PROTECTION
AGENCY
OALl--.
906R87106
CHAPTER 6
ECONOMIC IMPACT OF ALTERNATIVE WASTE MANAGEMENT PRACTICES
FOR THE ONSHORE OIL AND GAS INDUSTRY
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TABLE OP CONTENTS
Page
1. Introduction and Background 1-1
2. Economic Model Description 2-1
2.1 Economic Model Overview 2-1
«
2.2 Parameter Description 2-3
2.3 Model Calculational Procedures 2-4
2.4 Interpretation of Model Results 2-6
3. Base Case Analysis 3-1
3.1 Overview 3-1
3.2 Description of Regional Projects 3-1
3.3 Results of Base case Simulations 3-12
3.4 Stripper Wells 3-15
Appendix A Selection of Model Projects
Appendix B Timing of Exploration and Development
Phases
Appendix C Phase One Assumptions - Lease Costs
Appendix D Phase Two Assumptions - Exploration Costs
Appendix E Phase Three Assumptions - Development costs
Appendix F Phase Four Assumptions - Production
Parameters
Appendix G Base Case Financial Assumptions and
Rates
Appendix H ERG Economic Model for Onshore Petroleum
Production
V*
Appendix I Oil and Gas Project Baseline Cases
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LIST OF TABLES
Page
3-1 Model Project Configurations 3-3
3-2 Parameter Values for Baseline Projects 3-4
3-3 Regional Drilling Costs Per Well 3-6
3-4 .Regional Well Discovery Efficiencies 3-7
3-5 Daily Initial Production Rates 3-10
3-6 Field Production Rates Five Highest Rates 3-11
Per Region
3-7 Comparison of Drilling Costs and Wellhead Prices 3-13
3-8 Internal Rate of Return for Baseline Projects 3-14
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LIST OF FIGURES
2-1 General schematic diagram of ERG economic model 2-2
3-1 Geographic Regions 3-2
0298V
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1. Introduction and Background
The U.S. Environmental Protection Agency is currently
preparing a Report to Congress concerning the wastes generated
during oil and gas exploration, development, and production as
mandated under Section 8002(m) of the Resource Conservation and
Recovery Act (RCRA). The Report to Congress must address,
among other issues, the impact of alternative waste management
practices on exploration, development, and production in this
industry. This draft report, which provides an economic
description of oil and gas projects throughout the United
States, is a part of the impact assessment. Portions of this
report will be incorporated into the Report to Congress and
supporting technical materials.
The primary wastes of concern are muds and cuttings
disposed of during drilling operations (i.e., drilling wastes)
and water separated from the hydrocarbons in production
operations (i.e., produced waters). Drilling wastes are
currently disposed of in unlined pits located at the drill
site. Produced waters typically are conveyed by pipeline or
truck to a class II disposal well for injection. The cost of
these disposal methods are part of the current (i.e.,
"baseline") cost of exploring for and producing oil and gas.
If additional regulatory requirements concerning waste
disposal are promulgated for this industry, the cost of waste
disposal could rise. The purpose of this report is to
establish baseline economic cases that can be used to simulate
the economic performance of representative projects both with
and without the cost of additional waste management practices.
The change in economic performance, so measured, will provide
an estimate of the effect of federal regulations on industry
*•
exploration, development, and production.
1-1
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Section Two of this report describes the model that has
been constructed to simulate the economic performance of
onshore drilling and production projects. Regional projects
are designated to reflect cost and productivity differences
throughout the country. Two economic classes of companies,
majors and independents, are considered to reflect differences
in tax considerations. This results in a total of 21
representative projects for baseline analysis. Each of the 21
cases can be used to assess the economic performance of either
a new project or a stripper well operation at any phase of the
well's production life. Thus, the baseline models depicted
herein can be used to simulate far more than 21 cases.
The economic model has been tested and operated to simulate
the economic performance of the 21 basic model cases. These
results are described in Section Three. In Section Four of the
final report, not provided here, the additional cost of waste
management requirements under two hypothetical "Waste
Management Scenarios" will be estimated. In Section Five,
profitability of new projects will be compared between the base
case and the waste management scenarios. In Section Six, a
similar comparison will be made for stripper well economics.
This report also contains nine appendices which provide
details of all of the data sets and calculations described in
summary fashion in the report text. Appendices A through H
describe all of the input data and algorithm logic of the
baseline economic cases. In Appendix I, the model project
simulations are reproduced in their entirety.
0292y
1-2
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2. Economic Model Description
To estimate the effects of the regulatory options, the
economic performance of model projects are simulated before and
after new disposal requirements. This section reviews the
economic model and its components.
2.1 Economic Model Overview
The economic model simulates the performance and measures
the profitability of a petroleum production project. For the
purposes of this report, a project is defined as a single
well. For each project, economic data representing typical
costs for leasing, exploration, production, and operating are
entered, as well as typical production rates, oil and gas
selling prices, and other pertinent data. The model calculates
the annual after-tax cash flow for each year of operation, as
well as cumulative (i.e., lifetime) measures of a project's
performance such as net present value (NPV) and internal rate
of return (IRR).
The schematic design of the model is summarized in Figure
2-1. Two sets of exogenous values — project specific and
general-model variables — are entered into the model. The
model provides the integrative calculation procedures and
algorithms which duplicate (1) the oil industry's standard
accounting procedures, (2) federal taxation rules after the Tax
Reform Act of 1986, and (3) standard financial rate-of-return
calculation methods. The outputs of the economic model are a
series of yearly project cash flows and cumulative performance
measures.
«-
The regulatory options are incorporated into the economic
model by adding relevant capital costs and operating expenses
2-1
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INPUTS
Project Specific inputs
• Location
• cost characteristics
«
• Production profile
General Exogenous inputs
• Discount rate
• Price of oil and gas
• Tax and accounting
practices for oil and gas
companies
ERG Model Algorithms for:
• Production logic
• Cost logic
• Pollution control cost logic
• Sequencing logic
• Price revenue and earnings calculation
• Financial analysis
• Summary calculations
ODTPUTS
• Cumulative project internal rate of return
• Yearly project financial results
• Cumulative project financial results
• Cumulative present value of project results
Figure 2-1. General schematic diagram of ERG economic model
2-2
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to the set of cost data. The model calculates all yearly and
cumulative outputs for both the base case and regulated cases
for each project.
2.2 Parameter Description
t
A distinct set of parameter values are required for each of
the model projects and constitute a complete economic
description of each project. The following categories of
parameters are incorporated into each project:
1. Lease Cost - Bonus payments to Federal or state
governments or to private individuals for the land.
2. Geological and Geophysical Cost - Cost of analytic
work prior to drilling.
3. Drilling Cost per Well.
4. Cost of Production Equipment.
5. Discovery Efficiency - The number of wells drilled for
one successful well.
6. Production Rates - initial production rates of oil and
gas and production decline rates.
7. Operation and Maintenance costs.
8. Tax Rates - Rates for: Federal and state income
taxes, severance taxes, royalty payments,
depreciation, and depletion.
9. Price - Wellhead selling price of oil and gas (also
called the "first purchase price" of the product).
10. Cost of capital - Real rate of return for the industry.
11. Timing - Length of time required for each project
phase (i.e. leasing, exploration, development, and
production).
*•
The parameter values used in the analysis are summarized in
Section 3 and described more fully in Appendices A through H.
2-3
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2.3 Model calculational Procedures
The model's calculational procedures are a set of rules and
logic used to convert the project parameters into measures of a
project's financial performance. These procedures fall into
several categories:
«
Sequencing Logic - The economic model includes a scheduling
sequence for each phase of a project life: leasing,
exploration, development, and production. For the lower 48
states, production begins in the first year (i.e. one year
after the lease sale). Due to constraints posed by Alaska's
unique environment, production begins in the tenth year for
this region.
Production Logic - The model equations use exogenous values
for peak production rates and production decline rates to
define a production profile for the well. Summary measures of
production for the entire project lifetime are also calculated.
Cost Logic - The model equations use exogenous cost data to
define yearly capital and operating costs of each project.
Exogenous parameters include capital cost (e.g. leasehold
costs, geological and geophysical costs, drilling cost, and
production equipment cost) and operating costs. Using the
model sequencing logic, the exogenous cost information is
converted to annual capital and operating cost streams.
Summary measures of all capital and operating costs (both
before and after taxes) are calculated for the entire project
lifetime.
Pollution control Cost Logic - A set of equations
incorporates the capital and operating costs of additional
waste management practices into the project cost stream, thus
creating a simulation of the economic effect of different solid
2-4
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waste regulations. A separate summary of pollution control
costs for the entire project lifetime is also calculated.
Cost Accounting Practices - Specialized oil industry
accounting procedures are applied to project cost streams.
Capital and operating costs are treated in accordance with oil
industry accounting practices. The model calculates the
expensed and capitalized portions of each capital expenditure.
The capitalized portion of each capital expenditure is then
used as a base to estimate depreciation amounts for each year
of the project's life. Majors expense 70% of intangible
drilling costs while independents expense 100% of these costs.
Depletion allowances are also credited to the project.
Depletion allowances are calculated on a cost basis for majors
and on a percentage basis for independents.
Price and Revenue calculations - The wellhead price (also
known as a "first purchase price") of oil and gas are exogenous
parameters for the model. These vary by region, see Section
3. The prices are multiplied by the annual production volumes
to calculate annual project revenues. Revenues are calculated
both as an annual stream and as a total for project lifetime.
Earnings and cash Flow Analysis - The model calculates a
project's annual earnings, which are the difference between a
project's revenues and its costs. Tax and royalty payments are
subtracted from before-tax earnings to calculate annual cash
flow. Depreciation, and depletion are treated in these
calculations according to Federal laws. For the sake of
simplicity, all severance taxes are calculated on the basis of
gross income. This is the most common situation although some
states calculate severance taxes on a net income basis (i.e.
gross revenues minus royalty payments) while others use a
fee-per-unit-production basis (e.g. $0.075 per Mcf).
2-5
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Financial Performance Calculations - A variety of summary
financial measures are calculated in the model. Annual project
cash flows are discounted to the present using an 8 per cent
discount rate to calculate to net pr.esent value (NPV) of the
project. The internal rate of return (i.e. the discount rate
at which the present value of the project is zero) is also
calculated. The present value of all project costs is divided
by th*e present value of all petroleum production to calculate
the average cost per unit of production.
2.4 Interpretation of Model Results
Based on the economic model logic described above, a number
of summary statistics and performance measures are calculated
for each project/ including:
1. Internal rate of return (IRR)
2. Corporate cost per unit of production
3. Net present value (NPV)
4. Present value of all project costs
5. Present value of all project revenues
6. Present value of additional pollution control costs
7. Annual costs of additional pollution control
The analysis of the economic status of the base cases,
presented in Section 3, focuses on the internal rate of return
(IRR) as a performance measure.
The internal rate of return of a project is a measure of
its profitability, if the IRR of a project is greater than the
corporate-ion's actual cost of capital, the project is
profitable. In this analysis, the real cost of capital is
2-6
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valued at 8 percent. Thus, projects with a real IRR higher
than 8 percent are considered profitable.
In interpreting the IRR from the model simulations, several
factors must be considered. First, the input data are of
varying quality. There is an annual report on nationwide
drilling costs and the data can be adjusted to separate onshore
and offshore drilling costs. In contrast, initial well
production and production decline rates are not readily
available. This report makes use of actual field data and
recent modeling efforts in well productivity in order to obtain
reasonable estimates for production rates and production
decline. Second, the use of regional models implies an
aggregation of data and a concommitant loss of fine detail.
There will certainly be wells that are more or less profitable
than those in our analysis. What we are striving for is a set
of projects that reasonably spans the diverse conditions within
the industry and to evaluate to economic impacts of new waste
management upon each of those projects.
0294V
2-7
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3. Base Case Analysis
3.1 Overview
The United States is divided into 11 geographic regions for
consideration in this analysis (see Figure 3-1). Region 1 (New
England) and Region 3 (Georgia and the Carolinas) have minimal
oil and gas production and so they are not considered further.
Each of the remaining regions has a set of projects for oil
production; eight regions (i.e., all regions except California)
typically are assumed to produce oil with casinghead gas.
