conventional Oil

0.00 0.55 0.48 0.00 11 Conventional Radial Flow

0.00 0.55 0.48 0.00 12 Water Drive

0.00 0.55 0.48 0.00 13 Tight Sands

0.00 0.55 0.48 0.00 14 Wet Coal/Shale Gas

0.00 0.55 0.48 0.00 15 Dry Coal/Shale Gas

0.00 0.55 0.48 0.00 16 Undiscovered Conventional Gas

0.94 0.48 0.94 0.00 17 Undiscovered Unconventional Oil

0.00 0.55 0.48 0.00 18 Undiscovered Tight Gas

0.00 0.55 0.48 0.00 19 Undiscovered Coal Bed Methane

0.00 0.55 0.48 0.00 20 Undiscovered Shale Gas

0.00 0.55 0.48 0.00 21 Developing Shale Gas

0.00 0.55 0.48 0.00 22 Developing Tight Gas

0.00 0.55 0.48 0.00 23 Developing Coalbed Methane

%

%

% B. Lifting Cost

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 10137.398 0.462 

0.0 0.0

1a 0.00 99999.00 10137.398 0.462 

0.0 0.0

2 0.00 99999.00 11585.191 0.912 

0.0 0.0

3 0.00 99999.00 8298.339 0.843 

0.0 0.0

4 0.00 99999.00 7534.515 0.922 

0.0 0.0

5 0.00 99999.00 10137.398 0.462 

0.0 0.0
6 0.00 99999.00 5147.313 3.301 

0.0 0.0

7 0.00 99999.00 10137.398 0.462 

0.0 0.0

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% C. Secondary Workover Cost

% cost = A + B*depth ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 5291.954 2.300 

0.0 0.0

1a 0.00 99999.00 5291.954 2.300 

0.0 0.0

2 0.00 99999.00 10560.069 3.587 

0.0 0.0

3 0.00 99999.00 3732.510 2.740 

0.0 0.0

4 0.00 99999.00 4951.059 2.703 

0.0 0.0

5 0.00 99999.00 5291.954 2.300 

0.0 0.0

6 0.00 99999.00 4131.486 2.545 

0.0 0.0

7 0.00 99999.00 5291.954 2.300 

0.0 0.0

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% D. Injection Cost

% cost = A + B*depth + C*(depth^2) + D*(depth^3) ($/Well)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.0 0.0 

0.0 0.0

1a 0.00 99999.00 0.0 0.0 

0.0 0.0

2 0.00 99999.00 0.0 0.0 

0.0 0.0

3 0.00 99999.00 0.0 0.0 

0.0 0.0

4 0.00 99999.00 0.0 0.0 

0.0 0.0

5 0.00 99999.00 0.0 0.0 

0.0 0.0

6 0.00 99999.00 0.0 0.0 

0.0 0.0

7 0.00 99999.00 0.0 0.0 

0.0 0.0

8 0.00 99999.00 0.0 0.0 

0.0 0.0

%

% D. Injectant Cost

% polymer

% CO2

%

% NOTE: A & B ARE FUNCTIONS OF DEPTH

% C (POLYMER) IS A FIXED VALUE ($/Lbs)

% C (CO2) IS A FIXED VALUE DEPENDANT ON CO2 SOURCE AND REGION

%

% Section 4.C: Injectant Costs

% polymer cost ($/Lb)
@

1.96

%

% Natural CO2 Costs ($/Mcf)

% CO2 West Texas Purchase Cost (Includes NM and UT)

% Cost ($/Mcf) = a0 + a1*Oil Price ($/Bbl)

@

1.00 0.008

%

% Number of Regions (Excluding Default - 99)

@

6

% CO2 Non-West Texas Purchase Cost (Factor * West Texas Price)

@

5 1.00 ! CO

17 1.00 ! LA

30 1.00 ! MS

43 1.00 ! UT

49 1.00 ! WY

99 1.00 ! 99 default

% Industrial CO2 Costs

%

% TOTAL CO2 COST FOR ALL SOURCES (CAPTURE + TRANSPORTATION) TABLE BY REGION AND SOURCE 

($/MCF)

% (NATURAL SOURCES ARE CALCULATED AS A FUNCTION OF OIL PRICE)

%

% EAST COAST GULF COAST MIDCONTINENT SOUTHWEST ROCKY MOUNTAINS WEST COAST 

NORTHERN GREAT PLAINS C SOURCE

@

2.04 1.54 1.67 1.62 1.63 1.61 

1.65 C HYDROGEN

1.70 1.70 1.70 1.70 1.70 1.70 

1.70 C AMMONIA

1.83 1.83 1.83 1.83 1.83 1.83 

1.83 C ETHANOL

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 C NATURAL

3.89 3.89 3.89 3.89 3.89 3.89 

3.89 C CEMENT

2.04 1.54 1.67 1.62 1.63 1.61 

1.65 C HYDROGEN REFINERIES

1.50 1.50 1.50 1.50 1.50 1.50 

1.50 C PLANNED POWER PLANTS

5.56 5.56 5.56 5.56 5.56 5.56 

5.56 C POWER PLANTS

1.52 1.52 1.52 1.52 1.52 1.52 

1.52 C NATURAL GAS PROCESSING

1.51 1.51 1.51 1.51 1.51 1.51 

1.51 C PLANNED COAL TO LIQUIDS

1.51 1.51 1.51 1.51 1.51 1.51 

1.51 C COAL TO LIQUIDS

99.99 99.99 99.99 99.99 99.99 99.99 

99.99 C NEW SOURCE 1

99.99 99.99 99.99 99.99 99.99 99.99 

99.99 C NEW SOURCE 2

%

%

% O&M Costs for injection of CO2 ($/Mcf)

@

0.40 !Max injection rate > 20 MMcf

0.45 !Max injection rate < 20 MMcf

%

%

% Section 4.D: Other Process Specific Operating Costs

% Gas Well Stimulation Efficiency (Percent)

@
60.0

%

% Gas Well Stimulation Cost ($MM/Well):

% Stimulation Cost $20k plus $2.5/foot + Frac Costs

@

20000.0 2.5

%

% Number of Years between stimulations (not applied: 0)

@

3

%

% Compressor O&M ($/Mcf)

@

0.1500

%

% Water Recycling Factors

% water oil

@

0.075 0.40

%

%*****************************************************************************

%

%

% Section 5: Other Cost Parameters

% A. Lease Acquisition Factor

@

1.00 C Lease Bonus Cost Factor (Percent)

100.0 C Percent Lease Acquisition Cost Capitalized

% B. Geological and Geophysical Factors

@

5.00 C G&G Factor (Percent)

100.0 C Percent of G&G Depleted (Percent)

% C. G&A Multipliers

@

20.00 C G&A Expense Multiplier (Percent)

2.00 C G&A Capital Multiplier (Percent)

% D. Environmental Cost Multipliers

@

10.00 C Environmental Capital Cost Multiplier (Percent)

15.00 C Environmental Operating Cost Multiplier (Percent)

% E. Tangible Investment Multipliers

@

30.0 C Percent Development Well Cost Tangible (Percent)

100.0 C Percent Facilities Cost Tangible (Percent)

%

% F. Factors for Oil/Gas Price Multipliers (Values)

% OIL

@

0.2 C Intangible cost multiplier factor

0.2 C Tangible cost multiplier factor

0.1 C O & M cost multiplier factor

%

% GAS

@

0.2 C Intangible cost multiplier factor

0.2 C Tangible cost multiplier factor

0.1 C O & M cost multiplier factor

%

%*****************************************************************************

%

%

% Section 6: Process Discount Rates

@

24 C Number of Processes

% Discount Rate Process Number Process Name

@ (Percent)
15.00 00 Decline Curve

15.00 01 Primary

15.00 02 Water Flooding

15.00 03 CO2 Flooding

15.00 04 Steam Flooding

15.00 05 Polymer Flooding

15.00 06 Infill Drilling

15.00 07 Profile Modification

15.00 08 Horizontal Continuity

15.00 09 Horizontal Profile

15.00 10 Undiscovered Conventional Oil

15.00 11 Conventional Radial Flow

15.00 12 Water Drive

15.00 13 Tight Sands

15.00 14 Wet Coal/Shale Gas

15.00 15 Dry Coal/Shale Gas

15.00 16 Undiscovered Conventional Gas

15.00 17 Undiscovered Unconventional Oil

15.00 18 Undiscovered Tight Gas

15.00 19 Undiscovered Coalbed Methane

15.00 20 Undiscovered Shale Gas

15.00 21 Developing Shale Gas

15.00 22 Developing Tight Gas

15.00 23 Developing Coalbed Methane

%*****************************************************************************

%

%

% Section 7: Consumer Price Indices

%

% YEAR FOR NOMINAL DOLLARS

@

2008

%

% NUMBER OF YEARS TO READ

@

9

%

% YEAR CPI AVG. FACTOR

@

2000 172.20 1.250

2001 177.10 1.215

2002 179.90 1.196

2003 184.00 1.170

2004 188.90 1.139

2005 195.30 1.102

2006 201.60 1.067

2007 207.34 1.038

2008 215.303 1.000

%

%*****************************************************************************

%

%

% Section 8: Oil & Gas Sales Controls

@

21 C Number of Processes

% Sell Oil Sell Gas Process Number Process Name

@ (Y/N) (Y/N)

Y Y 00 Decline Curve

Y Y 01 Primary

Y Y 02 Water Flooding

Y Y 03 CO2 Flooding

Y Y 04 Steam Flooding

Y Y 05 Polymer Flooding

Y N 06 Infill Drilling

Y N 07 Profile Modification
Y N 08 Horizontal Continuity

Y N 09 Horizontal Profile

Y Y 10 Undiscovered Conventional Oil

Y Y 11 Conventional Radial Flow

Y Y 12 Water Drive

Y Y 13 Tight Sands

Y Y 14 Wet Coal/Shale Gas

Y Y 15 Dry Coal/Shale Gas

Y Y 16 Undiscovered Conventional

Y Y 17 Undiscovered Unconventional Oil

Y Y 18 Undiscovered Tight Gas

Y Y 19 Undiscovered Coalbed Methane

Y Y 20 Undiscovered Shale Gas

Y Y 21 Developing Shale Gas

Y Y 22 Developing Tight Gas

Y Y 23 Developing Coalbed Methane

!

!******************************************************************************

!******************************************************************************

!