California does produce some casinghead gas, but a substantial
proportion of it is used for repressurization. Region 10,
therefore, has an oil-only set of projects. Three states in
two regions produce 75 percent of the nation's natural gas
(Texas 35 percent, Louisiana 29 percent and Oklahoma
11 percent). A set of gas-on
Regions 4 and 7 on this basis.
11 percent). A set of gas-only models are developed for
This results in 11 regional projects. There are assumed to
be two economic classes of companies in this study, majors and
independents. The classes are diffentiated by tax
considerations (e.g. cost versus percentage basis for depletion
and the percent of intangibles expensed). Given the economic
requirements for oil and gas production in Alaska, only majors
are assumed for Region 11. This results in 11 regional
projects for majors and 10 regional projects for independents
for a total of 21 baseline projects (see Table 3-1).
3.2 Description of Regional Projects
The,.parameter values for each of the regional projects are
presented in Table 3-2. All values are in 1985 dollars and are
based on data for 1985 unless otherwise noted.
3-1
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3-2
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TABLE 3-1
MODEL PROJECT CONFIGURATIONS
.
REGION STATE
2 NY, PA, KY,
VA, WV, TN
4 AL, AR,
LA, MS
5 IL, IN, 10,
OH, MI, MN, MO
6 ND, SD,
NB, KS
7 TX,
OK
8 ID, MT,
WY
9 AZ, CO, NV,
NM, UT
10 CA
11 AK
PRODUCTION
TYPE
Oil
Oil
Oil
Oil
Gas
Gas
Oil
Oil
Oil
Oil
Oil
Oil
Gas
Gas
Oil
Oil
Oil
Oil
Oil
Oil
Oil
OPERATOR
CATEGORY
Major
Independent
Major
independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
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Production in the lower 48 states begins in Year 1 of the
project while it is delayed until Year 10 for Alaska (Region
11). The lease bonus payments range from a low of $1,146 in
Appalachia (Region 2) to a high of $161,056 per drillable unit
in Alaska. ' Geological and geophysical expenses cost
58.3 percent of the leasing costs in the lower 48 states but
only,12.6 percent of leasing costs for Alaska.
Well costs are derived based on the number of wells,
footage drilled, and costs for the states in each region.
Offshore and onshore components were separated for Alabama,
Alaska, California, Louisiana, and Texas data and only onshore
drilling costs were considered for this analysis. For the
lower 48 states, dry wells were assumed to cost no more than
completed wells. For Alaska (Region 11), dry onshore wells
have a substantially higher cost than completed oil wells. For
this region, a composite cost was generated by summing the cost
of one productive well and 14 percent of a dry well, in
1983-1985, an average of 1.14 wells were drilled in Alaska to
obtain one productive well (see following paragraph). Table
3-3 summarizes the average regional costs per well and average
well depth.
The discovery efficiency is the ratio of productive wells
to all wells drilled in the region (i.e. the value includes new
field wildcats, exploratory, and development wells). The ratio
is based on completion data for 1983-1985. This ratio
ranges from a low of 59 percent in Region 6 (Kansas, Nebraska
and the Dakotas) to a high of 90 percent in a heavily explored
area such as California (Region 10, see Table 3-4).
Production equipment costs for Regions 4,6,7,8,and 9 were
derived*- from the information in the Energy information
Q
Administration report on this topic. A regression model was
fit with cost being a function of depth for oil production
equipment costs. The following model was fit:
3-5
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TABLE 3-4
REGIONAL WELL DISCOVERY EFFICIENCIES
v
ALL WELLS DRILLED 1983
REGION
2
4
5
6
7
8
9
10
11
Source:
OIL
6,919
7,958
13,046
9,470
52,986
2,826
4,592
7,839
449
GAS DRY
7,870 3,598
3,820 8,308
3,137 6,316
1,238 9,985
14,032 27,497
614 2,716
3,016 2,914
329 912
4 64
- 1985
TOTAL
18,387
20,086
22,499
20,693
94,515
6,201
10,522
9,080
517
Based on completion date data for
1985: The Complete Annual Review
Activity
in the United
NUMBER
OF WELLS
PER
SUCCESS-
FUL WELL
1.24
1.71
1.39
1.93
1.41
1.80
1.38
1.11
1.14
1983 - 1985
of Oil and
DISCOVERY
EFFICIENCY
0.80
0.59
0.72
0.52
0.71
0.55
0.72
0.90
0.88
Resume
Gas
States, Petroleum Information
Corporation, 1986
0185V
3-7
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Cost = a * depth5
where a = 482.99 and b = 0.62. Average well depths for each
region are given in Table 3-3. The'average well depth for
California is 1845 ft, that is, it is outside the range of
depths sampled. For California, production equipment costs
were set to the values presented in Reference 8 for a 2,000 ft.
«
well in California. For Regions 2 and 5, production equipment
costs were assumed to be the difference between total well
9
costs presented in a recent industry report on that region
and well costs presented Table 3-3. For Alaska, production
2 10
equipment costs are taken from young and Hauser, 1986 '
Production costs for gas operations were modeled as a function
of depth and production. The following equation was used:
b c
Cost = a * depth * production
with a = 311.06, b = 0.41, and c = 0.18.
A parallel set of efforts are used to obtain estimates of
the annual operation and maintainance (O&M) costs for each
region. For oil operations, the model parameters are a =
407.48 and b = 0.43. For gas operations, the fitted model
parameters are a = 129.02, b = 0.46 and c = 0.14. O&M costs
q
for Regions 2 and 5 were taken from the Applachian report ,
g
costs for California are those for a 2,000 ft. well , those
2 10
for Alaska are taken from young and Hauser, 1986 '
Initial production rates and production decline rates were
the parameters for which it was most difficult to obtain data.
Three steps were taken to generate reasonable estimates of
initial well production rates: (1) regional average production
rates in 1985 were calculated from the number of producing
wells and production figures ' ; (2) lower, mid-range, and
upper estimates for intitial production were calculated on the
3-8
-------
assumption that average production figures were representative
of wells half-way through their productive life; and (3) the
estimates were compared against samples of first-year
production figures for actual wells'to verify their
reasonableness.
Table 3-5 summarizes the initial production rates used in
this analysis. The use of regional averages implies a loss of
information about the extremes in well productivity. There are
wells that are produced, not because they are profitable, but
to recover a portion of sunk costs. On the other hand,
regional averages mask very large producers as well, such as
some gas wells in southern Louisiana with production of 1125
Mcf/day/well12.
The production decline rates are derived from ratios of
1985 production to estimated remaining reserves for over 100
fields published in Oil and Gas Journal. Table 3-6
presents the five fields with the highest decline rates for
each region in the sample. The decline rate for a field cannot
exceed that of the average well in that field, in contrast,
however, a low field decline rate may be the result of a small
number of wells in a large field. Note that actual field
decline rates frequently exceed the 10 percent-15 percent
14
rule-of-thumb proposed in textbooks on oil production. For
Appalachia, (Region 2) we rely on industry data collected in
q
January 1987 for production decline rates.
With respect to taxation, it is assumed that the projects
are incremental to the other activities of the company, and
therefore, the net taxable income is marginally taxed at the
U.S. corporate rate of 34 percent. This assumption implies
that the company has at least $100,000 of other net income
without this project. State taxes and severance taxes are
chosen from one of the states in each region. The severance
3-9
-------
TABLE 3-5
DAILY INITIAL PRODUCTION RATES
THEORETICAL RANGE IN
INITIAL PRODUCTIONb
REGION
2
4
4
5
6
7
7
8
9
10
11
PRODUCT
.Oil
Casing
Oil
Casing
Gas
Oil
Casing
Oil
Casing
Oil
Casing
Gas
Oil
Casing
Oil
Casing
Oil
Casing
Oil
Casing
AVERAGE
PRODUCTION3
0.7
3.9
39.9
54.6
647.6
3.0
4.0
6.4
8.6
9.2
17.3
259.4
26.7
35.9
16.0
34.5
23.3
13.8
1868.3
343.2
LOWER
1
6
60
82
971
4
6
10
13
14
26
389
40
54
24
52
35
21
2802
515
MID-RANGE
1
8
80
109
1,295
6
8
13
17
18
35
519
53
72
32
69
47
28
3,737
686
UPPER
3
16
160
218
2,590
12
16
26
34
37
69
1,038
107
143
64
138
93
55
7,473
1,373
RANGE IN INITIAL
PRODUCTION SEEN
IN FIELD DATAC
LOWER
3
22
20
95
0
2
4
3
44
218
239
6
1
6
16
5
94
4,000
UPPER
21
60
233
2,731
13
38
211
30
2,658
777
23
37
105
343
DATA
USED IN
ANALYSIS
3
16
36
68
971
12
16
26
34
37
69
1,038
53
72 -
32
69
35
0
3,700
686
Note: Production figures are in units of bbl/day or Mcf/day.
aSee Tables F-5 and F-6.
bBased on information in Lohec, Ron E., "Analytical Approach Evaluates Frontal
Displacement Mechanism I and II," Oil and Gas Journal, September 17, 1984, 83-89 and
September 24, 1984, 92-97.
cField data provided by various sources. Region 2: "An Analysis of the Economic
of New Hazardous Waste Regulations on the Appalachian Basin Oil and Gas Industry",
Robinson and McElwee, Charleston, WV, February 1987. Region 4: Jackie Hodges,
Department of Natural Resources, Baton Rouge, LA. Region 5: Graham Robb, Oxford Oil
Co., Ohio. Regions 6-10: Petroleum Information Corporation, Denver and Houston
offices. Region 11: U.S. Arctic Oil and Gas, National Petroleum Council, 1981.
0186V
3-10
-------
TABLE 3-6
FIELD PRODUCTION RATES
FIVE HIGHEST RATES PER REGION
REGION
4
5
6
7
8
9
10
11
Source:
PRODUCTION
STATE (10001
MS
LA
LA
MS
LA
IL
IL
IL
IL
IL
KA
KA
KA
KA
KA
TX
TX
TX
TX
TX
WY
WY
WY -
WY
WY
NM
NM
NM
NM
CO
CA
CA
CA
CA
CA
AK
AK
AK
AK
AK
"U.S
Oil
4,424
468
1,176
1,202
456
926
2,075
2,770
2,700
3,400
1,351
1,496
1,359
1,329
1,508
21,396
2,412
18,912
24,300
33,324
3,650
5,662
2,655
2,635
3,042
2,023
800
6,651
13,081
12,507
216
1,016
236
1,227
2,346
568,212
3,012
2,172
7,548
3,060
1985
EST. REM.
RESERVES
s of bbls)
15,576
1,615
4,000
4,000
1,475
1,800
4,000
4,901
4,200
5,100
6,500
6,400
5,800
5,600
6,000
60,000
6,588
50,000
60,000
56,676
18,000
20,000
8,488
8,000
8,000
10,792
3,263
25,000
46,000
30,000
983
3,632
835
3,700
6,220
5,101,761
19,890
13,750
47,133
11,705
. Fields with Reserves Exceeding 100 Mi
and Gas Journal,
January 27, 1986, pp.
FIELD
PRODUCTION
DECLINE
RATE
22.1%
22.5%
22.7%
23.1%
23.6%
34.0%
34.2%
36.1%
39.1%
40.0%
17.2%
18.9%
19.0%
19.2% ~
20.1%
26. 3%
26.8%
27.4%
28.8%
37.0%
16.9%
22.1%
23.8%
24.8%
27.5%
15.8%
19.7%
21.0%
22.1%
29.4%
18.0%
21.9%
22.0%
24.9%
27.4%
10.0%
13.2%
13.6%
13.8%
20.7%
llion Bbl,"
104-105.
0187V
3-11
-------
tax structure for Alaska (Region 11) consists of nominal rates
with are then adjusted by a formula called the Economic Limit
Factor (ELF).
Wellhead prices are annual prices for 1985 and are
aggregated by region. ' Although these prices have
continued to plummet in 1986, there is insufficient 1986
information available to adjust all other costs to the more
recent year. A comparison of wellhead prices and drilling
costs suggests that as wellhead prices decline, drillng costs
decline, see Table 3-7.
3.3 Results of Base Case Simulations
Table 3-8 summarizes the financial performance of each
project as measured by the internal rate of return (IRR). The
real cost of capital in this study is 8 percent. In all
regions, independents show a higher internal rate of return
than major integrated companies due to the different methods of
taking depletion allowances and expensing all intangible
drilling costs.
As mentioned in Section Two, care should be taken in
interpreting the IRR values calculated by the model. The model
outputs are based on the input parameter values which are only
point estimates in a universe in which there is a great deal of
variation. Table 3-8 provides only a baseline upon which to
evaluate the impacts of additional waste, management control
costs on individual projects. For example, because oil
operations show an IRR of 8.4 percent for majors in Alaska, it
cannot be concluded that all oil operations are barely
profitable in that state. Rather, these estimates show that,
based on a series of typical economic values, a typical oil
project in Alaska would be close to a cutoff level of marginal
profitability.
3-12
-------
TABLE 3-7
COMPARISON OF DRILLING COSTS AND
YEAR
*
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
aBasic Pet
1986. Section
Drilling Costs
bBasic Pet
1986. Section
WELLHEAD PRICES (CURRENT DOLLARS)
>
DRILLING COSTS
($ PER FT)a
34.29
39.29
47.91
57.18
66.86
83.11
95.60
69.85
60.01
59.20
roleum Data Book, Vol. VI, No. 3,
WELLHEAD PRICES
($ PER BBL)b
8.14
8.57
8.96
12.51
21.59
31.77
28.52
26.19
25.88
24.09
September
III, Table 9a; 1985 Joint Association Survey on
, December 1986, Table 1.
roleum Data Book, Vol. VI, No. 3,
VI, Table 1; Petroleum Marketing
September
Annual 1985,
U.S. Department of Energy. Energy Information Information,
DOE/EIA-0487(85)/1, Vol. 1, December 1986, Table 7.
0189V
3-13
-------
TABLE 3-8
INTERNAL RATE OF RETURN FOR BASELINE PROJECTS
%
, REGION
2
4
4
5
6
7
7
8
9
10
11
PRODUCTION
Oil
Oil
Gas
Oil
Oil
Oil
Gas
Oil
Oil
Oil
Oil
INTERNAL
MAJORS
10.3%
14.8%
12.9%
9.2%
15.5%
14.7%
11.0%
13.1%
11.5%
20.4%
8.4%
RATE OF RETURN
INDEPENDENTS
10.5%
15.4%
13.3%
9.7%
16.0%
15.6%
11.6%
13.5%
11.9%
21.3%
Source: ERG estimates,
0188V
3-14
-------
The computer simulations which operated the internal rates
of return reported in Table 3-8 are reproduced in Appendix I.
Additional simulations may be performed in the course of the
impacts assessment to address operations that may experience
large economic effects under the waste management scenario.
These simulations will use the same basic economic modeling
structure/ but with some of the data inputs altered to depict
high-impact situations.
3.4 Stripper Wells
The model project simulation results presented in Section
3.3 depicted new oil and gas projects from leasing through
drilling and production. Existing producing wells, however,
could also be affected by changes in waste management
requirements. Specifically, more stringent requirements
regarding produced water disposal could affect the operating
costs and profitability of these operations. The impact could
be greatest with respect to stripper wells which, because of
their low production, are extremely sensitive to changes in
operating costs.
In the impact assessment, the same economic model that is
used to depict new wells can be used to depict stripper
operations. This can be seen by referring to any of the
computer printouts in Appendix I. As the printouts show, the
economic models are operated to simulate each year of a well's
performance. In the latter year of a well's life, it may be
operating as a stripper. Thus truncating any of the model runs
to include only the final years of operation, any of the 21
models can be used to simulate stripper well performance.
«•*
In a recent study, Standard Oil Company simulated the
performance of stripper well operations in Texas to estimate
3-15
-------
the impact of waste management costs. The same revenue and
cost elements included in the Standard Oil model are included
in the economic model presented here (e.g., oil and gas
revenues, operating costs, mineral owner royalties, and state
severance taxes). Thus, this economic model can be used to
test or replicate the analysis performed by Standard Oil under
alternative assumptions. The use of the model to simulate
stripper operations will be considered further in the impact
assessment.
0295^
3-16
-------
NOTES FOR SECTION THREE
1. Natural Gas Annual 1985, U. S. Department of Energy,
Energy information Administration, DOE/EIA-013K85),
November 1986, Tables 2 and 4.
2. Young, J. S. and Hauser, W. S., "Economics of Oil and Gas
Production from ANWR for the Determination of Minimum
^Economic Field Size," Bureau of Land Management, Alaska
State Office, Division of Mineral Resources, unpublished
report, 1986; "Draft Artie National Wildlife Refuge,
Alaska, Coastal Plain Resource Assessment", U. S. Bureau
of Land Management, November 1986.
3. U. S. Lease Price Report, vol. 5 no. 10 October/November
1986, Lierle Newsletters, Inc., Aurora, CO.
4. Five-Year Oil and Gas Leasing Program, Alaska Department
of Natural Resources, Division of Oil and Gas, January
1986.
5. 1984 Survey on Oil and Gas Expenditures, American
Petroleum Institute, Washington D. C., October 1986.
6. 1985 Joint Association Survey on Drilling Costs, American
Petroleum Institute, Washington D. C., December 1986.
7. Resume 1985; The Complete Annual Review of oil and Gas
Activity in the United States, Petroleum information
Corporation, Denver, CO., 1986.
8. costs and Indices for Domestic Oil and Gas Field Equipment
and Production Operations, 1985, U. S. Department of
Energy, Energy information Administration,
DOE/EIA-0185(85), April 1986.
9. An Analysis of the Economic impact of New Hazardous Waste
Regulations on the Appalachian Basin Oil and Gas Industry,
Robinson & McElwee, Charleston, WV., February 1987.
10. U. S. Arctic Oil and Gas, National Petroleum Council, 1981
11. Basic Petroleum Data Book, vol. VI no. 3, September 1986,
Section III Table 18b, Section IV Table 4b.
12. Monthly Activity Report for August 1986, supplied by
Jackie Hodges, Louisiana Department of Natural Resources,
Baton Rouge, LA.
13. "U. S. Fields with Reserves Exceeding 100 Million Bbls,"
Oil and Gas Journal, January 27, 1986, 104-105.
3-17
-------
14. North, F. K., petroleum Geology/ Allen & Unwin, Boston,
1985, 479.
15. State Tax Handbook: as of October 1, 1986/ Commerce
Clearing House, Chicago, 1986. ,
16. Petroleum Marketing Annual 1985, U. S. Department of
Energy, Energy Information Administration,
DOE/EIA-047(85)/l,vol. 1, December 1986.
0295V
3-18
-------
APPENDIX A
SELECTION OF MODEL PROJECTS
In order to assess the effects of effluent guidelines, ERG
developed an economic model to simulate the performance of
typical onshore petroleum production projects. This appendix
reviews the logic used in developing a set of model projects to
analyze, considerations include the choice of modeling
projects on a per-well or per-field basis, regional variations,
and the economic category of the company. Each area is
discussed in turn.
A.I Per-Well or Per-Field Basis
The model is capable of handling projects on a single well
or multiple well basis. For the onshore study, a single well
basis is used for two reasons. First, the decision to drill is
made on a well-by-well basis in the industry. Second, it is
unlikely that only one company would be the sole developer of a
large, multiple well field.
A.2 Regional Versus National Models
A single factor that characterizes onshore petroleum
production is diversity. Project timing can range from 1 year
in the lower 48 states to a decade for Alaska. Drilling costs
depend on depth and local labor costs. The expected depth of a
petroleum reservoir is a site-specific parameter, although some
similarities within a given region do exist. Some reservoirs
cover large expanses of territory, such as in Appalachia, while
others form small pockets around salt domes or geologic traps.
A-l
-------
The initial production rates and production decline rates vary
according to reservior porosity, permeability, viscosity, and
hydraulic head; all these factors can vary from site to site
and even within a given field. For'example, wells in
Appalachia tend to have low production rates but long periods
of production. In contrast, wells in Texas may produce
voluminously in the first year, but need lifting equipment
thereafter.
In view of this diversity, it was decided to develop
projects on a regional basis. For this report, the United
States is divided into eleven geographic regions (see Figure
A-l). Region 1 (New England) and Region 3 (Georgia and the
Carolinas) have minimal oil and gas production so they are not
considered further.
A.3 Type of Production
Three states produce 75% of the nation's natural gas (Texas
35%, Louisiana 29%, and Oklahoma 11%). On this basis, a set
of gas-only projects is developed for Regions 4 and 7.
California produces some casinghead gas but a substantial
proportion of it is used for repressurization. Region 10,
therefore, has a set of oil-only projects. The remaining eight
regions are assumed to produce oil with casinghead gas.
A.4 Level of Production
The intial daily production for each project is discussed
in Section E.3. In this appendix it is sufficient to note that
the range in production level ranges from wells that begin as
strippers in Appalachia (Region 2) to the very large producers
(3700 bbl/day/well) in Alaska (Region 11).
A-2
-------
A-3
-------
A.5 Economic Category of Producer
Two economic categories of producers are considered in this
analysis. First are the "majors". These companies are
characterized by a high degree of vertical integration, i.e.
their activities encompass both "upstream" and "downstream"
actiyities. The former refers to exploration, development and
production activities while the latter refers to
transportation, refining, and marketing activities. Second are
the "independents". These companies focus on downstream
activities, although some are strictly producers of oil and gas
while others concentrate on service operations such as contract
drilling.
The discount rate, or cost of capital, is assumed to be the
same for both categories (see Section F.15). Tax
considerations distinguish the two categories. Majors
calculate depletion on a cost basis while independents use a
percentage basis. Majors expense 70% of intangible drilling
costs while independents expense 100% of these costs (see
Appendix F).
A.6 Summary
Given the economic requirements for oil and gas production
in Alaska, only majors are assumed to operate in Region 11.
This results in 11 regional projects for majors and 10 regional
projects for independents. The 21 basel.ine projects considered
in this analysis are summarized in Table A-l.
A-4
-------
TABLE A-l
MODEL PROJECT CONFIGURATIONS
>
REGION STATE
*
2 NY, PA, KY,
VA, WV, TN
4 AL, AR,
LA, MS
5 IL, IN, 10,
OH, MI, MN, MO
6 ND, SD,
NB, KS
7 TX,
OK
8 ID, MT,
WY
9 AZ, CO, NV,
NM, UT
10 CA
11 AK
PRODUCTION
TYPE
Oil
Oil
Oil
Oil
Gas
Gas
Oil
Oil
Oil
Oil
Oil
Oil
Gas
Gas
Oil
Oil
Oil
Oil
Oil
Oil
Oil
OPERATOR
CATEGORY
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
0182V
A-5
-------
A.7 Reference
1. Natural Gas Annual 1985, U. S. Department of Energy, Energy
Information Administration, DOE/EIA-013K85), November
1986, Table 2.
0268V
A-6
-------
APPENDIX B
TIMING OF EXPLORATION AND DEVELOPMENT PHASES
In developing the model simulations, projects were divided
intotfour phases of project development: (1) time between
lease bid and start of exploration, (2) time from start of
exploration to start of development, (3) time between start of
development and start of production, and (4) production. Each
of these phases is discussed below.
B.I Lease Bid to Start of Exploration
For the lower 48 states, very little time is lost between
the acquisition of a lease and the start of exploration. A few
months may elapse while geological and geophysical prospecting
takes place and capital is raised for drilling. Since time in
the ERG model is measured in terms of years, a "zero" is
entered for this parameter for these eight regions.
The timing for projects in Alaska differs greatly because
of the severe and unique environment in which to work. The
development schedule presented here is based upon the schedule
used in both the National Petroleum Council report on U. S.
Arctic oil and gas production and the report on the
determination of minimum economic field size in the Arctic
National Wildlife Refuge (see Figure B-l).2 The time between
lease bid and the start of exploration is assumed to be two
years since discovery occurs in the third year.