%******************************************************************************

%

% Cost Adjustment Factors. To be multiplied with the calculated cost (Equation number)

%

%******************************************************************************

%

@

9 C Number of regions

%

% Cost Adjustment Factor for Vertical Drilling and Completion for Oil (1A)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------------- Depth: < 2,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 4999.99 0.3096164 0.0198371 

-0.00014241 0.00000035

1a 0.00 4999.99 0.3096164 0.0198371 

-0.00014241 0.00000035

2 0.00 4999.99 0.4046777 0.0163359 

-0.00010587 0.00000024

3 0.00 4999.99 0.309185 0.0190363 

-0.00012367 0.00000026

4 0.00 4999.99 0.293837 0.02018312 

-0.00014294 0.00000034

5 0.00 4999.99 0.2972705 0.02012623 

-0.00014308 0.00000035

6 0.00 4999.99 0.2977022 0.02009143 

-0.0001426 0.00000034

7 0.00 4999.99 0.2927846 0.0204158 

-0.0001464 0.00000036

8 0.00 4999.99 0.00 0.000 

0.0 0.0

% --------------------- Depth: 2,000 - 4,000 ft --------------------------

@

1 5000.00 9999.99 0.3096164 0.0198371 

-0.00014241 0.00000035

1a 5000.00 9999.99 0.3096164 0.0198371 

-0.00014241 0.00000035

2 5000.00 9999.99 0.4046777 0.0163359 

-0.00010587 0.00000024

3 5000.00 9999.99 0.309185 0.0190363 

-0.00012367 0.00000026

4 5000.00 9999.99 0.293837 0.02018312 
-0.00014294 0.00000034

5 5000.00 9999.99 0.2972705 0.02012623 

-0.00014308 0.00000035

6 5000.00 9999.99 0.2977022 0.02009143 

-0.0001426 0.00000034

7 5000.00 9999.99 0.2927846 0.0204158 

-0.0001464 0.00000036

8 5000.00 9999.99 0.00 0.000 

0.0 0.0

% --------------------- Depth: 4,000 - 8,000 ft --------------------------

@

1 10000.00 14999.99 0.3096164 0.0198371 

-0.00014241 0.00000035

1a 10000.00 14999.99 0.3096164 0.0198371 

-0.00014241 0.00000035

2 10000.00 14999.99 0.4046777 0.0163359 

-0.00010587 0.00000024

3 10000.00 14999.99 0.309185 0.0190363 

-0.00012367 0.00000026

4 10000.00 14999.99 0.293837 0.02018312 

-0.00014294 0.00000034

5 10000.00 14999.99 0.2972705 0.02012623 

-0.00014308 0.00000035

6 10000.00 14999.99 0.2977022 0.02009143 

-0.0001426 0.00000034

7 10000.00 14999.99 0.2927846 0.0204158 

-0.0001464 0.00000036

8 10000.00 14999.99 0.00 0.000 

0.0 0.0

% --------------------------- Depth: > 8,000 ft --------------------------

@

1 15000.00 99999.00 0.3096164 0.0198371 

-0.00014241 0.00000035

1a 15000.00 99999.00 0.3096164 0.0198371 

-0.00014241 0.00000035

2 15000.00 99999.00 0.4046777 0.0163359 

-0.00010587 0.00000024

3 15000.00 99999.00 0.309185 0.0190363 

-0.00012367 0.00000026

4 15000.00 99999.00 0.293837 0.02018312 

-0.00014294 0.00000034

5 15000.00 99999.00 0.2972705 0.02012623 

-0.00014308 0.00000035

6 15000.00 99999.00 0.2977022 0.02009143 

-0.0001426 0.00000034

7 15000.00 99999.00 0.2927846 0.0204158 

-0.0001464 0.00000036

8 15000.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Cost to Equip a Primary Producer (1B)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.31969 0.019517 

-0.0001399 0.00000034

1a 0.00 99999.00 0.31969 0.019517 

-0.0001399 0.00000034

2 0.00 99999.00 0.32034 0.019534 

-0.00014 0.00000034

3 0.00 99999.00 0.32246 0.019485 

-0.0001402 0.00000034

4 0.00 99999.00 0.32422 0.019446 
-0.00014 0.00000034

5 0.00 99999.00 0.31969 0.019517 

-0.0001399 0.00000034

6 0.00 99999.00 0.31415 0.019671 

-0.0001405 0.00000034

7 0.00 99999.00 0.31969 0.019517 

-0.0001399 0.00000034

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Vertical Drilling and Completion for Gas (1C)

%

% Factor = A + B*gasprice + C*(gasprice^2) + D*(gasprice^3) (fraction)

% --------------------------- Depth: < 2,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 4999.99 0.315932 0.195761 

-0.013906 0.000336

1a 0.00 4999.99 0.315932 0.195761 

-0.013906 0.000336

2 0.00 4999.99 0.343646 0.190339 

-0.013966 0.000343

3 0.00 4999.99 0.340223 0.19022 

-0.013753 0.000335

4 0.00 4999.99 0.323862 0.19383 

-0.013821 0.000335

5 0.00 4999.99 0.325368 0.194046 

-0.013967 0.00034

6 0.00 4999.99 0.325917 0.193657 

-0.013893 0.000337

7 0.00 4999.99 0.352772 0.189511 

-0.01406 0.000347

8 0.00 4999.99 0.00 0.000 

0.0 0.0

% --------------------- Depth: 2,000 - 4,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 5000.00 9999.99 0.315932 0.195761 

-0.013906 0.000336

1a 5000.00 9999.99 0.315932 0.195761 

-0.013906 0.000336

2 5000.00 9999.99 0.343646 0.190339 

-0.013966 0.000343

3 5000.00 9999.99 0.340223 0.19022 

-0.013753 0.000335

4 5000.00 9999.99 0.323862 0.19383 

-0.013821 0.000335

5 5000.00 9999.99 0.325368 0.194046 

-0.013967 0.00034

6 5000.00 9999.99 0.325917 0.193657 

-0.013893 0.000337

7 5000.00 9999.99 0.352772 0.189511 

-0.01406 0.000347

8 5000.00 9999.99 0.00 0.000 

0.0 0.0

% --------------------- Depth: 4,000 - 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 10000.00 14999.99 0.315932 0.195761 

-0.013906 0.000336

1a 10000.00 14999.99 0.315932 0.195761 

-0.013906 0.000336

2 10000.00 14999.99 0.343646 0.190339 
-0.013966 0.000343

3 10000.00 14999.99 0.340223 0.19022 

-0.013753 0.000335

4 10000.00 14999.99 0.323862 0.19383 

-0.013821 0.000335

5 10000.00 14999.99 0.325368 0.194046 

-0.013967 0.00034

6 10000.00 14999.99 0.325917 0.193657 

-0.013893 0.000337

7 10000.00 14999.99 0.352772 0.189511 

-0.01406 0.000347

8 10000.00 14999.99 0.00 0.000 

0.0 0.0

% --------------------------- Depth: > 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 15000.00 99999.00 0.315932 0.195761 

-0.013906 0.000336

1a 15000.00 99999.00 0.315932 0.195761 

-0.013906 0.000336

2 15000.00 99999.00 0.343646 0.190339 

-0.013966 0.000343

3 15000.00 99999.00 0.340223 0.19022 

-0.013753 0.000335

4 15000.00 99999.00 0.323862 0.19383 

-0.013821 0.000335

5 15000.00 99999.00 0.325368 0.194046 

-0.013967 0.00034

6 15000.00 99999.00 0.325917 0.193657 

-0.013893 0.000337

7 15000.00 99999.00 0.352772 0.189511 

-0.01406 0.000347

8 15000.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Dry Hole (1D)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------------- Depth: < 2,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 4999.99 0.290689 0.0202617 

-0.00014329 0.000000345

1a 0.00 4999.99 0.290689 0.0202617 

-0.00014329 0.000000345

2 0.00 4999.99 0.27794 0.02052998 

-0.00014347 0.000000344

3 0.00 4999.99 0.2899717 0.0202662 

-0.000143007 0.000000344

4 0.00 4999.99 0.2781363 0.0203814 

-0.00014194 0.000000339

5 0.00 4999.99 0.29027614 0.0202674 

-0.00014328 0.000000345

6 0.00 4999.99 0.297818 0.02009243 

-0.00014272 0.000000345

7 0.00 4999.99 0.2815685 0.0204374 

-0.00014267 0.000000342

8 0.00 4999.99 0.00 0.000 

0.0 0.0

% --------------------- Depth: 2,000 - 4,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 5000.00 9999.99 0.290689 0.0202617 
-0.00014329 0.000000345

1a 5000.00 9999.99 0.290689 0.0202617 

-0.00014329 0.000000345

2 5000.00 9999.99 0.27794 0.02052998 

-0.00014347 0.000000344

3 5000.00 9999.99 0.2899717 0.0202662 

-0.000143007 0.000000344

4 5000.00 9999.99 0.2781363 0.0203814 

-0.00014194 0.000000339

5 5000.00 9999.99 0.29027614 0.0202674 

-0.00014328 0.000000345

6 5000.00 9999.99 0.297818 0.02009243 

-0.00014272 0.000000345

7 5000.00 9999.99 0.2815685 0.0204374 

-0.00014267 0.000000342

8 5000.00 9999.99 0.00 0.000 

0.0 0.0

% --------------------- Depth: 4,000 - 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 10000.00 14999.99 0.290689 0.0202617 

-0.00014329 0.000000345

1a 10000.00 14999.99 0.290689 0.0202617 

-0.00014329 0.000000345

2 10000.00 14999.99 0.27794 0.02052998 

-0.00014347 0.000000344

3 10000.00 14999.99 0.2899717 0.0202662 

-0.000143007 0.000000344

4 10000.00 14999.99 0.2781363 0.0203814 

-0.00014194 0.000000339

5 10000.00 14999.99 0.29027614 0.0202674 

-0.00014328 0.000000345

6 10000.00 14999.99 0.297818 0.02009243 

-0.00014272 0.000000345

7 10000.00 14999.99 0.2815685 0.0204374 

-0.00014267 0.000000342

8 10000.00 14999.99 0.00 0.000 

0.0 0.0

% --------------------------- Depth: > 8,000 ft --------------------------

% Region Min. Depth Max Depth A B C 

D

@

1 15000.00 99999.00 0.290689 0.0202617 

-0.00014329 0.000000345

1a 15000.00 99999.00 0.290689 0.0202617 

-0.00014329 0.000000345

2 15000.00 99999.00 0.27794 0.02052998 

-0.00014347 0.000000344

3 15000.00 99999.00 0.2899717 0.0202662 

-0.000143007 0.000000344

4 15000.00 99999.00 0.2781363 0.0203814 

-0.00014194 0.000000339

5 15000.00 99999.00 0.29027614 0.0202674 

-0.00014328 0.000000345

6 15000.00 99999.00 0.297818 0.02009243 

-0.00014272 0.000000345

7 15000.00 99999.00 0.2815685 0.0204374 

-0.00014267 0.000000342

8 15000.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Workover Costs (1E)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------
% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.3125396 0.01970713 