B-l
-------
FIGURE B-l
PROJECTED DEVELOPMENT SCHEDULE FOR
ARCTIC NATIONAL WILDLIFE REFUGE
I
XXXXX1 PLAN1
I
xxxxx,
UNO i
UGCX2C
* D]
IXG
; ;
,
m ?
xxxx.
SCOVl
xxxx
IXXXX
2
3
4
;RMIT
riHG
3XXXXXXX
;RY
PREPARE A
1
OCXXXJ APPR
XXXXX
XXXXX
(XXX PREP A
XXXXX
5
6
:XPLO
ID SU
3VAL
COCXX
OCCXX
IE TS
XXXXX
7
UTIOJN AND
WIT PUNS
1
JF PL
KXXXX
ccxxx
ANS
KXXXX
CCXX
U4SPORT PL
XXXXX
3
XXX 0
*
9
DEL
xxxx
:ONS-
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ESIG!
FIH
10
:NEAT
DEVE
•RUCT]
ION D
ULLIf
LOPME
[ON 0
ID OBTAIN
i AND| CONS]
-------
B.2 Start of Exploration to Start of Development
This phase covers the drilling of exploratory wells and
delineation wells. Drilling can occur on a near-year-round
basis in the lower 48 states. Since this period is only a
matter of months, a "zero" is entered for this parameter for
the fight regions.
In Alaska, however, the drilling season is less than 2
months long. For deep wells, two years may be required for
drilling, in addition, delineation wells are an integral part
of Arctic oil and gas production operations. A total of four
years is assumed for this phase in Region 11.
B.3 From Start of Development to Start of Production
This phase encompasses the planning, building and
installation of the production equipment. In the lower 48
states, this phase can also be completed within a matter of
months. Since it is the third phase with a limited duration,
however, we assign a value of "one" to this parameter for
regions in the continental United States. For Alaska, four
years are assumed to be needed to complete building of the
infrastructure for production.
B.4 Production
Under the schedules described above, production is
projected to begin in Year 1 for regions in the lower 48 states
while production begins in Year 10 for Alaska. Table B-l
summarizes project timing by region.
B-3
-------
TABLE B-l
PROJECT TIMING BY REGION
TIMING
REGION
10 11
Years Between Lease Sale
and Start of Explorations
Years Between Start of
Exploration and Start
of Development
Years Between Start
of Development and
Start of Production
0000000 0 2
0000000 0 4
1111111 1 4
Total Years Between
Lease Sale and Start
of Production
10
Source: ERG estimates.
0225V
B-4
-------
B.5 References
1. U. S. Arctic Oil and Gas, National Petroleum council,
Washington DC, December 1981.
2. Young, J. S. and Hauser, W. S., "Economics of Oil and Gas
Production from ANWR for the Determination of Minimum
Economic Field Size," Bureau of Land Management, Alaska
State Office, Division of Mineral Resources, unpublished
report, November 1986.
0269V
B-5
-------
APPENDIX C
PHASE ONE ASSUMPTIONS - LEASE COSTS
The price paid for a parcel of land is a function of the
cost,per acre and the number of acres in the parcel. Most
onshore leases are purchased from private individuals, although
sales of federal and state lands do occur. There is a general
absence of data on lease prices on private transactions. One
of the few sources of information is the "U. S. Lease Price
Report" published by Lierle Newsletters Inc. This monthly
report summarizes bonuses, royalties, rental, and lease terms
on a county-by-county basis. Table C-l lists the high, low and
average bonuses for each region. These were obtained by
scanning the high and low values for each entry for the region
and by averaging the most common bonus per county data. The
regional costs are based on nearly 1600 entries and form a
"snapshot" of regional prices in November 1986.
Lease prices tend to rise and fall with the price of oil.
For example, lease prices in Wyoming averaged about $19/acre in
November 1986 . In 1985, however, lease bids on federal and
state lands averaged $59/acre and $21/acre, respectively and
2
$284/acre and $24/acre respectively in 1984. The U. S.
average wellhead price per barrel went from $25.88 in 1984 to
$24.09 in 1985 to $11.15 in November 1986.3 To adjust the
1986 prices back to 1985 levels, we multiplied the 1986 costs
by the ratio of November 1986/1985 average annual wellhead
prices for each region (see Section F.6 for a more complete
discussion of regional wellhead prices).
For,- regions whose states do not have spacing requirements,
a minimum parcel size of 40 acres is assumed. Mississippi
requirements are used for Region 4 — 40 or 80 acres for an oil
c-i
-------
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4
well and 320 or 640 acres for a gas well. Technically,
Texas has a minimum spacing of 40 acres per well, oil or gas,
although specific fields may have larger acreage
requirements. In this report, we assume an 80-acre
requirement for a gas well since a gas well can drain a larger
area than an oil well due to the greater mobility of gas in the
reservoir. Wyoming reports that an 80-acre spacing is common
in that state (Region 8). California has no acreage
requirements although its spacing requirement (330 feet from
any boundary line) works out to about one acre. The economic
limit for production, however, can range up to 80 or 160
acres.
Not all wells drilled are successful, so more than one
parcel is need for each project. The discovery efficiency
ranges from 52% to 90% (see Section D.3), so two parcels per
well are required for each region. The project lease bids are
the product of the price per acre, acres per parcel, number of
parcels and the ratio of 1986 to 1985 wellhead prices.
A different approach was used to estimate typical lease
bids in Alaska. TWO sales of Alaska territory were held in
1985 for a total of 80 tracts for $19,302,481. Six of these
tracts were for offshore territories. Removing these resulted
in the sale of 74 tracts for $11,918,167 or $161,056 per
tract. Since tracts range from 1,280 acres to 5,760 acres,
Q
only one tract is needed for an Alaska project.
References
1. "U. S. Lease Price Report", vol. 5 nos. 10 & 11,
October/November 1986, Lierle Newletters inc., Aurora, CO.
C-3
-------
2. Resume 1985; The Complete Annual Review of Oil and Gas
Activity in the United states, Petroleum information
Corporation, Denver, CO 1986.
3. Petroleum Marketing Monthly November 1986, u. S. Department
of Energy, Energy Information Administration,
»OE/EIA-0380(86/11), February 1987.
4. Richard Lewis, Mississipi Oil and Gas Board, Jackson MS,
telephone conversation, 27 January 1987.
5. Virginia Marclay, Texas Railroad Commission, Austin TX,
telephone conversation, 26 January 1987.
6. Winnie Loder, Wyoming Oil and Gas Conservation commission,
Casper WY, telephone conversation, 26 January 1987.
7. William Guerard, California Department of conservation,
Division of oil and Gas, Sacramento CA, telephone
conversation, 26 January 1987.
8. Five-Year Oil and Gas Leasing Program, Alaska Department of
Natural Resources, Division of Oil and Gas, January 1986.
0270V
C-4
-------
APPENDIX D
PHASE TWO ASSUMPTIONS - EXPLORATION COSTS
The exploration phase assumptions include geological and
geophysical expenses, drilling costs and discovery efficiency.
*
The data and methodology used to develop estimates for each of
these parameters are discussed in separate sections below.
D.I Geophysical and Geological Costs
Before a decision is made to drill, the proposed site is
subjected to a variety of geological and geophysical
prospecting procedures. These may include seismic analysis of
the particular site and a study to evaluate the geological
structures with regard to known neighboring productive
formations. These costs are modeled as a percentage of the
lease bid. For onshore production in the lower 48 states, this
percentage has ranged from 43.5% in 1980 to 58.3% in
1 2
1984. ' Onshore and offshore components have not been
separated for Alaska in the recent API surveys. For this
region, geological and geophysical costs ranged from 33% of
lease bids in 1980 to 12.6% in 1984. The 1984 values are used
in this analysis.
D.2 Drilling Costs
The drilling costs per well are based upon the data in the
1985 Joint Association Survey on Drilling Costs. The number
of oil or gas wells, footage drilled, and costs were summed for
«•*
onshore production for every state in a region to give regional
depths and cost per well. Table D-l displays the data used for
D-l
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Region 6 drilling. This procedure was repeated for each region
to obtain the information presented in Table D-2. The costs
for oil and gas wells are calculated independently since gas
wells tend to be more expensive than oil wells in Regions 4 and
7. For the lower 48 states, a dry well is assumed to cost no
more than a productive one.
In Alaska, however, the average cost of a dry well far
exceeds the average cost of a productive oil or gas well, (in
1985, the average cost per foot for onshore projects was
$218.03 for an oil well, $388.72 for a gas well, and $1,439.55
for a dry hole.) For Alaska, 1.14 wells must be drilled to
obtain one productive well (see Section D.3). For this region,
then, the cost of a well is estimated as:
Total Cost of an Alaskan oil well = a + (b * c * d)
where:
a= cost of a productive well ($1,894,007)
b= average depth of an oil well (8,687 ft)
c= average cost per foot for a dry hole ($l,439.55/ft)
d= fraction of dry well drilled for every productive well
(.14)
Total exploratory drilling costs, then, are $3,644,759.
Multiplying this by the discovery efficiency gives a composite
cost of $3,207,388 per well.
D.3 Discovery Efficiencies
The discovery efficiency is the ratio of productive wells
to all wells drilled. The value for this parameter will be
high for well-known areas with broad reservoirs, such as
Appalachia and California, and will be lower in areas where
D-3
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petroleum occurs in small pockets. Discovery efficiences also
vary according to whether the well is for exploration or
development. Only about 10% to 15% of exploratory wells are
4
productive.
Drilling statistics for all wells from 1983 through 1985
were^averaged to obtain regional discovery efficiencies. Data
*
on all wells were used because the single-well basis requires
that the well be a composite of exploratory and development
features. A three-year span of data was used to moderate the
effects of unusually sucessful or unsuccessful years.
Completion date data was used because it provides a more
accurate description of drilling activity than does "as
reported" data. Because of reporting lags in "as reported"
data, cost estimates made on an "as reported" basis do not
reflect the drilling and completion costs in effect at the time
4
of official completion.
Table D-3 shows how regional averages were obtained for
Region 6. This Midwestern area has the lowest discovery
efficiency for the 1983 - 1985 period. The discovery
efficiencies for all regions are summarized in Table D-4.
D.4 References
1. Annual Survey of Oil and Gas/ 1980, U. S. Department of
Commerce, Bureau of the Census, Current industrial Reports,
MA-13k(80)-l, March 1982. These surveys were not continued
beyond 1982 data. The American petroleum institute (API)
undertook its survey due to the termination of the one by
the Bureau of the census. Efforts have been made to
maintain continuity between the surveys although less
detailed information is available in the API publications.
D-5
-------
TABLE D-3
DISCOVERY EFFICIENCY 1983-1985, REGION 6
YEAR
1984
1983
1985
1984
1985
1983
1985
1983
1984
1985
1983
1984
Source
•^
*
STATE OIL
Kansas 2,
Kansas 3,
Kansas 1,
N Dakota
N Dakota
N Dakota
Nebraska
Nebraska
Nebraska
S Dakota
S Dakota
S Dakota
REGION 6 9,
: Completion
of Oil and
811
650
748
386
207
287
71
126
137
12
11
24
470
date
Gas
GAS
430
416
361
3
4
9
1
1
2
3
8
0
1,238
data in
Activity
DRY
3,190
2,996
2,356
324
196
197
169
245
243
15
34
20
9,985
Resume
in the
TOTAL
6,431
7,062
4,465
713
407
493
' 241
372
382
30
53
44
20,693
1985:
United
REGIONAL
NUMBER
OF WELLS
PER
SUCCESS- DISCOVERY
FUL WELL EFFICIENCY
1.93 0.52
The Complete Annual Review
States, Petroleum
Information Corporation, Denver, CO, 1986.