-0.00014062 0.00000034

1a 0.00 99999.00 0.3125396 0.01970713 

-0.00014062 0.00000034

2 0.00 99999.00 0.3159034 0.0196294 

-0.00014039 0.00000034

3 0.00 99999.00 0.31275 0.0196998 

-0.00014054 0.00000034

4 0.00 99999.00 0.281549 0.02036 

-0.000141 0.00000034

5 0.00 99999.00 0.3125396 0.01970713 

-0.00014062 0.00000034

6 0.00 99999.00 0.3165667 0.01961375 

-0.00014037 0.00000034

7 0.00 99999.00 0.3125396 0.01970713 

-0.00014062 0.00000034

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Cost to Convert a Primary to Secondary Well (2B)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.38684429 0.02368116 

-0.00016986 0.00000041

1a 0.00 99999.00 0.38684429 0.02368116 

-0.00016986 0.00000041

2 0.00 99999.00 0.403458 0.0230308 

-0.00016772 0.00000041

3 0.00 99999.00 0.3997689 0.0234099 

-0.00016901 0.00000041

4 0.00 99999.00 0.363068 0.0241333 

-0.00017548 0.00000043

5 0.00 99999.00 0.38684429 0.02368116 

-0.00016986 0.00000041

6 0.00 99999.00 0.3937975 0.0234092 

-0.000169 0.00000041

7 0.00 99999.00 0.38684429 0.02368116 

-0.00016986 0.00000041

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Cost to Convert a Producer to an Injector (2C)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.318906 0.0195642 

-0.00014032 0.00000034

1a 0.00 99999.00 0.318906 0.0195642 

-0.00014032 0.00000034

2 0.00 99999.00 0.3162087 0.0197462 

-0.00014296 0.00000035

3 0.00 99999.00 0.31895455 0.0195642 

-0.00014032 0.00000034

4 0.00 99999.00 0.3189444 0.01956323 

-0.00014032 0.00000034

5 0.00 99999.00 0.318906 0.0195642 
-0.00014032 0.00000034

6 0.00 99999.00 0.3197836 0.01953153 

-0.0001403 0.00000034

7 0.00 99999.00 0.318906 0.0195642 

-0.00014032 0.00000034

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Facilities Upgrade Cost (2D)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.32111 0.019515 

-0.00014 0.00000034

1a 0.00 99999.00 0.32111 0.019515 

-0.00014 0.00000034

2 0.00 99999.00 0.32109 0.019516 

-0.00014 0.00000034

3 0.00 99999.00 0.30541 0.019923 

-0.000143 0.00000035

4 0.00 99999.00 0.32105 0.019516 

-0.00014 0.00000034

5 0.00 99999.00 0.32111 0.019515 

-0.00014 0.00000034

6 0.00 99999.00 0.320979 0.019117 

-0.000134 0.00000034

7 0.00 99999.00 0.32111 0.019515 

-0.00014 0.00000034

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Well Facilities Cost for Gas (2E)

%

% Factor = A + B*gasprice + C*(gasprice^2) + D*(gasprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.27631 0.206 

-0.01446 0.00035

1a 0.00 99999.00 0.27631 0.206 

-0.01446 0.00035

2 0.00 99999.00 0.28085 0.20488 

-0.01439 0.00035

3 0.00 99999.00 0.28097 0.20486 

-0.01439 0.00035

4 0.00 99999.00 0.28251 0.2045 

-0.01438 0.00035

5 0.00 99999.00 0.27631 0.206 

-0.01446 0.00035

6 0.00 99999.00 0.28097 0.20486 

-0.01439 0.00035

7 0.00 99999.00 0.27631 0.206 

-0.01446 0.00035

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Fixed Annual Cost for Oil (3A)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@
1 0.00 99999.00 0.325523 0.01941538 

-0.00014 0.00000034

1a 0.00 99999.00 0.325523 0.01941538 

-0.00014 0.00000034

2 0.00 99999.00 0.305891 0.019637 

-0.00014761 0.00000036

3 0.00 99999.00 0.325452 0.0194191 

-0.00014006 0.00000034

4 0.00 99999.00 0.343679 0.020087 

-0.00015388 0.00000039

5 0.00 99999.00 0.325523 0.01941538 

-0.00014 0.00000034

6 0.00 99999.00 0.330961 0.0192954 

-0.00013978 0.00000034

7 0.00 99999.00 0.325523 0.01941538 

-0.00014 0.00000034

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Fixed Annual Cost for Gas (3B)

%

% Factor = A + B*gasprice + C*(gasprice^2) + D*(gasprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.23422 0.21676 

-0.01523 0.00037

1a 0.00 99999.00 0.23422 0.21676 

-0.01523 0.00037

2 0.00 99999.00 0.27687 0.20574 

-0.01441 0.00035

3 0.00 99999.00 0.2787 0.20537 

-0.0144 0.00035

4 0.00 99999.00 0.27973 0.20515 

-0.0144 0.00035

5 0.00 99999.00 0.23422 0.21676 

-0.01523 0.00037

6 0.00 99999.00 0.2787 0.20537 

-0.0144 0.00035

7 0.00 99999.00 0.23422 0.21676 

-0.01523 0.00037

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Annual Cost for Secondary Production (3C)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.325312 0.0194199 

-0.00014001 0.00000034

1a 0.00 99999.00 0.325312 0.0194199 

-0.00014001 0.00000034

2 0.00 99999.00 0.32175 0.019369 

-0.00014021 0.00000034

3 0.00 99999.00 0.32528 0.0194206 

-0.00014001 0.00000034

4 0.00 99999.00 0.325293 0.01942 

-0.00014001 0.00000034

5 0.00 99999.00 0.325312 0.0194199 

-0.00014001 0.00000034

6 0.00 99999.00 0.327128 0.0192837 
-0.00013842 0.00000034

7 0.00 99999.00 0.325312 0.0194199 

-0.00014001 0.00000034

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Lifting Cost (4B)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.31444 0.019667 

-0.00014064 0.00000034

1a 0.00 99999.00 0.31444 0.019667 

-0.00014064 0.00000034

2 0.00 99999.00 0.30725 0.0198433 

-0.00014134 0.00000034

3 0.00 99999.00 0.30927 0.019797 

-0.00014064 0.00000034

4 0.00 99999.00 0.30766 0.19836 

-0.0001436 0.00000034

5 0.00 99999.00 0.31444 0.019667 

-0.00014064 0.00000034

6 0.00 99999.00 0.326854 0.0193548 

-0.00014018 0.00000034

7 0.00 99999.00 0.31444 0.019667 

-0.00014064 0.00000034

8 0.00 99999.00 0.00 0.000 

0.0 0.0

%

% Cost Adjustment Factor for Secondary Workover Cost (4C)

%

% Factor = A + B*oilprice + C*(oilprice^2) + D*(oilprice^3) (fraction)

% --------------------- All Depth Categories ---------------------

% Region Min. Depth Max Depth A B C 

D

@

1 0.00 99999.00 0.3121799 0.01970524 

-0.0001404 0.00000034

1a 0.00 99999.00 0.3121799 0.01970524 

-0.0001404 0.00000034

2 0.00 99999.00 0.312249 0.019703 

-0.00014039 0.00000034

3 0.00 99999.00 0.301399 0.020286 

-0.00014527 0.00000034

4 0.00 99999.00 0.312146 0.019706 

-0.0001404 0.00000034

5 0.00 99999.00 0.3121799 0.01970524 

-0.0001404 0.00000034

6 0.00 99999.00 0.3121236 0.019707 

-0.0001404 0.00000034

7 0.00 99999.00 0.3121799 0.01970524 

-0.0001404 0.00000034

8 0.00 99999.00 0.00 0.000 

0.0 0.0

!***************************************************************

!from wlconstraints.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) Constraint Data File

%

% Sections:

% 1. Rig Data

% 2. Drilling Constraints

% 3. Capital Constraints

% 4. CO2 Constraints
%

%

%

%*****************************************************************************

%

% Section 1: Rig Data

%

% Data source: OGJ 3.16.2009 -

% Based on Actual Depth drilled

% RIG DEPTH RATING

% % OF Oil RIGS MAX BINS

% MAXDEPTH East coast Gulf Coast Midcontinent Permian Rockies West 

Coast Northern GP Rig Detph Class (ft)

@

2500 100.00 100.00 100.00 100.00 100.00 

100.00 100.00 C 0-2500

5000 100.00 86.00 97.00 92.00 94.00 

95.00 86.00 C 2501-5000

7500 83.00 85.00 96.00 91.00 91.00 

89.00 84.00 C 5000-7500

10000 67.00 79.00 69.00 87.00 76.00 

68.00 80.00 C 7501-10000

12500 50.00 61.00 36.00 61.00 48.00 

42.00 65.00 C 10001-12500

15000 50.00 47.00 28.00 36.00 23.00 

42.00 59.00 C 12501-15000

17500 0.00 29.00 12.00 13.00 8.00 

37.00 47.00 C 15001-17500

20000 0.00 26.00 4.00 7.00 3.00 

32.00 32.00 C 17501-20000

99999 0.00 0.00 0.00 0.00 0.00 

0.00 0.00 C 20001- +

%

% Data source: OGJ 3.16.2009 -

% Based on Actual Depth drilled

% RIG DEPTH RATING FOR GAS

% % OF Gas RIGS MAX BINS

% MAXDEPTH East coast Gulf Coast Midcontinent Permian Rockies West 

Coast Northern GP Rig Detph Class (ft)

@

2500 100.00 100.00 100.00 100.00 100.00 

100.00 100.00 C 0-2500

5000 95.00 91.00 97.00 94.00 93.00 

86.00 100.00 C 2501-5000

7500 88.00 90.00 96.00 94.00 93.00 

86.00 100.00 C 5000-7500

10000 71.00 86.00 95.00 91.00 86.00 

57.00 100.00 C 7501-10000

12500 40.00 74.00 76.00 65.00 56.00 

29.00 100.00 C 10001-12500

15000 31.00 68.00 68.00 47.00 43.00 

0.00 100.00 C 12501-15000

17500 14.00 52.00 54.00 21.00 26.00 

0.00 100.00 C 15001-17500

20000 10.00 46.00 47.00 19.00 21.00 

0.00 100.00 C 17501-20000

99999 0.00 0.00 0.00 0.00 0.00 

0.00 0.00 C 20001- +

%

% Do you want to use the national rig depth rating constraint? (Y/N)

@

Y

%

% * * * * * * * * * * * * * * * * * * * * * * * * * *

% Drilling rig equations

% #rigs = A*ln(oil price) + B, where oil price is $/Bbl
%

% region A B

@

1 41.8465 -93.3466 C EAST COAST

2 166.7310 -260.3122 C GULF COAST

3 165.6901 -381.8852 C MIDCONTINENT

4 291.8677 -761.8706 C SOUTHWEST

5 146.4758 -340.2829 C ROCKY MOUNTAINS

6 20.1000 -48.6162 C WEST COAST

7 44.6464 -121.5713 C NORTHERN GREAT PLAINS

%

%

% Footage available = #rigs * utilization * average rate * %rigs capable of

% drilling in the depth categories above

@

0.8 !rig utilization (fr)

15.9 !average penetration rate (ft/hr)

%

%

% Rig concentration (%)

% This is the maximum percentage of rigs which are deployed in a single

% play within the depth class

%

% Conc max depth depth range

@

50.00 2500 0-2500

50.00 5000 2501-5000

50.00 7500 5000-7500

50.00 10000 7501-10000

50.00 12500 10001-12500

50.00 15000 12501-15000

50.00 17500 15001-17500

50.00 20000 17501-20000

50.00 99999 20001- +

%*****************************************************************************

%

% Section 2: Drilling Constraints

% A. Oil Drilling and Dryhole

% B. Gas Drilling and Dryhole

% C. Exploration Drilling and Dryhole

% D. Distribution Controls and Multipliers

%

% Note: All Drilling Equations are in Feet

%

%-----------------------------------------------------------------------------

% Section 2.A: Oil Drilling and Dryhole

% OIL WELL FOOTAGE EQUATION (Thousand Feet)

% Forecast = Footage * (1 + (Incremental year - year1) * Growth Rate)

% Oil Dev Footage = A0 + A1 * Oil Price + A2 * Oil Price^3 + A3 * Oil Price * Gas Price

@

23726.4078 839.7889 0.0416 -74.6733 0.000

% Existing Dryhole Rate = Developed Dryhole / Total Drilling (thousand feet)

% Dry Dev Footage = A0 +A1 * Oil Price^2 * + A2 * Oil Price^3 + A3 * Gas price + A4 * 

Gas Price^2

@

22111.8088 0.3689 0.0002 -2768.8619 241.4373

%

% REGIONAL DISTRIBUTION OF OIL DRILLING FOOTAGE

% REGION REGION % existing dryhole rate (also applied to gas)

@

1 2.500 2.800

2 9.400 7.000

3 13.500 7.800

4 49.800 5.500

5 5.500 1.100

6 4.200 5.400
7 15.200 1.800

%

%

%-----------------------------------------------------------------------------

% Section 2.B: Gas Drilling and Dryhole

% GAS WELL FOOTAGE EQUATION (Thousand Feet)

% Gas Dev Footage = A0 + A1 * Oil Price + A2 * Gas Price^2

@

14602.8232 1513.3128 1131.8266 0.000 0.000

% Existing Dryhole Rate = Developed Dryhole / Total Drilling (thousand feet)

% Dry Dev Footage = A0 +A1 * Oil Price^2 * + A2 * Oil Price^3 + A3 * Gas price + A4 * 

Gas Price^2

@

22111.8088 0.3689 0.0002 -2768.8619 241.4373

%

% REGIONAL DISTRIBUTION OF GAS DRILLING FOOTAGE

% REGION REGION %

@

1 9.900

2 40.200

3 16.200

4 7.900

5 25.300

6 0.200

7 0.300

%

%

%-----------------------------------------------------------------------------

% Section 2.C:Exploration Drilling and Dryhole

% EXPLORATION WELL FOOTAGE EQUATION (Thousand Feet)

% Oil Footage = A0 + A1 * Oil Price^2 * + A2 * Gas price + A3 * Oil Price * Gas Price 

+ A4 * Oil Price^2 * Gas Price

% Gas Footage = A0 + A1 * Oil Price^2 * + A2 * Gas price + A3 * Oil Price * Gas Price 

+ A4 * Oil Price^2 * Gas Price

% Dry Footage = A0 + A1 * Oil Price * + A2 * Oil price^2 + A3 * Oil Price^3 + A4 * Gas 

Price

@

3700.2033 1.6432 -356.1698 0.0000 -0.1084 !oil footage

3048.2708 0.0000 0.0000 23.0787 0.0000 !gas footage

28226.7366 1213.0103 -23.4564 0.1356 -19000.6302 !dry footage

%

% REGION Dry Hole RATE | REGION %

% exploration development | Oil Gas

@

1 7.700 5.000 1.400 77.200 9.1

2 176.600 9.500 6.000 7.000 32.7

3 79.600 12.900 26.100 11.400 39.4

4 53.000 6.300 11.300 1.600 8.6

5 41.500 1.800 7.900 2.500 5.6

6 36.700 6.900 1.000 0.100 1.2

7 6.000 2.800 46.300 0.300 3.4

%

%

%-----------------------------------------------------------------------------

% Section 2.D: Distribution Controls and Multipliers

%

% Do you want to use (N)ational or (R)egional drilling constraints?

@

R

% Do you want to split constraints between oil and gas? (Y/N)

@

Y

% What percentage of the development drilling can be transferred between resources? (%)

@

0.00

% Do you want to split between exploration and development drilling? (Y/N)
@

Y

% What percentage of the exploration drilling constraint will be for conventional? (%)

@

10.00 !oil

25.00 !gas

% Do you want to split oil drilling between horizontal and vertical? (Y/N)

@

Y

% What percentage of the oil drilling constraint is available for horizontal drilling? 

(%)

@

1.00

% What percentage of drilling constraint can be transferred between regions? (%)

@

50.00

% What percentage of the drilling constraint is available for footage over run? (%)

@

20.00

% What is the annual drilling growth rate (%)

@

4.75

% What is the annual drilling retirement rate (%)

@

0.75

% Exploration drilling constraint multiplier

@

1.00

% Total drilling constraint multiplier

@

1.00

% Horizontal drilling constraint multiplier

@

1.0

% Horizontal well growth rate (%) - applied to the annual national horizontal drilling 

footage

@

1.25

% Horizontal success rate (%)

@

75

%

%*****************************************************************************

%

% Section 3: Capital Constraints

% (Million Dollars)

%

% YR 1 YR 2 YR 3 YR 4 YR 5 YR 6 YR 7 YR 8 YR 9 

YR10 YR11 YR12 YR13 YR14 YR15 YR16 YR17 YR18 

YR19 YR20 YR21 YR22 YR23 YR24 YR25 YR26 YR27 

YR28 YR29 YR30 YR31 YR32 YR33 YR34 YR35 YR36 

YR37 YR38 YR39 YR40 YR41 YR42 YR43 YR44 YR45

@

95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 

95000.0 95000.0 95000.0 95000.0

95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 

95000.0 95000.0 95000.0 95000.0

95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 

95000.0 95000.0 95000.0 95000.0

95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0 95000.0

%

% Capital constraint multiplier

@

1.0

%

%*****************************************************************************
%

% Section 4: CO2 Constraints

%

@

Y C Use NATURAL sources of CO2 (Y/N)

Y C Use INDUSTRIAL sources of CO2 (Y/N)

%

% BASE CO2 VOLUMES BY REGION AND SOURCE (BCF/YR)

% EAST COAST GULF COAST MIDCONTINENT SOUTHWEST ROCKY MOUNTAINS WEST COAST 

NORTHERN GREAT PLAINS C SOURCE

@

3.06 0.00 0.00 0.00 0.00 0.00 

0.00 C HYDROGEN

0.00 78.18 0.15 0.00 3.37 0.00 

0.00 C AMMONIA

52.02 0.00 174.96 68.04 23.04 3.96 

9.00 C ETHANOL

0.00 291.96 16.02 657.00 79.92 0.00 

0.00 C NATURAL

93.99 86.41 48.02 73.97 35.09 47.53 

3.21 C CEMENT

16.73 113.66 0.71 0.00 61.60 92.92 

15.71 C HYDROGEN REFINERIES

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 C PLANNED POWER PLANTS

12979.98 3929.94 752.00 0.00 2907.00 1134.00 

59.94 C POWER PLANTS

22.68 113.94 0.00 0.36 11.88 39.96 

6.48 C NATURAL GAS PROCESSING

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 C PLANNED COAL TO LIQUIDS

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 C COAL TO LIQUIDS

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 C NEW SOURCE 1

0.00 0.00 0.00 0.00 0.00 0.00 

0.00 C NEW SOURCE 2

%

% CO2 Availibility constraint multiplier

@

1.0

%

%

% DEVELOPMENT LEVERS TO BE APPLIED TO EXISTING CO2 SOURCES

%

% YEARS TO DEVELOP TECHNOLOGY (R&D PHASE) BY SOURCE

% YEARS SOURCE

@

0 C HYDROGEN

0 C AMMONIA

0 C ETHANOL

0 C NATURAL

0 C CEMENT

0 C HYDROGEN REFINERIES

0 C PLANNED POWER PLANTS

0 C POWER PLANTS

0 C NATURAL GAS PROCESSING

0 C PLANNED COAL TO LIQUIDS

0 C COAL TO LIQUIDS

0 C NEW SOURCE 1

0 C NEW SOURCE 2

%

% YEARS TO DEVELOP INFRASTRUCTURE (CAPTURE TECHNOLOGY AND PIPELINE CONSTRUCTION PHASE) BY 

SOURCE

% YEARS SOURCE

@
4 C HYDROGEN

2 C AMMONIA

4 C ETHANOL

0 C NATURAL

7 C CEMENT

4 C HYDROGEN REFINERIES

100 C PLANNED POWER PLANTS

12 C POWER PLANTS

2 C NATURAL GAS PROCESSING

100 C PLANNED COAL TO LIQUIDS

100 C COAL TO LIQUIDS

100 C NEW SOURCE 1

100 C NEW SOURCE 2

%

% YEARS TO REACH FULL CAPACITY (MARKET ACCEPTANCE) BY SOURCE

% YEARS SOURCE

@

10 C HYDROGEN

10 C AMMONIA

10 C ETHANOL

10 C NATURAL

10 C CEMENT

10 C HYDROGEN REFINERIES

100 C PLANNED POWER PLANTS

10 C POWER PLANTS

10 C NATURAL GAS PROCESSING

100 C PLANNED COAL TO LIQUIDS

100 C COAL TO LIQUIDS

100 C NEW SOURCE 1

100 C NEW SOURCE 2

%

%

% ANNUAL ACCEPTANCE RATE (% OF ULTIMATE MARKET ACCEPTANCE / YEAR OF MARKET ACCEPTANCE) BY 

SOURCE

@

5.0 5.0 5.0 5.0 5.0 10.0 10.0 10.0 10.0 35.0 C 

HYDROGEN

5.0 5.0 5.0 5.0 5.0 10.0 10.0 10.0 10.0 35.0 C 

AMMONIA

3.0 3.0 3.0 3.0 3.0 5.0 10.0 15.0 15.0 40.0 C 

ETHANOL

25.0 25.0 50.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 C 

NATURAL

5.0 5.0 5.0 5.0 5.0 10.0 10.0 10.0 10.0 35.0 C 

CEMENT

5.0 5.0 5.0 5.0 5.0 10.0 10.0 10.0 10.0 35.0 C 

HYDROGEN REFINERIES

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 C 

PLANNED POWER PLANTS

1.0 2.0 2.0 5.0 10.0 10.0 10.0 10.0 10.0 40.0 C 

POWER PLANTS

5.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 15.0 C 

NATURAL GAS PROCESSING

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 C 

PLANNED COAL TO LIQUIDS

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 C COAL 

TO LIQUIDS

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 C NEW 

SOURCE 1

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 C NEW 

SOURCE 2

%

%

% ULTIMATE MARKET ACCEPTANCE (%) BY SOURCE

@

100.0 C HYDROGEN
100.0 C AMMONIA

100.0 C ETHANOL

100.0 C NATURAL

100.0 C CEMENT

100.0 C HYDROGEN REFINERIES

0.0 C PLANNED POWER PLANTS

100.0 C POWER PLANTS

100.0 C NATURAL GAS PROCESSING

0.0 C PLANNED COAL TO LIQUIDS

0.0 C COAL TO LIQUIDS

0.0 C NEW SOURCE 1

0.0 C NEW SOURCE 2

!***************************************************************

!from wladjust.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS)