0228V
D-6
-------
0185V
TABLE D-4
REGIONAL WELL DISCOVERY EFFICIENCIES
ALL WELLS DRILLED 1983 - 1985
NUMBER
OF WELLS
PER
•* SUCCESS- DISCOVERY
REGfON
2
4
5
6
7
8
9
10
11
Source:
OIL
6,
7,
13,
9,
52,
2,
4,
7,
919
958
046
470
986
826
592
839
449
Based on
198
GAS
7,
3,
3,
1,
14,
3,
870
820
137
238
032
614
016
329
4
complet
5: The
Activity
in
DRY
3,
8,
6,
9,
27,
2,
2,
ion
Complete
the
Uni
TOTAL
598
308
316
985
497
716
914
912
64
18
20
22
20
94
6
10
9
,387
,086
,499
,693
,515
,201
,522
,'080
517
date data for
Annual
ted
Review
FUL WELL EFF-ICIENCY
1.24
1.71
1.39
1.93
1.41
1.80
1.38
1.11
1.14
1983 -
of Oil
States, Petroleum
0.
0.
0.
0.
0.
0.
0.
0.
0.
80
59
72
52
71
55
72
90
88
1985. Resume
and Gas
Inf ormati
on
Corporation, 1986
D-7
-------
2. 1984 Survey on Oil and Gas Expenditures, American Petroleum
Institute, Washington, DC, October 1986.
3. 1985 Joint Association Survey on Drilling costs, American
Petroleum institute, Washington, DC, December 1986.
4. Resume 1985; The complete Annual Review of Oil and Gas
Activities in the United States, Petroleum Information
Corporation, Denver, CO, 1986.
0271V
D-8
-------
APPENDIX E
PHASE THREE ASSUMPTIONS -'DEVELOPMENT COSTS
E.I infrastructure costs - Oil
The infrastructure costs for regional projects are
presented in Table E-l and have been compiled from a variety of
sources. For Regions 2 and 5, typical drilling costs are given
in Table D-2. Typical total well costs are contained within a
recent industry report for the Appalachian Basin. These range
from $31,000 for an oil well in Pennsylvania to $225,000 for a
shale oil well in West Virginia. Infrastructure costs are
estimated by the difference between total well costs and
drilling costs. A value of $45,000 is used as typical
infrastructure costs in the economic analysis for Regions 2 and
5.
A survey by the Energy Information Administration (EIA)
provides data on equipment costs for oil production. Survey
data is gathered from California, Oklahoma, South Louisiana,
South Texas, West Texas, and Wyoming. The data for primary oil
recovery is presented in Table E-2. Note that the costs for
California are consistently higher than elsewhere in the
nation. The California data was removed and the rest of the
data formed the basis for a regression model that fit cost as a
function of depth:
Infrastructure cost for oil = a * depth
The approximate values for a and b are 482.99 and 0.62,
respectively. Average well depths are given in Table D-2. The
E-l
-------
TABLE E-l
INFRASTRUCTURE COSTS - OIL
REGION
10
11
COST ($)
COMMENTS
-*l
2*
5
4
6
7
8
9
45,000
45,000
73,189
81,855
86,820
102,662
109,357
Difference between typical drilling
costs and total production well
costs. a'b
Calculated from model:
cost = x + depthv.
Equation fitted to data in
Source c. Average depths given
Table D-2.
in
82,560
45,998,400
Infrastructure costs for 2,000 ft
California oil well.c
Costs in 1984 dollars for a field
production rate of 250,000 b/d,d
initial well production rate of 3700
b/d,e, and adjusted to 1985 dollars
using implicit price deflators for
GNP.f
aTable D-2.
b"An Analysis of the Economic impact of New Hazardous
Waste Regulations on the Appalachian Basin Oil and Gas
Industry," submitted by David M. Flannery and Robert E. Lannan,
Robinson & McElwell, Charleston, WV, February 1987.
cCost and indices for Domestic Oil and Gas Field
Equipment and Production Operations 1985, U.S. Department of
Energy, Energy Information Administration, DOE/EIA-0185(85),
April 1986.
dFigure E-l.
eTable F-10.
fEconomic Report of the President 1987, Council of
Economic Advisors, Washington, DC February 1987, Table B-3.
0234V
E-2
-------
TABLE E-2
SUMMARY OF LEASE EQUIPMENT COSTS FOR PRIMARY OIL
RECOVERY OPERATIONS (10 PRODUCING WELLS)
1985 COST* (DOLLARS)
AREA
California
Oklahoma
South Louisiana
South Texas
West Texas
Wyoming
*Preliminary.
Source: Costs and
Equipment
DEPTH:
2,000-
FOOT
WELLS
825,600
527,600
577,000
539,300
537,200
572,000
Indices
DEPTH:
4,000-
FOOT
WELLS
1,121,200
764,200
734,000
694,400
778,200
823, 000
for Domestic Oil
and Production Operations
DEPTH:
8,000-
FOOT
WELLS
1,613,900
1,250,600
955,300
890,800
1,430,900
1,453,900
and Gas Field
1985, U.S.
DEPTH:
12,000-
FOOT
WELLS
2,002,900
1,623,600
1,742,300
1,698,300
1,677,100
1,673,900
Department of Energy, Energy Information Administration,
DOE/EIA-0185(85), April 1986, Table 1.
0235V
E-3
-------
values shown in Table E-l may not match those generated by a
hand calculator due to a greater precision for the parameters
carried in the Lotus spreadsheet.
The average depth for a California oil well is 1,845 feet,
i. e., outside the range surveyed. It is not appropriate to
use^a regression model under these circumstances. For Region
10, then, infrastructure costs were set to the values for- a
2
2,000 foot well, the shallowest in the sample.
For Region 11, infrastructure costs are based upon
information contained in Young and Hauser (1986). Figure
E-l reproduces the curve used in that report to estimate
infrastructure costs. ERG assumed the well was drilled in a
field with a peak production rate of 250 MBPD, the size given
for a field in the Arctic National Wildlife Refuge area. This
results in a cost per peak barrel of $12,000. A peak
production rate of 3700 bbl/day is estimated for this region
(see Section F.3). The infrastructure cost of $44,400,000 is
adjusted to $45,998,400 in $1985 dollars by use of the implicit
4
price inflator for the gross national product.
E.2 Infrastructure Costs - Gas
The two gas projects in the ERG study occur in Region 4 and
Region 7, areas included in the EIA study. Infrastructure
costs for gas production are stratified by both depth and level
of production (see Table E-3 for sample data). The regression
analysis to estimate costs is comparably modeled as a function
of depth and production:
b c
Infrastructure costs for gas = a * depth * production
E-4
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E-5
-------
TABLE E-3
SUMMARY OF GAS LEASE EQUIPMENT COSTS FOR ONE WELL
PRODUCING 500 THOUSAND CUBIC FEET PER DAY
1985 COST* (DOLLARS)
*
AREA
Mid-Continent
North Louisiana
South Louisiana
Rocky Mountains
South Texas
West Texas
Preliminary.
Source: Costs and
Equipment
DEPTH:
4,000-
FOOT
WELLS
21,700
15,600
—
41,900
—
—
Indices
DEPTH:
8,000-
FOOT
WELLS
37,600
36,700
36,700
42,400
36,200
36,600-' ..
for Domestic Oil
and Production Operations
DEPTH:
12,000-
FOOT
WELLS
41,300
40,400
40,400
45,300
40,000
40,300
and Gas
1985,
DEPTH:
16,000-
FOOT
WELLS
45,700
—
40,400
—
—
44,900
Field
U.S.
Department of Energy, Energy Information Administration,
DOE/EIA-0185(85), April 1986, Table 9.
0236V
E-6
-------
Average well depths are given in Table D-2. The values for a,
bf and c are approximately 311.06, 0.41 and 0.18 respectively.
Infrastructure costs for gas are presented in Table E-4. These
values may not match those generated with a hand calculator due
to greater precision in the parameters in the Lotus spreadsheet,
*
E.3 References
1. "An Analysis of the Economic impact of New Hazardous Waste
Regulations on the Appalachian Basin Oil and Gas Industry,"
submitted by David M. Flannery and Robert E. Lannan,
Robinson & McElwee, Charleston WV, February 1987.
2. Cost and indices for Domestic Oil and Gas Field Equipment
and Production Operations 1985, U. S. Department of Energy/
Energy Information Administration, DOE/EIA-0185(85), April
1986.
3. Young, J. S. and Hauser, W. S., "Economics of Oil and Gas
Production from ANWR for the Determination of Minimum
Economic Field Size," Bureau of Land Management, Alaska
State Office, Division of Mineral Resources, unpublished
report, November 1986.
4. Economic Report of the President 1987, Council of Economic
Advisors, Washington D.C., February 1987.
0272-V
E-7
-------
TABLE E-4
INFRASTRUCTURE COSTS - GAS
REGION COST ($)
COMMENTS
35,297
39,824
Calculated from model:
cost = x + depth^ + production.2
See text.
Source: Data taken from costs and indices for Domestic Oil and
Gas Field Equipment and Production Operations 1985,
U.S. Department of Energy, Energy Information
Administration, DOE/EIA-0185(85), April 1986.
0237V
E-8
-------
APPENDIX F
PHASE FOUR ASSUMPTIONS - PRODUCTION PARAMETERS
The production phase encompasses several parameters that
*
lead to both cash inflow and cash outflow for the project, in
terms of cash outflow/ the annual cost of operating and
maintaining (0 & M) a project falls in this category, in terms
of cash inflow, peak production rates, production decline rates
and the wellhead prices for gas and oil interact to generate
project revenues. Each of these parameters is discussed in a
separate section below.
F.1 Operation and Maintanance costs (0 & M)
P.1.1 0 & M costs - Oil
The 0 & M costs for regional oil projects are presented in
Table F-l and have been compiled from the same sources as were
the infrastructure costs. For Regions 2 and 5, typical 0 & M
costs for wells in the Appalachian Basin are given in a recent
industry report. These range from $1,800 for an oil well in
Pennsylvania to $6,500 for a shale oil well in West Virginia.
The average of the costs, $4,100, is the value used for 0 & M
costs for Region 2. The 0 & M cost for an Ohio well in that
report is $6,500. This figure is higher than the $3,863
2
figure given by G. Robb of The Oxford Oil Company. We use
the higher value in the analysis because Oxford Oil frequently
buys and continues to produce wells which other oil companies
consider uneconomical, i.e., Oxford's operating costs are lower
than the local average.
F-l
-------
TABLE P-l
OPERATION AND MAINTENANCE COST
OIL ($/YEARj
REGION
2
5
4
6
7
8
9
10
11
COST ($/YR)
4,100
6,500
13,439
14,529
15,114
17,015
17,781
13,370
690,900
COMMENTS
Average for Appalachian basin well.3
Ohio well.3
Calculated from model:
cost = x + depthv.
Data from Source b.
Average depths given in Table D-2.
O&M cost for 2,000 ft oil well in CA.b
Costs in 1981 dollars,0 adjusted to
1985 dollars using the implicit price.
a"An Analysis of the Economic Impact of New Hazardous
Waste Regulations on the Appalachian Basin Oil and Gas
Industry," submitted by David M. Plannery and Robert E. Lannan,
Robinson & McElwee, Charleston, WV, February 1987.
bCost and indices for Domestic Oil and Gas Field
Equipment and Production Operations 1985, U.S. Department of
Energy, Energy Information Administration, DOE/EIA-0185(85),
April 1986.
cEconomic Report of the President 1987, Council of
Economic Advisors, Washington, DC, February 1987, Table B-3.
0238V
F-2
-------
A survey by the Energy Information Administration (EIA)
4
also provides data on 0 & M costs for oil production.
Survey data is gathered from California, Oklahoma, South
Louisiana, South Texas, West Texas, and Wyoming. The data for
primary oil recovery is presented in Table F-2. Note that the
costs for California are consistently higher than elsewhere in
the .nation. The California data was removed and the rest of
»
the data formed the basis for a regression model that fit cost
as a function of depth:
0 & M costs for oil = a * depth
The approximate values for a and b are 407.48 and 0.43,
respectively. Average well depths are given in Table D-2. The
values shown in Table F-l may not match those generated by a
hand calculator due to a greater precision for the parameters
carried in the Lotus spreadsheet.
The average depth for a California-oil well is 1,845 feet.
Since this is outside the range surveyed, it is not appropriate
to use a regression model to estimate costs. For Region 10,
then, 0 & M were set to the values for a 2,000 foot well, the
4
shallowest in the sample.