% Drilling Adjustment Factors

%

%

% Fraction of total drilling available in a particular year

% format: (f5.3)

%*****************************************************************************

%

% Drilling

% Category YR 1 YR 2 YR 3 YR 4 YR 5 YR 6 YR 

7 YR 8 YR 9 YR 10 YR 11 YR 12 YR 13 YR 14 YR 15 

YR 16 YR 17 YR 18 YR 19 YR 20 YR 21 YR 22 YR 23 

YR 24 YR 25 YR 26 YR 27 YR 28 YR 29 YR 30 YR 31 

YR 32 YR 33 YR 34 YR 35 YR 36 YR 37 YR 38 YR 39 

YR 40 YR 41 YR 42 YR 43 YR 44 YR 45 YR 46

@

Oil Drilling 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000

Gas Drilling 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000

Oil Exploration 0.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000

Gas Exploration 0.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000

Horizontal 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 

1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000

!***************************************************************

!from wlaccess.txt

%*****************************************************************************************

*************************

%
% Onshore Lower 48 Oil and Gas Supply Submodule

%

% Resource Access File

%

% This file contains the years in which the UNDISCOVERED resources

% in each PROVINCE become available for exploration. 9999 indicates

% that the resource, in that category, is NOT available during the

% span of the analysis

%

% There are FOUR resource access categories for each province:

% 1 No Leasing (Statutory/Executive Order) (NLS)

% 2 Leasing, Cumulative Timing Limitations (TLs) of between 3 and 9 Months

% 3 Leasing, Controlled Surface Use (CSU)

% 4 Leasing, Standard Lease Terms (SLTs)

%

% PROVINCE YEAR YEAR YEAR YEAR PROVINCE

% NUMBER CAT 1 CAT 2 CAT 3 CAT 4 NAME

%

%*****************************************************************************************

*************************

@

5001 9999 9999 9999 9999 North Slope ANWR

5002 9999 9999 9999 9999 Central Alaska

5003 9999 9999 9999 9999 Southern Alaska

5004 9999 2001 2003 2005 Western Oregon-Wash.

5005 9999 2001 2003 2005 Eastern Oregon-Wash.

5007 9999 2001 2003 2005 Northern Coastal

5008 9999 2001 2003 2005 Sonoma-Livermore

5009 9999 2001 2003 2005 Sacramento Basin

5010 9999 2001 2003 2005 San Joaquin Basin

5011 9999 2001 2003 2005 Central Coastal

5012 9999 2001 2003 2005 Santa Maria Basin

5013 9999 2001 2003 2005 Ventura Basin

5014 9999 2001 2003 2005 Los Angeles Basin

5017 9999 2001 2003 2005 Idaho-Snake River Downwarp

5018 9999 2001 2003 2005 Western Great Basin

5019 9999 2001 2003 2005 Eastern Great Basin

5020 9999 2001 2003 2005 Uinta-Piceance Basin

5021 9999 2001 2003 2005 Paradox Basin

5022 2001 2001 2003 2005 San Juan Basin

5023 9999 2001 2003 2005 Albuquerque-Sante Fe Rift

5024 9999 2001 2003 2005 Northern Arizona

5025 9999 2001 2003 2005 S. Ariz.-S.W. New Mexico

5026 9999 2001 2003 2005 South-Central New Mexico

5027 9999 2001 2003 2005 Montana Thrust Belt

5028 9999 2001 2003 2005 Central Montana

5029 9999 2001 2003 2005 Southwest Montana

5030 9999 2001 2003 2005 Hanna, Laramie, and Shirley Basins

5031 9999 2001 2003 2005 Williston Basin

5033 9999 2001 2003 2005 Powder River Basin

5034 9999 2001 2003 2005 Big Horn Basin

5035 9999 2001 2003 2005 Wind River Basin

5036 9999 2001 2003 2005 Wyoming Thrust Belt

5037 9999 2001 2003 2005 Southwestern Wyoming

5038 9999 2001 2003 2005 Park Basins

5039 9999 2001 2003 2005 Denver Basin

5040 9999 2001 2003 2005 Las Animas Arch

5041 9999 2001 2003 2005 Raton Basin-Sierra Grande Uplift

5043 9999 2001 2003 2005 Palo Duro Basin

5044 9999 2001 2003 2005 Permian Basin

5045 9999 2001 2003 2005 Bend Arch-Ft. Worth Basin

5046 9999 2001 2003 2005 Marathon Thrust Belt

5047 9999 2001 2003 2005 Western Gulf

5049 9999 2001 2003 2005 East Texas Basin/LA-MS Salt Basins

5050 9999 2001 2003 2005 Florida Peninsula

5051 9999 2001 2003 2005 Superior
5053 9999 2001 2003 2005 Cambridge Arch-Central Kansas

5055 9999 2001 2003 2005 Nemaha Uplift

5056 9999 2001 2003 2005 Forest City Basin

5058 9999 2001 2003 2005 Anadarko Basin

5059 9999 2001 2003 2005 Sedgwick Basin/Salina Basin

5060 9999 2001 2003 2005 Cherokee Platform

5061 9999 2001 2003 2005 Southern Oklahoma

5062 9999 2001 2003 2005 Arkoma Basin

5063 9999 2001 2003 2005 Michigan Basin

5064 9999 2001 2003 2005 Illinois Basin

5065 9999 2001 2003 2005 Black Warrior Basin

5066 9999 2001 2003 2005 Cincinnati Arch

5067 9999 2001 2003 2005 Appalachian Basin

5068 9999 2001 2003 2005 Blue Ridge Thrust Belt

5069 9999 2001 2003 2005 Piedmont

%

!***************************************************************

!from wlpattern.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS)

% Development Schedule File

%

%*****************************************************************************

% % DEVELOPMENT MAXIMUM NUMBER MINIMUM NUMBER PROCESS PROCESS

% PER YEAR OF WELLS PER YEAR OF WELLS PER YEAR CODE NAME

%

@

10.00 20 10 00 Decline Curve

10.00 20 10 01 Primary

10.00 20 10 02 Water Flooding

10.00 10 5 03 CO2 Flooding

10.00 10 5 04 Steam Flooding

10.00 10 5 05 Polymer 

Flooding

10.00 10 5 06 Infill 

Drilling

10.00 10 5 07 Profile 

Modification

10.00 10 5 08 Horizontal 

Continuity

10.00 10 5 09 Horizontal 

Profile

10.00 10 5 10 Undiscovered 

Conventional Oil

10.00 20 10 11 Conventional 

Radial Flow

10.00 20 10 12 Water Drive

10.00 20 10 13 Tight Sands

10.00 20 10 14 Wet 

Coal/Shale Gas

10.00 20 10 15 Dry 

Coal/Shale Gas

10.00 20 10 16 Undiscovered 

Conventional Gas

10.00 100 2 17 Undiscovered 

Unconventional Oil

10.00 100 2 18 Undiscovered 

Tight Gas

10.00 20 2 19 Undiscovered 

Coalbed Methane

10.00 100 2 20 Undiscovered 

Shale Gas

10.00 100 2 21 Developing 

Shale Gas

10.00 100 2 22 Developing 
Tight Gas

10.00 20 2 23 Developing 

Coalbed Methane

%

!***************************************************************

!from wlprice.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) Price Data File

%

% Sections:

% 1. Fixed Prices

% 2. Price Track

% 3. Prices for Gas Processing Byproducts

% 4. Prices for Economic Prescreening

%

%*****************************************************************************

% Section 1: Fixed Prices

%

@

N C Use fixed prices? (Y/N)

80.00 C Fixed Oil Price ($/Bbl)

5.00 C Fixed Natural Gas Price ($/Mcf)

0.00 C Annual Inflation Factor (Percent)

%

%*****************************************************************************

% Section 2: Price Track

%

% First Year for Price Track

@

2003

%

% Row 1: Annual Oil Prices ($/Bbl)

% Row 2: Annual Gas Prices ($/Mcf)

%

%

% 2003 2004 2005 2006 2007 2008 2009 2010 2011 

2012 2013 2014 2015 2016 2017 2018 2019 2020 

2021 2022 2023 2024 2025 2026 2027 2028 2029 

2030

@

31.08 41.51 56.64 61.80 65.70 95.68 53.02 70.98 80.24 

89.57 93.68 104.07 107.45 108.41 107.97 109.62 109.50 108.34 

109.02 110.66 110.64 111.73 112.56 113.34 116.34 117.50 119.03 

121.09

4.88 5.46 7.33 6.48 6.22 7.78 5.58 5.76 5.75 

5.90 5.91 6.02 6.09 6.21 6.32 6.52 6.67 6.57 

6.41 6.55 6.60 6.88 7.11 7.44 7.80 7.92 8.08 

8.17

%@

%20.00 21.00 22.00 23.00 24.00 25.00 26.00 27.00 28.00 29.00 30.00 

31.00 32.00 33.00 34.00 35.00 36.00 37.00 38.00 39.00 40.00 41.00 

42.00 43.00 44.00 45.00 46.00 47.00

%4.00 4.50 5.00 5.50 6.00 6.50 7.00 7.50 8.00 8.50 9.00 

9.50 10.00 10.50 11.00 11.50 12.00 12.50 13.00 13.50 14.00 14.50 

15.00 15.50 16.00 16.50 17.00 17.50

%

%*****************************************************************************

% Section 3: Prices for Gas Processing Byproducts

%

@

0.65 C CO2 price ($/Mcf)

130.00 C H2S price ($/metric ton)

0.30 C alpha for NGL price ($/Bbl) nglprice = alpha*oilprice+5

1.30 C N2 price ($/Mcf)

%

%*****************************************************************************

% Section 4: Prices for Economic Prescreening
%

@

F C USE F(ixed) or Highest T(rack) Price?

100.00 C Fixed Price ($/Bbl)

7.00 C Fixed Price ($/Mcf)

%

@

200.00 C Fixed Oil Price ($/Bbl) for CO2 economic prescreening

%

%

!***************************************************************

!from wlplaymap.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS)

%

% This File Conatins Information for Province and the Play

%

% Rows:

% 1. Province_Num

% 2. Play_Num

% 3. Province_Name

%

%*****************************************************************************

%

%

% PROVINCE_NUM PLAY_NUM PROVINCE_NAME

@

1 101 Northern Alaska

1 102 Northern Alaska

1 103 Northern Alaska

1 104 Northern Alaska

1 105 Northern Alaska

1 106 Northern Alaska

1 107 Northern Alaska

1 108 Northern Alaska

1 109 Northern Alaska

1 110 Northern Alaska

1 111 Northern Alaska

2 201 Central Alaska

2 202 Central Alaska

2 203 Central Alaska

2 204 Central Alaska

2 205 Central Alaska

3 301 Southern Alaska

3 302 Southern Alaska

3 303 Southern Alaska

3 304 Southern Alaska

3 305 Southern Alaska

3 306 Southern Alaska

3 307 Southern Alaska

3 308 Southern Alaska

3 309 Southern Alaska

4 401 Western Oregon - Washington

4 402 Western Oregon - Washington

4 403 Western Oregon - Washington

4 404 Western Oregon - Washington

4 405 Western Oregon - Washington

4 406 Western Oregon - Washington

4 407 Western Oregon - Washington

4 408 Western Oregon - Washington

4 410 Western Oregon - Washington

4 450 Western Washington - Bellingham Basin

4 451 Western Washington - Western Cascade Mountains

4 452 Western Washington - Southern Puget Lowlands

5 501 Eastern Oregon - Washington

5 502 Eastern Oregon - Washington
5 503 Columbia Basin - Basin Centered Gas

5 503 Columbia Basin - Basin Centered Gas

7 701 Northern Coastal

7 702 Northern Coastal

7 703 Northern Coastal

8 801 Sonoma - Livermore Basin

9 901 Sacramento Basin

9 902 Sacramento Basin

9 903 Sacramento Basin

10 1001 San Joaquin Basin

10 1002 San Joaquin Basin

10 1003 San Joaquin Basin

10 1004 San Joaquin Basin

10 1005 San Joaquin Basin

10 1006 San Joaquin Basin

10 1007 San Joaquin Basin

10 1008 San Joaquin Basin

10 1009 San Joaquin Basin

10 1010 San Joaquin Basin

10 1011 San Joaquin Basin

11 1101 Central Coastal

11 1102 Central Coastal

11 1103 Central Coastal

11 1104 Central Coastal

11 1105 Central Coastal

11 1106 Central Coastal

11 1107 Central Coastal

11 1109 Central Coastal

12 1201 Santa Maria Basin

12 1202 Santa Maria Basin

12 1204 Santa Maria Basin

12 1211 Santa Maria Basin

13 1301 Ventura Basin

13 1302 Ventura Basin

13 1304 Ventura Basin

13 1311 Ventura Basin

13 1312 Ventura Basin

14 1401 Los Angeles Basin

14 1402 Los Angeles Basin

14 1403 Los Angeles Basin

14 1404 Los Angeles Basin

14 1405 Los Angeles Basin

14 1406 Los Angeles Basin

14 1407 Los Angeles Basin

17 1701 Idaho - Snake River Downwarp

17 1702 Idaho - Snake River Downwarp

17 1703 Idaho - Snake River Downwarp

17 1704 Idaho - Snake River Downwarp

18 1801 Western Great Basin

18 1802 Western Great Basin

18 1803 Western Great Basin

18 1804 Western Great Basin

18 1805 Western Great Basin

19 1901 Eastern Great Basin

19 1902 Eastern Great Basin

19 1903 Eastern Great Basin

19 1905 Eastern Great Basin

19 1906 Eastern Great Basin

19 1907 Eastern Great Basin

20 2001 Uinta - Piceance Basin

20 2002 Uinta - Piceance Basin

20 2003 Uinta - Piceance Basin

20 2004 Uinta - Piceance Basin

20 2005 Uinta - Piceance Basin

20 2014 Uinta - Piceance Basin

20 2050 Uinta Basin - Book Cliffs
20 2051 Uinta Basin - Sego

20 2052 Uinta Basin - Emery

20 2053 Piceance Basin - White River Dome

20 2054 Piceance Basin - Western Basin Margin

20 2055 Piceance Basin - Grand Hogback

20 2056 Piceance Basin - Divide Creek Anticline

20 2057 Piceance Basin - Igneous Intrusion

20 2007 Tight Gas Piceance Mesaverde Williams Fork

20 2009 Cretaceous Self-Sourced Fractured Shales Oil

20 2010 Tight Gas Piceance Mesaverde Iles

20 2015 Tight Gas Uinta Tertiary East

20 2015 Tight Gas Uinta Tertiary East

20 2016 Tight Gas Uinta Tertiary West

20 2016 Tight Gas Uinta Tertiary West

20 2018 Basin Flank Uinta Mesaverde

20 2020 Deep Synclinal Uinta Mesaverde

21 2101 Paradox Basin

21 2102 Paradox Basin

21 2104 Paradox Basin

21 2105 Paradox Basin

21 2106 Paradox Basin

21 2107 Paradox Basin

21 2103 Fractured Interbed

22 2204 San Juan Basin

22 2206 San Juan Basin

22 2207 San Juan Basin

22 2210 San Juan Basin

22 2212 San Juan Basin

22 2250 San Juan Basin - Overpressured

22 2252 San Juan Basin - Underpressured Discharge

22 2253 San Juan Basin - Underpressured

22 2205 Dakota Central Basin Gas

22 2208 Mancos Fractured Shale

22 2209 Central Basin Mesaverde Gas

22 2211 Pictured Cliffs Gas

23 2301 Albuquerque - Santa Fe Rift

23 2302 Albuquerque - Santa Fe Rift

23 2303 Albuquerque - Santa Fe Rift

23 2304 Albuquerque - Santa Fe Rift

23 2305 Albuquerque - Santa Fe Rift

24 2401 Northern Arizona

24 2402 Northern Arizona

24 2403 Northern Arizona

24 2404 Northern Arizona

25 2501 Southern Arizona - Southwestern New Mexico

25 2502 Southern Arizona - Southwestern New Mexico

25 2503 Southern Arizona - Southwestern New Mexico

25 2504 Southern Arizona - Southwestern New Mexico

26 2602 South-Central New Mexico

26 2603 South-Central New Mexico

27 2701 Montana Thrust Belt

27 2704 Montana Thrust Belt

27 2705 Montana Thrust Belt

27 2706 Montana Thrust Belt

27 2707 Montana Thrust Belt

28 2801 North-Central Montana

28 2802 North-Central Montana

28 2803 North-Central Montana

28 2805 North-Central Montana

28 2806 North-Central Montana

28 2807 North-Central Montana

28 2808 North-Central Montana

28 2809 North-Central Montana

28 2804 Bakken Shale Fracture Systems

28 2810 Northern Great Plains Biogenic Gas, High Potenti

28 2811 Northern Great Plains Biogenic Gas, Moderate Pot
28 2812 Northern Great Plains Biogenic Gas, Low Potentia

29 2901 Southwest Montana

29 2903 Southwest Montana

29 2904 Southwest Montana

29 2905 Southwest Montana

29 2906 Southwest Montana

29 2907 Southwest Montana

29 2908 Southwest Montana

29 2910 Southwest Montana

31 3101 Williston Basin

31 3102 Williston Basin

31 3103 Williston Basin

31 3105 Williston Basin

31 3106 Williston Basin

31 3107 Williston Basin

31 3110 Bakken Fairway

31 3111 Bakken Intermediate

31 3112 Bakken Outlying

31 3113 Southern Williston Basin Margin - Niobrara Shall

32 3202 Sioux Arch

33 3301 Powder River Basin

33 3302 Powder River Basin

33 3303 Powder River Basin

33 3304 Powder River Basin

33 3305 Powder River Basin

33 3306 Powder River Basin

33 3307 Powder River Basin

33 3309 Powder River Basin

33 3310 Powder River Basin

33 3312 Powder River Basin

33 3313 Powder River Basin

33 3315 Powder River Basin

33 3350 Powder River Basin - Shallow Mining-Related

33 3351 Powder River Basin - Central Basin

34 3401 Big Horn Basin

34 3402 Big Horn Basin

34 3403 Big Horn Basin

34 3405 Big Horn Basin

34 3406 Big Horn Basin

34 3407 Big Horn Basin

34 3408 Big Horn Basin

34 3410 Big Horn Basin

34 3411 Big Horn Basin

34 3412 Big Horn Basin

34 3413 Big Horn Basin

34 3414 Big Horn Basin

34 3416 Big Horn Basin

34 3417 Big Horn Basin

35 3501 Wind River Basin

35 3502 Wind River Basin

35 3503 Wind River Basin

35 3504 Wind River Basin

35 3506 Wind River Basin

35 3509 Wind River Basin

35 3510 Wind River Basin

35 3511 Wind River Basin

35 3512 Wind River Basin

35 3513 Wind River Basin

35 3515 Wind River Basin

35 3518 Wind River Basin

35 3550 Wind River Basin - Mesaverde

36 3601 Wyoming Thrust Belt

36 3602 Wyoming Thrust Belt

36 3603 Wyoming Thrust Belt

36 3604 Wyoming Thrust Belt

36 3606 Wyoming Thrust Belt
36 3607 Wyoming Thrust Belt

37 3701 Southwestern Wyoming

37 3702 Southwestern Wyoming

37 3703 Southwestern Wyoming

37 3704 Southwestern Wyoming

37 3705 Southwestern Wyoming

37 3706 Southwestern Wyoming

37 3707 Southwestern Wyoming

37 3708 Southwestern Wyoming

37 3709 Southwestern Wyoming

37 3750 Greater Green River Basin - Rock Springs

37 3751 Greater Green River Basin - Iles

37 3752 Greater Green River Basin - Williams Fork

37 3753 Greater Green River Basin - Almond

37 3754 Greater Green River Basin - Lance

37 3755 Greater Green River Basin - Fort Union

37 3740 Greater Green River Basin - Cloverly-Frontier

37 3740 Greater Green River Basin - Cloverly-Frontier

37 3741 Greater Green River Basin - Mesaverde

37 3741 Greater Green River Basin - Mesaverde

37 3742 Greater Green River Basin - Lewis

37 3742 Greater Green River Basin - Lewis

37 3743 Greater Green River Basin - Fox Hills-Lance

37 3743 Greater Green River Basin - Fox Hills-Lance

37 3744 Greater Green River Basin - Fort Union

37 3744 Greater Green River Basin - Fort Union

38 3801 Park Basins

38 3802 Park Basins

39 3901 Denver Basin

39 3903 Denver Basin

39 3905 Denver Basin

39 3907 Denver Basin

39 3908 Denver Basin

39 3910 Denver Basin

39 3904 Greater Wattenberg Codell/Niobrara Oil and Gas

39 3906 J Sandstone Deep Gas (Wattenberg)