For Region 11, 0 & M costs are based upon information
contained in the National Petroleum council report on Arctic
Oil and Gas (1981). in Table E-2 of that report, the annual
operating costs for a 250,000 bbl/day field in the Arctic
National Wildlife Refuge area are estimated at $80 million
dollars for 136 wells. This works out to $588,000/yr annual
operating costs in 1981 dollars. This figure is adjusted to
$690,900/yr in 1985 dollars by use of the implicit price
deflator for the gross national product.
F-3
-------
TABLE F-2
SUMMARY OF DIRECT ANNUAL OPERATING COSTS FOR
PRIMARY RECOVERY OPERATIONS (10 PRODUCING WELLS)
1985 COST* (DOLLARS)
*
AREA
California
Oklahoma
South Louisiana
South Texas
West Texas
Wyoming
*Preliminary.
Source: Costs and
Equipment
DEPTH:
2,000-
FOOT
WELLS
133,700
98,700
123,000
110,200
100,400
114,600
Indices
DEPTH: DEPTH:
4,000- 8,000-
FOOT FOOT
WELLS WELLS
180,700
116,000
179,800
164,900
117,600
129,600.
for Domestic Oil
and Production Operations
296,400
178,200
213,800
196,400
164,500
174,000
and Gas F
1985, U.
tiEPTH:
12,000-
FOOT
WELLS
423,300
223,100
270,100
257,900
217,100
223,500
ield
S.
Department of Energy, Energy information Administration,
DOE/EIA-0185(85), April 1986, Table 3.
0239V
F-4
-------
F.I.2 0 & M Costs - Gas
The two gas projects in the ERG study occur in Region 4 and
A
Region 7, areas included in the EIA study. 0 & M costs for
gas production are stratified by both depth and level of
production (see Table F-3 for sample data). The regression
analysis to estimate costs is comparably modeled as a function
«
of depth and production:
b c
0 & M costs for gas = a * depth * production
Average well depths are given in Table D-2. The values for a,
b, and c are approximately 129.02, 0.46 and 0.14 respectively.
0 & M costs for gas are presented in Table F-4. These values
may not match those generated with a hand calculator due to
greater precision in the parameters in the Lotus spreadsheet.
F.2 Peak Production Rates
Each well is assumed to have its highest rate of production
in its first year of operation. Well performance is a complex
function of the thickness of the oil zone, geometery of the
zone, effective permeability of the zone to oil, oil viscosity,
effective drainage radius of the well and other factors. It is
not surprising, then, that initial production rates and
production decline rates are two parameters for which it is
very difficult to obtain data.
A two-pronged approach is used to obtain regional initial
production rates. First, a range in initial production is
generated based on theoretical modeling efforts by Lohec.
Second,^this range is compared against sample of first-year
production data for actual wells and adjusted accordingly.
F-5
-------
TABLE F-3
SUMMARY OP GAS LEASE OPERATING COSTS FOR ONE WELL
PRODUCING 500 THOUSAND CUBIC FEET PER DAY
1985 COST* (DOLLARS)
*
AREA
Mid-Continent
North
South
Rocky
South
Louisiana
Louisiana
Mountains
Texas
DEPTH:
4,000-
FOOT
WELLS
12,800
12,900
—
19,400
—
West Texas
*
Source
Preliminary.
: Costs and
Equipment
Indices
DEPTH:
8,000-
FOOT
WELLS
17,700
19,000
19,000
21,700
16,300
17,300* .
for Domestic Oil
and Production Operations
DEPTH:
12,000-
FOOT
WELLS
21,100
21,400
21,300
25,700
19,900
21,000
and Gas
1985,
DEPTH:
16,000-
FOOT
WELLS
23,700
—
24,400
—
--
23,500
Field
U.S.
Department of Energy, Energy information Administration,
DOE/EIA-0185(85), April 1986, Table 16.
0240V
F-6
-------
TABLE F-4
OPERATIONS AND MAINTENANCE COST
GAS ($/YR!
REGION
COST ($/YR) COMMENTS
*
4
7
18,486
21,048
Calculated from model:
cost = x + depth^ + production2.
See text.
Source: Data taken from Costs and indices for Domestic Oil and
Gas Field Equipment and Production Operations 1985,
U.S. Department of Energy, Energy Information
Administration, DOE/EIA-0185(85), April 1986.
0241V
F-7
-------
We begin by calculating regional average production rates
in 1985. This process is summarized in Table F-5 for oil and
Table F-6 for gas. For each state/ the average annual
production of oil and casinghead gas is obtained by dividing
the annual production of each product by the number of
producing oil wells. This value is divided by 365 to give
average daily production rates. The same process is followed
*
to generate average daily gas production for the Region 4 and
Region 7 gas projects. Average gas production figures will be
somewhat high because they are calculated from gross
withdrawals. Alaska uses most of its gas for repressurization
and the values in Table F-5 are adjusted downward accordingly.
The regional average production is assumed to be
representative of wells half-way through their productive
life. The prediction of a field's producing time-rate
relationship is of great interest to the producer for the
purpose of economic analysis, forecast planning, sizing of
facilities, etc. An article by Ron Lohec in the Oil and Gas
Journal presents recent work on the mathematical modeling of
well production. Under certain conditions of reservoir
geometry and productivity, Lohec's approach obtains the
exponential decline curve and the hyperbolic decline curve so
8 9 10
often seen in the literature. ' ' One observation from
Lohec's approach is that when a well is half-way through its
productive life, the producing rate can vary from one-fourth to
two-thirds of the initial production rate simply because of
reservoir geometry. The assumption of an exponential decline
rate for a well results in a production rate of one-half the
initial production rate when the well is half-way through its
productive life.
High, middle, and low estimates of the initial production
«-
rate for a region were calculated from the regional average
production figures (see Table F-7). Field data were obtained
F-8
-------
TABLE
AVERAGE OIL WELL PRODUCTION BY REGION
STATE
Kentucky
New York
Pennsylvania
Tennessee
Virginia
west Virginia
REGION 2
Alabama
Arkansas
Louisiana
Mississippi
REGION 4
Illinois
Indiana
Michigan
Missouri
Ohio
REGION 5
Kansas
North Dakota
Nebraska
South Dakota
REGION 6
Oklahoma
Texas
REGION 7
Montana
Wyoming
REGION 8
Arizona
Colorado
Nevada
New Mexico
Utah
REGION 9
California
Alaska
Source:
PRODUCING
OIL WELLS
19853
21,844
4,811
24,000
798
28
15,895
67,376
810
9,700
25,823
3,468
39,801
31,100
7,164
5,125
581
27,975
71,945
51,888
3,697
2,091
165
57,841
103,000
209,040
312,040
4,196
12,038
16,234
28
5,457
45
18,697
1,944
26,171
49,874
977
'Basic Petroleum Data
III, Table 18b.
bBasic Petroleum Data
IV, Table 4b.
cNatural Gas
OIL PRODUCTION '
1000'S OF BBLS
1985&
7,
1,
4,
3,
18,
21,
19,
508,
30,
579,
30,
5,
27,
14,
77,
75,
50,
6,
1,
134,
162,
888,
1,051,
29,
128,
158,
30,
3,
78,
40,
152,
423,
666,
Book, VI NO
Book, VI No
790
071
851
786
26
555
079
581
044
239
641
505
265
168
300
243
988
964
407
857
943
596
803
739
831
570
768
514
282
175
246
039
530
792
782
877
233
GAS PRODUCTION
MMCF-OIL WELLS
1985=
18
2
37
1
36
95
6
50
723
11
792
60
45
106
92
84
1
1
/ 180
455
1,517
1,973
12
200
212
57
218
53
329
250
122
. 3, American
. 3, American
Annual 1985, U.S. Department
,282
,733
,559
,172
0
,221
,965
,556
,533
,341
,685
,635
96
92
,301
0
,561
,050
,429
,438
,674
,934
,475
,921
,238
,159
,335
,295
,630
197
,492
0
,909
,326
,924
,342
,393
Petroleum
Petroleum
AVERAGE
PRODUCTION PER OIL WELL
OIL (BBLS)
ANNUAL
26
1
19
8
14
5
1
1
13
3
9
2
1
4
3
7
10
9
6
5
67
4
20
5
8
681
357
223
202
985
929
224
268
,643
,963
,682
,835
,560
973
721
,327
418
536
,084
,453
,756
,320
,673
,331
,580
,252
,370
,094
,676
,750
,250
,543
,533
,200
,984
,838
,499
,917 1
Institute,
Institute,
of Energy, Energy
DAILY
0.98
0.61
0.55
2.70
2.54 .
0.61
0.74_
73.00
5.38
53.92
24.21
39.89
2.67
1.98
14.59
1.15
1.47
2_._?7
3.98
37.69
9.10
26.50
6.39
4.33
11.65
9.23
19.44
29.25
_26.7_i
17.12
15.19
185.02
11.51
57.49
15.99
23.28
,868.27
September
September
GAS (MCF)
ANNUAL
1
1
2
1
8
5
28
3
19
11
1
1
1
22
11
3
4
7
6
2
16
13
7
10
11
27
12
5
125
837
568
,565
,468
0
,279
,424
,094
,212
,031
,369
,915
3
13
,766
0
,629
,474
,781
,840
801
,721
,120
,426
,258
,323
,940
,639
,098
,036
,535
0
,708
,431
,606
,020
,274
1986, Sect
DAI
2.
1.
4.
4.
0.
6.
_3_._
22.
14.
76.
9.
54.
0.
O.i
32.
O.i
4.
4.i
4.1
62.'
2.
32.
8.'
12.
19.1
i 7
8.
45.
35.
19.
28.
0.
32.
75.
34.
13.
343.
ion
1986, Section
Information Administration,
DOE/EIA-013K85), November 1986, Table 2, col. 2.
Note: Average gas production figures may be high since values are based on gross withdrawals exce
for Alaska and California.
0245V
F-9
-------
TABLE F-6
AVERAGE GAS WELL PRODUCTION BY REGION
•*
»
STATE
Alabama
Arkansas
Louisiana
Mississippi
REGION 4
Oklahoma
Texas
REGION 7
Source: Natural
PRODUCING
GAS WELLS
1985
863
2,623
16,716
710
20,912
24,756
44,320
69,076
Gas Annual
GAS PRODUCTION
MMCF-GAS WELLS
1985
136,864
131,406
4,494,257
180,212
4,942,739
1,480,420
5,059,681
6,540,101
AVERAGE
PER GAS
ANNUAL
158,591
50,098
268,860
253,820
236,359
59,800
114,162
94,680
1985, U.S. Department of
PRODUCTION
WELL (MCF)
DAILY
434.50
137.25
736.60
695.40
647.56
163.84
312.77
259.40
Energy,
Energy Information Administration. DOE/EIA-013K85),
November 1986.
0246V
F-10
-------
TABLE F-7
DAILY INITIAL PRODUCTION RATES
THEORETICAL RANGE IN
INITIAL PRODUCTION^1
REGION
2
4
4
5
6
7
7
8
9
10
11
PRODUCT
Oil
Basing
Oil
Casing
Gas
Oil
Casing
Oil
Casing
Oil
Casing
Gas
Oil
Casing
Oil
Casing
Oil
Casing
Oil
Casing
AVERAGE
PRODUCTION3
0.7
3.9
39.9
54.6
647.6
3.0
4.0
6.4
8.6
9.2
17.3
259.4
26.7
35.9
16.0
34.5
23.3
13.8
1868.3
343.2
LOWER
1
6
60
82
971
4
6
10
13
14
26
389
40
54
24
52
35
21
2802
515
MID-RANGE
1
8
80
109
1,295
6
8
13
17
18
35
519
53
72
32
69
47
28
3,737
686
UPPER
3
16
160
218
2,590
12
16
26
34
37
69
1,038
107
143
64
138
93
55
7,473
1,373
RANGE IN INITIAL
PRODUCTION SEEN
IN FIELD DATAC
LOWER
3
22
20
95
0
2
4
3
44
218
239
6
1
6
16
5
94
4,000
UPPER
21
60
233
2,731
13
38
211
30
2,658
111
23
37
105
343
DATA
USED IN
ANALYSIS
3
16
36
68
971
12
16
26
34
37
69
1,038
53
72
32
69
35
0
3,700
686
Note: Production figures are in units of bbl/day or Mcf/day.
aSee Tables F-5 and F-6. ??????
bBased on information in Lohec, Ron E., "Analytical Approach Evaluates Frontal
Displacement Mechanism I and II," Oil and Gas Journal, September 17, 1984, 83-89 and
September 24, 1984, 92-97.