39 3920 Fractured Niobrara - Greater Silo/Dale Salt-Edge

39 3921 Fractured Niobrara - Greater Northern Denver Bas

40 4001 Las Animas Arch

40 4004 Las Animas Arch

40 4005 Las Animas Arch

41 4101 Raton Basin - Sierra Grande Uplift

41 4102 Raton Basin - Sierra Grande Uplift

41 4150 Northern Raton Basin

41 4151 Raton Basin - Purgatoire River

41 4152 Southern Raton Basin

42 4201 Pedernal Uplift

43 4301 Palo Duro Basin

44 4401 Permian Basin

44 4402 Permian Basin

44 4403 Permian Basin

44 4404 Permian Basin

44 4405 Permian Basin

44 4406 Permian Basin

44 4407 Permian Basin

44 4408 Permian Basin

44 4409 Permian Basin

44 4410 Permian Basin

44 4411 Permian Basin

44 4412 Permian Basin

45 4501 Bend Arch - Fort Worth Basin

45 4502 Bend Arch - Fort Worth Basin

45 4504 Bend Arch - Fort Worth Basin

45 4505 Bend Arch - Fort Worth Basin

45 4506 Bend Arch - Fort Worth Basin

45 4510 Bend Arch - Fort Worth Basin
46 4601 Marathon Thrust Belt

47 4701 Western Gulf

47 4702 Western Gulf

47 4703 Western Gulf

47 4704 Western Gulf

47 4705 Western Gulf

47 4706 Western Gulf

47 4707 Western Gulf

47 4708 Western Gulf

47 4709 Western Gulf

47 4710 Western Gulf

47 4711 Western Gulf

47 4713 Western Gulf

47 4714 Western Gulf

47 4715 Western Gulf

47 4716 Western Gulf

47 4717 Western Gulf

47 4718 Western Gulf

47 4719 Western Gulf

47 4720 Western Gulf

47 4721 Western Gulf

47 4722 Western Gulf

47 4723 Western Gulf

47 4724 Western Gulf

47 4725 Western Gulf

47 4726 Western Gulf

47 4727 Western Gulf

47 4728 Western Gulf

47 4729 Western Gulf

47 4730 Western Gulf

47 4731 Western Gulf

47 4732 Western Gulf

47 4733 Western Gulf

47 4734 Western Gulf

47 4735 Western Gulf

47 4736 Western Gulf

47 4737 Western Gulf

47 4738 Western Gulf

47 4739 Western Gulf

47 4740 Western Gulf

47 4741 Western Gulf

47 4742 Western Gulf

47 4743 Western Gulf

47 4744 Western Gulf

47 4745 Western Gulf

47 4746 Western Gulf

47 4747 Austin Chalk-Pearsall

47 4748 Austin Chalk-Giddings

47 4749 Austin Chalk-Outlying

49 4901 Louisiana-Mississippi Salt Basins

49 4902 Louisiana-Mississippi Salt Basins

49 4903 Louisiana-Mississippi Salt Basins

49 4904 Louisiana-Mississippi Salt Basins

49 4905 Louisiana-Mississippi Salt Basins

49 4906 Louisiana-Mississippi Salt Basins

49 4907 Louisiana-Mississippi Salt Basins

49 4908 Louisiana-Mississippi Salt Basins

49 4909 Louisiana-Mississippi Salt Basins

49 4910 Louisiana-Mississippi Salt Basins

49 4911 Louisiana-Mississippi Salt Basins

49 4912 Louisiana-Mississippi Salt Basins

49 4913 Louisiana-Mississippi Salt Basins

49 4914 Louisiana-Mississippi Salt Basins

49 4915 Louisiana-Mississippi Salt Basins

49 4916 Louisiana-Mississippi Salt Basins

49 4917 Louisiana-Mississippi Salt Basins
49 4918 Louisiana-Mississippi Salt Basins

49 4919 Louisiana-Mississippi Salt Basins

49 4920 Louisiana-Mississippi Salt Basins

49 4921 Louisiana-Mississippi Salt Basins

49 4922 Louisiana-Mississippi Salt Basins

49 4924 Louisiana-Mississippi Salt Basins

49 4925 Louisiana-Mississippi Salt Basins

49 4926 Louisiana-Mississippi Salt Basins

49 4927 Louisiana-Mississippi Salt Basins

49 4928 Louisiana-Mississippi Salt Basins

49 4929 Louisiana-Mississippi Salt Basins

49 4930 Louisiana-Mississippi Salt Basins

49 4931 Louisiana-Mississippi Salt Basins

49 4932 Louisiana-Mississippi Salt Basins

49 4933 Louisiana-Mississippi Salt Basins

49 4934 Louisiana-Mississippi Salt Basins

49 4935 Louisiana-Mississippi Salt Basins

49 4936 Louisiana-Mississippi Salt Basins

49 4937 Louisiana-Mississippi Salt Basins

49 4938 Louisiana-Mississippi Salt Basins

49 4939 Louisiana-Mississippi Salt Basins

49 4940 Louisiana-Mississippi Salt Basins

49 4941 Louisiana-Mississippi Salt Basins

49 4942 Louisiana-Mississippi Salt Basins

49 4943 Louisiana-Mississippi Salt Basins

49 4944 Louisiana-Mississippi Salt Basins

49 4945 Louisiana-Mississippi Salt Basins

49 4946 Louisiana-Mississippi Salt Basins

49 4947 Louisiana-Mississippi Salt Basins

49 4923 Cotton Valley Blanket Sandstones Gas

50 5001 Florida Peninsula

50 5002 Florida Peninsula

50 5003 Florida Peninsula

50 5004 Florida Peninsula

50 5005 Florida Peninsula

50 5006 Florida Peninsula

51 5101 Superior

52 5201 Iowa Shelf

53 5303 Cambridge Arch - Central Kansas Uplift

53 5304 Cambridge Arch - Central Kansas Uplift

53 5305 Cambridge Arch - Central Kansas Uplift

53 5308 Cambridge Arch - Central Kansas Uplift

53 5309 Cambridge Arch - Central Kansas Uplift

55 5501 Nemaha Uplift

55 5503 Nemaha Uplift

55 5504 Nemaha Uplift

55 5505 Nemaha Uplift

55 5507 Nemaha Uplift

56 5601 Forest City Basin

56 5602 Forest City Basin

56 5603 Forest City Basin

56 5650 Forest City Basin - Central Basin

57 5701 Ozark Uplift

58 5801 Anadarko Basin

58 5802 Anadarko Basin

58 5803 Anadarko Basin

58 5804 Anadarko Basin

58 5805 Anadarko Basin

58 5807 Anadarko Basin

58 5809 Anadarko Basin

58 5810 Anadarko Basin

58 5812 Anadarko Basin

58 5813 Anadarko Basin

58 5814 Anadarko Basin

58 5815 Anadarko Basin

58 5816 Anadarko Basin
58 5817 Anadarko Basin

58 5818 Anadarko Basin

58 5819 Anadarko Basin

58 5820 Anadarko Basin

58 5821 Anadarko Basin

58 5822 Anadarko Basin

58 5823 Anadarko Basin

58 5824 Anadarko Basin

58 5825 Anadarko Basin

58 5827 Anadarko Basin

58 5828 Anadarko Basin

59 5901 Sedgwick Basin

59 5902 Sedgwick Basin

59 5903 Sedgwick Basin

60 6001 Cherokee Platform

60 6003 Cherokee Platform

60 6004 Cherokee Platform

60 6005 Cherokee Platform

60 6007 Cherokee Platform

60 6050 Cherokee Platform - Central Basin

61 6101 Southern Oklahoma

61 6102 Southern Oklahoma

61 6103 Southern Oklahoma

61 6104 Southern Oklahoma

61 6105 Southern Oklahoma

61 6107 Southern Oklahoma

61 6108 Southern Oklahoma

61 6109 Southern Oklahoma

61 6110 Southern Oklahoma

61 6111 Southern Oklahoma

61 6112 Southern Oklahoma

61 6113 Southern Oklahoma

62 6201 Arkoma Basin

62 6202 Arkoma Basin

62 6203 Arkoma Basin

62 6204 Arkoma Basin

62 6205 Arkoma Basin

62 6206 Arkoma Basin

62 6207 Arkoma Basin

62 6208 Arkoma Basin

62 6209 Arkoma Basin

62 6250 Arkoma Basin - Anticline

62 6251 Arkoma Basin - Syncline

63 6301 Michigan Basin

63 6303 Michigan Basin

63 6304 Michigan Basin

63 6306 Michigan Basin

63 6307 Michigan Basin

63 6308 Michigan Basin

63 6309 Michigan Basin

63 6310 Michigan Basin

63 6311 Michigan Basin

63 6312 Michigan Basin

63 6313 Michigan Basin

63 6314 Michigan Basin

63 6315 Michigan Basin

63 6317 Michigan Basin

63 6318 Michigan Basin

63 6319 Antrim Shale Gas, Developed Area

63 6320 Antrim Shale Gas, Undeveloped Area

64 6401 Illinois Basin

64 6402 Illinois Basin

64 6403 Illinois Basin

64 6404 Illinois Basin

64 6405 Illinois Basin

64 6409 Illinois Basin
64 6410 Illinois Basin

64 6412 Illinois Basin

64 6450 Illinois Basin - Central Basin

64 6407 Illinois Basin - New Albany Shale Gas

65 6501 Black Warrior Basin

65 6502 Black Warrior Basin

65 6503 Black Warrior Basin

65 6505 Black Warrior Basin

65 6550 Black Warrior Basin Recharge

65 6551 Black Warrior Basin - Southeastern Basin

65 6552 Black Warrior Basin - Coastal Plain

65 6553 Black Warrior Basin - Central and Western Basin

66 6601 Cincinnati Arch

66 6602 Cincinnati Arch

66 6603 Cincinnati Arch

66 6605 Cincinnati Arch

66 6604 Devonian Black Shale Gas

67 6701 Appalachian Basin

67 6702 Appalachian Basin

67 6703 Appalachian Basin

67 6704 Appalachian Basin

67 6706 Appalachian Basin

67 6708 Appalachian Basin

67 6714 Appalachian Basin

67 6715 Appalachian Basin

67 6716 Appalachian Basin

67 6717 Appalachian Basin

67 6718 Appalachian Basin

67 6719 Appalachian Basin

67 6720 Appalachian Basin

67 6721 Appalachian Basin

67 6725 Appalachian Basin

67 6727 Appalachian Basin

67 6732 Appalachian Basin

67 6737 Appalachian Basin

67 6750 Northern Appalachian Basin - Anticline

67 6751 Northern Appalachian Basin - Syncline

67 6752 Central Appalachian Basin - Central Basin

67 6753 Cahaba Coal Field

67 6728 Clinton/Medina Sandstone Gas High Potential

67 6729 Clinton/Medina Sandstone Gas Medium Potential

67 6730 Clinton/Medina Sandstone Gas Medium-Low Potentia

67 6733 Upper Devonian Sandstone Gas High Potential

67 6734 Upper Devonian Sandstone Gas Medium Potential

67 6735 Upper Devonian Sandstone Gas Medium-Low Potentia

67 6740 Devonian Black Shale - Greater Big Sandy

67 6740 Devonian Black Shale - Greater Big Sandy

67 6741 Devonian Black Shale - Greater Siltstone Content

67 6742 Devonian Black Shale - Lower Thermal Maturity

68 6801 Blue Ridge Thrust Belt

68 6802 Blue Ridge Thrust Belt

69 6901 Piedmont

00 0000

!***************************************************************

!from wltaxes.txt

%******************************************************************

%

% Onshore Lower 48 Oil and Gas Supply Submodule

% Tax Control File

%

% Note: all rates are percents.

%

%******************************************************************

%

%

%*** Federal Income Tax Rate (%)
@

34.5

%*** Royalty Rate (%)

@

12.5

%*** Independent Producer Depletion Rate (%)

@

100.0

%*** Are Intangible Drilling Costs to be Capitalized? (Y/N)

@

N

%*** Are Other Intangibles to be Capitalized? (Y/N)

@

N

%*** Include environmental Costs? (Y/N)

@

N

%*** Are Environmentals to be Capitalized? (Y/N)

@

N

%*** Implement Alternative Minimum Taxes? (Y/N)

@

N

%*** Allow AMT Taxes Paid to be Used as Credits in Future Years? (Y/N)

@

N

%*** Six Month Amortization Rate (%)

@

50.0

%*** Intangible Drilling Cost Preference Deduction (%)

@

100.0

%*** ACE Rate (%)

@

70.0

%*** Maximum Alternative Minimum Tax Reduction for Independents

@

0.0

%*** Alternative Minimum Tax RATE (%)

@

2.0

%C*** Expense EnviroNmental Costs? (Y/N)

@

N

%*** Allow Net Income Limitations? (Y/N)

@

N

%*** Net Income Limitation Limit (%)

@

40.0

%*** Percent Depletion Rate (%)

@

0.0

%*** Percent of Intan. Inv. to Capitalize (%)

@

0.0

%*** EOR Tax Credit(Y?N)

@

Y

%*** EOR Tax Credit Rate (%)

@

15.0

%*** EOR Tax Credit addback (%)

@

100

%*** EOR Tax Credit use by year (upto 10 years)
@

100,0,0,0,0,0,0,0,0,0,0,0,0,0,0

%*** Oil Price at which EOR Tax Credit is Phased Out

@

44.30

%*** Allow G&G Depletable Tax Credit? (Y/N)

@

Y

%*** G&G Depletable Tax Credit Rate (%)

@

10.0

%*** G&G Depletable Tax Credit addback (%)

@

100.0

%*** Allow Tax Credit for Expensed G&G? (Y/N)

@

N

%*** G&G Expensed Tax Credit Rate (%)

@

15.0

%*** G&G Expensed Tax Credit addback (%)

@

100.0

%*** Allow Lease Acq. Depletable Tax Credit? (Y/N)

@

N

%*** Lease Acq. Depletable Tax Credit Rate (%)

@

10.0

%*** Lease Acq. Depletable Tax Credit addback (%)

@

100.0

%*** Allow Tax Credit for Expensed Lease Acq. Costs? (Y/N)

@

N

%*** Tax Credit Rate for Expensed Lease Acq. Costs (%)

@

15.0

%*** Tax Credit for Expensed Lease Acq Cost addback (%)

@

100.0

%*** Allow Tangible Development Tax Credit? (Y/N)

@

N

%*** Tangible Development Tax Credit Rate (%)

@

15.0

%*** Tangible Development Tax Credit addback (%)

@

100.0

%*** Allow Intangible Drilling Cost Tax Credit? (Y/N)

@

N

%*** Intangible Drilling Cost Tax Credit Rate (%)

@

15.0

%*** Intangible Drilling Cost Tax Credit addback (%)

@

100.0

%*** Allow Other Intangible Tax Credit? (Y/N)

@

N

%*** Other Intangible Tax Credit Rate (%)

@

15.0

%*** Other Intangible Tax Credit addback (%)
@

100.0

%*** Allow Environmental Tangible Tax Credit? (Y/N)

@

N

%*** Environmental Tangible Tax Credit Rate (%)

@

20.0

%*** Environmental Tangible Tax Credit addback (%)

@

100.0

%*** Allow Environmental Intangible Tax Credit? (Y/N)

@

N

%*** Environmental Intangible Tax Credit Rate (%)

@

20.0

%*** Environmental Intangible Tax Credit addback (%)

@

100.0

%*** Allow Environmental Operating Cost Tax Credit? (Y/N)

@

N

%*** Environmental Operating Cost Tax Credit Rate (%)

@

20.0

%*** Environmental Operating Cost Tax Credit addback (%)

@

100.0

%*** Allow Tax Credit On Tangible Investments? (Y/N)

@

N

%*** Number of Years for Tax Credit on Tangible Investments

@

20

%*** Allow Tax Credit On Intangible Investments? (Y/N)

@

N

%*** Number of Years for Tax Credit on Intangible Investments

@

15

%

%

%***************************************************************

% Marginal Well Tax Credit Control File

%***************************************************************

%

@

Y !apply marginal well tax credit? (Y/N)

%

% Definition of Marginal Well

% Applied to wells with production less than 15 BOPD, 90 McfD,

% or those wells producing not less than 95% water with

% average production of not more than 25 barrels per day of oil,

% or heavy oil.

%

@

15.00 !daily oil production (Bbl)

90.00 !daily gas production (Mcf)

%

@

25.00 !oil production (Bbl/D)

95.00 !minimum water production percentage (%)

%

@

20.0 !API degree cutoff for heavy oil.
%

% Tax credit

%

@

3.00 !$/Bbl of applicable oil production

0.50 !$/Mcf of applicable gas production

%

% Applicable production

%

@

3.00 !Daily oil production (Bbl) to which credit is applied

18.00 !Daily gas production (Mcf) to which credit is applied

%

% Phase in/phase out prices

@

17.10 20.52 !oil price ($/Bbl) converted from (15.00 - 18.00) 2004 - 2008 dollars

1.90 2.28 !gas price ($/Mcf) converted from ( 1.67 - 2.00) 2004 - 2008 dollars

%

%

%

%**********************************************************************

%

% Hydraulic Fracturing (for Oil) Parameters

%

%**********************************************************************

%

% 1. Controls

%

@

N !Apply Hydraulic Fracturing

%

@

100.0 !Percentage of oil wells being fractured

%

% 2. Parameters for estimation of fracture length

%

@

50.0 !permeability cutoff for high permeability parameters (md)

%

% Low Permeability High Permeability

@

0.00823 0.0833 !fracture width (ft)

10.00 2.00 !fracture conductivity

1000000.00 1000000.00 !fracture permeability (md)

9999.00 50.00 !maximum fracture length (ft)

%

%

% 3. Cost equation parameters

%

% cost = fracture cost * fracture half length * 2.0

%

% fracture cost (K$) = a*depth^3+b*depth^2+c*depth+d

%

% min depth max depth a b c d

@

0.00 4999.99 0.000 0.000 0.0011 0.000

5000.00 99999.99 1.375E-10 -2.8179E-6 0.01988 -40.886

%

%

% 4. Technology Levers

%

% base case advanced case

@

1.00 1.00 ! H-1 Change in fracture cost (fraction)

0.00 0.00 ! H-2 Cost to apply fracture cost technology H-1 
(K$/fracture)

1.00 1.00 ! H-3 Change in fracture length (fraction)

0.00 0.00 ! H-4 Cost to apply fracture length technology H-3 (K$/ft 

frac)

%

% 5. Screening Criteria

%

@

100.0 !maximum applicable permeability

70.0 !maximum applicable API gravity

10000.0 !maximum applicable depth

%

% 6. Regional Controls

%

@

Y !hydraulic fracture permitted in Region 1: East Coast

Y !hydraulic fracture permitted in Region 2: Gulf Coast

Y !hydraulic fracture permitted in Region 3: Midcontinent

Y !hydraulic fracture permitted in Region 4: Southwest

Y !hydraulic fracture permitted in Region 5: Rocky Mountain

Y !hydraulic fracture permitted in Region 6: West Coast

Y !hydraulic fracture permitted in Region 7: Northern Great Plains

%

%

@

Y !Apply hydraulic fracturing to new drilling in mature oil fields

Y !Apply hydraulic fracturing to new drilling in undiscovered oil fields

%

%

!*****************************************************************************

!from wldepreciation.txt

%*****************************************************************************

% Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) Depreciation File

%

% Sections:

% 1. Default Depreciation and Amortization Schedules

% 2. Process Specific Depreciation Schedules

%

%*****************************************************************************

%

%

% Section 1: Default Depreciation and Amortization Schedules

%

% Note: these schedules are applied to all processes not specified in

% sections 2 and 3.

%

% Number of years in default depreciation schedule

@

8

% Annual Fraction Depreciated

@

0.14285714

0.24489796

0.17492711

0.12494794

0.08924853

0.08924853

0.08924853

0.04462426

%

% Number of years in default amortization schedule

@

6

% Annual Fraction Amortized

@

0.2

0.2
0.2

0.2

0.2

0.0

%

%*****************************************************************************

%

% Section 2: Process Specific Depreciation Schedules

%

% Override structure

% line 1: process number ! process name

% line 2: number of years in schedule to be applied (depryr)

% line 3: annual fraction to be depreciated for year 1

% line 3+depryr-1: annual fraction to be depreciated for year depryr

% line 3+depryr : Separation line between override schedules

%

% Number of processes with override depreciation schedules

@

0

% !!!OVERRIDE SCHEDULES BEGIN ON FOLLOWING LINE!!!

@

03 ! CO2 Flooding

7

0.10

0.20

0.20

0.20

0.20

0.20

0.10

%

@

04 ! Steam Flooding

4

0.3333

0.4445

0.1481

0.0741

%

@

02 ! Waterflooding

7

0.10

0.30

0.20

0.10

0.10

0.10

0.10

%