GField data provided by various sources. Region 2: "An Analysis of the Economic
of New Hazardous Waste Regulations on the Appalachian Basin Oil and Gas Industry",
Robinson and McElwee, Charleston, WV, February 1987. Region 4: Jackie Hodges,
Department of Natural Resources, Baton Rouge, LA. Region 5: Graham Robb, Oxford Oil
Co., Ohio. Regions 6-10: Petroleum Information Corporation, Denver and Houston
offices. Region 11: U.S. Arctic Oil and Gas, National Petroleum Council, 1981.
0186V
F-ll
-------
on approximately 100 wells and the first twelve months'
production was averaged for each region. The upper and
lower ranges for these data are shown in columns 7 and 8 in
Table F-7. The upper theoretical estimates agree well with the
field sample data for Regions 2, 5, 6, and 7 (both oil and
gas). For gas production in Region 4, and oil production in
Region 10, the lower theoretical estimate appears to fit the
Md.
fieJd data. For Regions 8, 9, and 11, the mid-range estimates
fall within the mid-range of the field data. On the basis of
the low values seen in some of the field data, the initial
production for Region 4 oil projects was adjusted closer to the
regional averages. The right-hand column in Table F-7
summarizes the production values used in the analysis.
The estimation of regional initial production rates
highlights some of the difficulties of analyzing an industry
chararacterized by diversity. Some readers may consider the
estimates too high while others may consider them too low in
light of some known producers. The use of regional averages
implies a loss of information about the extremes in well
productivity. On the low end, there are wells that are
produced to recover sunk costs, not because they are
economical. On the high end, there are very large producers,
such as those in southern Louisiana whose production averages
1125 Mcf/day/well.12
For this study, the regional models have initial production
rates ranging from less than 10 bbl/day (strippers) to 3,700
bbl/day. The regional models, then, reflect the large
diversity seen in U.S. oil production.
F-12
-------
P.3 Years at Peak Production
Each case in the analysis models a single well. Peak
production, therefore/ occurs for only one year. In contrast,
a field may take several years to reach peak production and may
remain at peak production for several years due to the
continual addition of new wells.
*
P.4 Production Decline Rates
The pattern of decline in a well's productivity can vary
greatly due to many factors (see Section P.2). ERG models
production decline as an exponential function, i.e., a constant
percentage of the remaining reserves is produced in any given
year. Table P-8 lists the production decline rates for each
regional project. The decline rate for Region 2 is based upon
field data in an industry survey. Note that it is the
lowest decline rate in the series. Wells in Appalachia are
known to be small but long-term producers. For the remaining
regions, decline rates are derived from ratios of 1985
production to estimated remaining reserves for over 100 onshore
fields published in an Oil and Gas Journal article. Table
F-9 lists the five highest decline rates for each region in the
sample. The decline rate for a field cannot exceed that of an
average well in the field. However, a low field decline rate
may be the result of a small number of wells in a large field.
Note that actual field decline rates frequently exceed the 10%
to 15% rule-of-thumb proposed in textbooks on oil
production.
F-13
-------
TABLE P-8
PRODUCTION DECLINE RATE BY REGION
PRODUCTION
REGION DECLINE RATE
2 9%
4 30%
5 32%
6 20%
7 37%
8 28%
9 17%
10 30%
11 13%
Source: Developed by ERG from
sources cited in text.
0247V
F-14
-------
TABl^F-9
FIELD PRODUCTION RATES
FIVE HIGHEST RATES PER REGION
REGION
4
5
6
7
8
9
10
11
Source:
STATE
MS
LA
LA
MS
LA
IL
IL
IL
IL
IL
KA
KA
KA
KA
KA
TX
TX
TX
TX
TX
WY
WY
WY
WY
WY
NM
NM
NM
NM
CO
CA
CA
CA
CA
CA
AK
AK
AK
AK
AK
"U.S.
PRODUCTION
(10001
4,424
468
1,176
1,202
456
926
2,075
2,770
2,700
3,400
1,351
1,496
1,359
1,329
1,508
21,396
2,412
18,912
24,300
33,324
3,650
5,662
2,655
2,635
3,042
2,023
800
6,651
13,081
12,507
216
1,016
236
1,227
2,346
568,212
3,012
2,172
7,548
3,060
1985
EST. REM.
RESERVES
S of bbls)
15,576
1,615
4,000
4,000
1,475
1,800
4,000
4,901
4,200
5,100
6,500
6,400
5,800
5,600
6,000
60,000
6,588
50,000
60,000
56,676
18,000
20,000
8,488
8,000
8,000
10,792
3,263
25,000
46,000
30,000
983
3,632
835
3,700
6,220
5,101,761
19,890
13,750
47,133
11,705
Fields with Reserves Exceeding 100 Mi
Oil and Gas Journal/
January 27, 1986, pp.
FIELD
PRODUCTION
DECLINE
RATE
22.1%
22.5%
22.7%
23.1%
23.6%
34.0%
34.2%
36.1%
39.1%
40.0%
17.2%
18.9%
19.0%
19.2%
20.1%
26.3%
26.8%
27.4%
28.8%
37.0%
16.9%
22.1%
23.8%
24.8%
27.5%
15.8%
19.7%
21.0%
22.1%
29.4%
18.0%
21.9%
22.0%
24.9%
27.4%
10.0%
13.2%
13.6%
13.8%
20.7%
llion Bbl,"
104-105.
0187V
F-15
-------
F.5 Wellhead Prices (First Purchase Prices)
The wellhead price of oil or gas (also known as the "first
purchase price") determines the gross revenues for a project's
production. Annual 1985 wellhead prices for each state were
averaged to obtain the regional averages (see Table
F-icg.14'15
F.6 References
1. "An Analysis of the Economic impact of New Hazardous Waste
Regulations on the Appalachian Basin Oil and Gas Industry,"
submitted by David M. Flannery and Robert E. Lannan,
Robinson & McElwee, Charleston, WV, February 1987.
2. Graham Robb, The Oxford Oil Company, Zanesville, Ohio,
personal letter, 14 January 1987.
3. Graham Robb, The Oxford Oil Company, Zanesville, Ohio,
telephone communication, 21 January 1987.
4. Cost and Indices for Domestic Oil and Gas Field Equipment
and Production Operations 1985, U. S. Department of Energy,
Energy information Administration, DOE/EIA-0185(85), April
1986.
5. U. S. Arctic Oil & Gas, National Petroleum Council,
Washington, DC, December 1987.
6. Economic Report of the President 1987, Council of Economic
Advisors, Washington DC, February 1986.
«-
7. Lohec, R. "Analytical Approach Evaluates Frontal
Displacement Mechanism," Oil and Gas Journal, 17 September
1984 and 24 September 1894.
F-16
-------
TABLE F-10
1985 ANNUAL WELLHEAD PR IC E S
STATE
Kentucky
New York
Pennsylvania
Tennessee
Virginia
West Virginia
REGION 2
Alabama
Arkansas
Louisiana
Mississippi
REGION 4
Illinois
Indiana
Michigan
Missouri
Ohio
REGION 5
Kansas
Nebraska
North Dakota
South Dakota
REGION 6
Oklahoma
Texas
REGION 7
Montana
Wyoming
REGION 8
Colorado
New Mexico
Utah
REGION 9
California (Region 10)
Alaska - North Slope
(Region 11)
Source:
aNatural Gas Annual
GASa
($ PER MCF)
2.39
3.37
3.16
2.48
3.02
3.85
3.05
3.71
2.55
2.66
3.17
3.02
2.77
2.51
3.60
3.50
3.08
3.09
1.27
3.01
1.90
2.51
2.17
2.47
2.33
2.40
2.39
3.01
2.70
2.90
2.62
3.52
3.01
3.36
0.74
1985, U.S. Department of
Energy Information Administration, DOE/EIA-013K 85
1986.
^Petroleum Marketing
OILb
($ PER BSD
26.20
25.19
25.05
24.35
25.20
25.77
25.79
27.22
25.51
26.07
26.90
26.82
26.16
25.11
26.25
25.33
25.42
25.32
25.79
25.47
26.28
26.80
26.54
25.29
24.67
24.98
25.64
26.84
23.98
25.49
22.14
16.98
Energy,
), November
Annual 1985, U.S. Department of
Energy, Energy Information Administration, DOE/EIA-0487(85)/l
December 1986.
0248V
F-17
-------
8. Muskat, M., Physical Principals of Oil Production,
McGraw-Hill Book Company, New York, NY, 1949, pp. 456-61.
9. Chilingar, G. V., Mannon, R. W., and Rieke, H.H. Ill
(ed.s), Oil and Gas Production from Carbonate Rocks,
American Elsevier Publishing Company, Inc., New York, NY,
J.972, pp. 216-29.
*
10. North, F. K., Petroleum Geology, Allen & Unwin, Boston, MA,
1985, pp. 477-80.
11. Data for Region 2: see Reference 1; Region 4: Jackie
Hodges, Department of Natural Resources, Baton Rouge LA;
Region 5: Graham Robb, The Oxford Oil Company, Zanesville
OH; Regions 6-10: Petroleum Information corporation
Denver and Houston offices; Region 11: see Reference 5.
12. Jackie Hodges, Department of Natural Resources, Baton Rouge
LA, monthly activity report for August 1986.
13. "U. S. Field with Reserves Exceeding 100 Million Bbls," Oil
and Gas Journal, 27 January 1986, pp. 104-05.
14. Petroleum Marketing Annual 1985, U. S. Department of
Energy, Energy Information Administration,
DOE/EIA-0487(85)/1, vol. 1, December 1986.
15. Natural Gas Annual 1985, U. S. Department of Energy, Energy
Information Administration, DOE/EIA-013K85), November 1986,
0273V
F-18
-------
APPENDIX G
BASE CASE FINANCIAL ASSUMPTIONS AND RATES
The economic and financial accounting assumptions used in
the .economic model are based upon common oil industry financing
*
methods and procedures. Changes in tax computations due t-o the
Tax Reform Act of 1986 (Public Law 99-514) are incorporated in
the ERG model.
G.I Incremental impact of Model Project on corporate income
Tax Rate
It is assumed that the model projects are incremental to
the other activities of the company, and therefore, the net
taxable income is marginally taxed at the U. S. corporate rate
of 34 percent. This assumption implies that the company has at
least $75,000 of other net income without this project, in
addition, it is assumed that any net losses in the initial
years of a project can be applied to the net income of other
projects, so that an effective tax shield of 34 percent of the
loss is realized. Therefore, the yearly net cash outflow is
100 percent minus 34 percent, or 66 percent of the year's
loss.
G.2 State Corporate Tax Rates
State corporate taxes are incurred upon onshore oil and gas
project revenues. Rather than compile regional averages to
estimate state corporate tax rates, a state was chosen in each
region.»• The tax structure of this state provides the basis for
G-l
-------
both state corporate taxes and severance taxes. Averaging
state corporate taxes and severance taxes independently may not
provide a reasonable approximation to a tax situation under
which an oil company may actually operate.
State taxes are incurred for project revenues generated
within that state. Taxes are calculated on the same earnings
*
basis as federal taxes. Table G-l summarizes the regional
corporate tax rates and the states upon which they are based.
G.3 Severance Taxes
State severance taxes are also applicable to revenues
generated by onshore oil and gas production. Table G-2 lists
the severance taxes for oil and gas by region, and the state
upon which they are based. In the ERG model, severance taxes
are calculated upon the gross revenues of the project, i.e.,
wellhead price times units of production. This is the most
common basis, although some states have a flat fee per unit of
production (e.g., Louisiana imposes a 7ft per Mcf tax on gas).
California, at present, sets its tax rate on an annual
basis to cover the costs of the Department of Conservation
operations. In 1985, state and local production taxes were
2
approximately 0.14 percent of gross revenues, and this value
is used in Table G-2.
The Alaska severance tax structure consists of nominal
rates which are then adjusted by a formula. The formula is
referred to as the ELF, the Economic Limit Factor.
Nominal tax rates on oil are 12.25 percent of gross
revenues for the first 5 years of production and 15 percent
G-2
-------
TABLE G-l
REGIONAL STATE CORPORATE TAX RATES
REGION
•»
2'
4
5
6
7
8
9
10
11
STATE
Kentucky
Alabama
Illinois
Kansas
Oklahoma
Montana
Colorado
California
Alaska
CORPORATE TAX RATEa
7.25%
5.00%
4.00%
6.75%
5.00%
6.75%
6.00%
9.35%
9.40%
aPercentage based on earnings before interest and taxes.
Source: State Tax Handbook; as of October I/ ^986, Commerce
Clearing House, Chicago, IL, October 1986.
0249V
G-3
-------
TABLE G-2
REGIONAL SEVERANCE TAX RATES
SEVERANCE TAXa
REGION
2
4
5
6
7
8
9
10
11
STATE
Kentucky
Alabama
Illinois
Kansas
Oklahoma
Montana
Colorado
California
Alaska
OIL
4.5%
10%
—
8%
7%
5%
4%
0.14%
d
GAS
—
10%
--
8%
7%
2.65%
4%b
0.14%c
d
aPercentage of gross revenues.
^Graduated from 2 percent to 5 percent of wellhead value,
GSee text.
^Severance taxes affected by Economic Limit Factor
(ELF). See text.
Source: State Tax Handbook: as of October 1, 1986/ Commerce
Clearing House, Chicago, IL, October 1986.
0250V
G-4
-------
thereafter. The ELF formula3 for oil is
/ \ 460 x WD
ELF
PEL
1 - PEL
TP
I
where:
;*-
PEL = monthly production at the economic limit
TP = total monthly production
WD = well days for the month (assumed to be 30)
The monthly production at the economic limit value is
confidential between the oil company and the Alaska Department
of Revenues. Three hundred bbl/day/well or 9,000
bbl/month/well is used for the economic limit (PEL) in this
4
analysis.
As an example, suppose monthly production is 50,000
barrels. Then the ELF is:
460 x 30
ELF =
9,000
9,000
1 - 50,000
= (.82)1-533 = .74
If the ELF is greater than .7, then the tax rate is the
nominal rate. If the ELF is less than .7, severance taxes are
calculated as follows:
For the first five years of production:
Oil Severance Taxes = Gross revenues x 12.25 percent x ELF,
v
After the first five years of production:
G-5
-------
Oil Severance Taxes = Gross revenues x 15.00 percent x ELF.
The nominal severance tax rate on natural gas is 10
percent, which is adjusted by the following ELF formula:
' PEL
ELF = 1 - TP
where:
PEL = monthly production at the economic limit
TP = total monthly production.
Three thousand Mcf/day/well or 90,000 Mcf/month/well is used
4
for the economic limit. Gas severance taxes are calculated
as follows:
Gas Severance Taxes = Gross revenues x 10.00 percent x ELF.
Unlike the oil severance ELF, the gas ELF is applied as long as
it is positive.
For offshore leases, the basis for the severance tax
calculation would be on the basis of (gross revenues - exempt
revenues) where royalty payments to state government are
considered exempt revenues.
G.4 Royalty Rates
Operators of oil and gas producing properties are usually
required to pay royalties to the lessors or owners of the land
based on the value of extracted production. Since many of the
lessors are private individuals rather than state or federal
G-6
-------
agencies, royalty rates are primarily taken from the "U. S.
Lease Price Report" that summarizes private sector/ state
and federal activity in leasing. The range in royalty rates
varies from a low of 12.50 percent to a high of 25.00 percent.
The royalty rates chosen for each region are listed in Table
G-3. Region 11 (Alaska) is not included in the price report.
Two .^lease sales were held in 1985, one with a 12.50% royalty
and the other with a 16.75% royalty. An average value of
14.30% is used in this analysis.
G.5 Rental Payments
Rental payments generally comprise a negligible cash
outflow in the overall set of costs for an oil and gas
project. For this reason, they have been excluded from the
analysis.
G.6 Depreciation
The Tax Reform Act of 1986 modifies the Accelerated cost
Recovery System (ACRS) for property placed in service after 31
December 1986. Under the new system, most oil and gas
equipment will be classified as seven-year property. The
recovery method for this class is double declining balance.
The schedule used to write off capitalized costs in the model
is as follows:
Year 1 14.29% of costs
Year 2 24.49%
Year 3 17.49%
Year 4 12.49%
r*
Year 5 8.93%
Year 6 8.92%
G-7
-------
TABLE G-3
REGIONAL ROYALTY RATES
ROYALTY RATE (%)
"d,
*
REGION
2
4
5
6
7
8
9
10
11
Source:
LOW
12.50
12.50
12.50
12.50
12.50
12.50
12.50
12.50
12.50
U.S. Lease Price Report, Vol.
Newsletters, Inc., Aurora, CO
For Alaska, Five-Year Leasing
HIGH
25.00
25.00
25.00
20.00
25.00
18.75
18.75
25.00
16.75
MOST COMMON
OR AVERAGE
18.75
18.75
12.50
12.50
20.00
12.50
16.00
18.75
14.30
5, No. 10 & 11, Lierle
, October/November 1986.
Programs, Alaska
Department of Natural Resources, Division of oil and
Gas, January 1986.
0251V
G-8
-------
Year 7 8.93%
Year 8 4.46%
Year 1 in the above table is defined as the first year in which
the equipment is placed in service. According to relevant
accounting principles, this is the first year in which the
*
equipment produces oil or gas.
G.7 Basis for Depreciation
The Tax Reform Act of 1986 repealed the investment Tax
7 8
Credit. ' This means that the initial basis for
depreciation is 100 percent of the total capitalized costs,
G.8 Capitalized Costs
It is assumed that the tax payer (oil company) elects to
expense intangible drilling costs incurred in the development
of oil and gas wells, intangible drilling costs (iDCs) are
estimated, on the average, to represent 60 percent of the cost
of production wells and their infrastructure. ' The Tax
Reform Act limits major integrated producers to expensing 70
percent of IDCs with the remaining 30% capitalized. (That is,
a major may only expense .60 times .70, or 42 percent of its
IDCs.) Independents are still allowed to expense 100 percent
of its IDCs. The remaining 40 percent of the total cost is
capitalized and treated as depreciable assets for tax
purposes.
Dry^holes are written off in the year in which the cost is
incurred. For independents, the proportion of the exploratory
drilling cost which is capitalized is therefore equal to 40
G-9
-------
percent of the total drilling cost times the discovery
efficiency. For majors, the proportion is 58 percent of the
total drilling cost times the discovery efficiency. The
remaining drilling costs are expensed.
G.9 .^inflation Rate
t
Although the model is capable of simulating inflated prices
and costs/ an inflation rate is not explicitly assumed.
Instead, the entire analysis is done in real terms, and a real-
inflation-adjusted discount rate of 8.0 percent is used.
G.10 Escalation of General Project Costs in Real Terms
It is assumed that costs will remain constant in real
terms, i.e., the rate of increase in material and labor costs
is equal to the rate of inflation.
G.ll Oil Depletion Allowance
The ERG model calculates depletion on both a cost basis and
a percentage basis. The value used in subsequent calculations
is determined by a flag identifying whether the oil company is
a major or an independent. (Majors use cost basis while
independents use percentage basis to calculate depletion.)
Cost depletion allows the producer to recover the leasehold
cost over the producing lifetime of the well. The leasehold
cost consists of the bonus bid (see Appendix B), and certain
geological, geophysical and legal costs (see Appendix C).
G-10
-------
G.ll.l Depletion - Cost Basis
Cost depletion is based on units of production and is
represented by the following formula:
B = U + S
»
where:
B = adjusted basis of leased property
S = units sold during the period
U = units remaining at the end of the period.
The initial basis of the property used in the ERG model
consists of the bonus bid and the geological and geophysical
expenses. (That is, the legal costs incurred in acquiring the
lease are not explicitly included in the model. It is assumed
they form a minimal increment to the overall leasehold cost.)
The basis is then adjusted downward to account for the
depletion taken in each period. The portion of the adjusted
basis taken as depletion in any given period is the units sold
during the period, divided by the units sold and the
recoverable units remaining. For the purposes of the model, it
is assumed that all units produced in a period are sold in the
same period. Thus, the depletion for any given period is equal
to the adjusted basis multiplied by the ratio of units produced
in the period to the sum of the units produced and remaining.
In this manner, the leasehold cost is amortized over the
productive life of the well.
G-ll
-------
G.11.2 Depletion - Percentage Basis
The rules for percentage depletion are found in Sections
613 and 613a of the tax code. When production is less than
1/000 barrels a day/ depletion is calculated as follows:
Depletion = (a - b) * .15 * (1 - c)
»
where:
a = gross oil revenues
b = oil royalties
c = royalty rate.
When production exceeds 1/000 barrels a day, the following
formula is used:
Depletion = (1000 * a) * 0.15 * (1 - c)
£
where:
a = wellhead price per barrel of oil
c = royalty rate.
That is/ independents are allowed to take an allowance of 15
percent of taxable revenues based on production up to and
including 1000 barrels of oil per day.
An analogous set of equations applies for the gas depletion
allowance except that the limit on the depletable quantity is
6/000 Mcf per day.
G-12
-------
G.12 Salvage
It is assumed that the after-tax cost to remove the
infrastructure and to retire the well at the end of its
economic life is approximately equal to their salvage values.
Hence, there is no additional positive or negative cash flow.
G.13 Investment Tax Credit
The Tax Reform Act of 1986 repealed the Investment Tax
Credit.7'8
G.14 Windfall Profits Tax
A phaseout of the Windfall Profits Tax of 1980 will begin
no later than January 1991, with a 33-month phaseout beginning
as early as January 1988. Under these, conditions, the Windfall
Profits Tax will apply, at most, to the first few years of the
projects. In addition, the industry is trying to have the tax
12
repealed in its entirety at an earlier date. For these
reasons, the effects of the Windfall Profits Tax have not been
included in the analysis.
G.15 Discount Rate
The discount rate used in this analysis represents the
opportunity cost of capital for investments in oil and gas
production. The cost of capital is the investor's expected
rate of return for a particular investment. That is, the cost
of capital is the return that could be earned elsewhere in the
**
economy on projects of equivalent risk. The riskier the
investment, the higher the cost of capital.
G-13
-------
The opportunity cost of capital is modeled as
Real cost
of
Capital
|"l + nominal cost j - 1
[l + inflation rateJ
where:
nominal cost = [equity cost * equity share] + [debt share *
debt cost]
The equity cost is the sum of the risk-free return and the
risk premium. For the risk-free return, ERG uses the average
return on long-term U. S. Treasury bonds. The risk premium is
the product of the average industry risk (i.e., the industry
beta) and the market risk for long-term investment.
£
The debt and equity shares are the portions of capital
financed by debt and equity, respectively. These are estimated
by the average share of debt or equity in the firm's value.
The debt cost is the after-tax cost of debt, i.e., the
product of the current cost of debt and (1 minus the corporate
tax rate). For the current cost of debt, the interest rates
for Moody's Baa corporate bonds are used.
The next point to consider is whether to use long-term or
short-term estimates for each of these parameters. The
productive life of the project can be several decades in the
ERG model. On this basis, long-term average values are used in
estimating the cost of capital.
G-14
-------
Table G-4 compiles twenty-year averages for risk-free
returns, current cost of debt, and inflation rates. (Most
projects in this study are no longer profitable after twenty
years of production.) Table G-5 gives the average long-term
debt to capital ratio for 19 major integrated companies. This
ratio varies around 25% for the time period investigated. On
this*basis, we use 25% as the debt share and 75% as the equity
»
share in the cost of capital calculations.
The cost of capital is calculated in Table G-6. Sources
for the remaining parameter values are cited in the table. The
estimated cost of capital is 7.55%. This value is rounded
upwards to 8% for use in the analysis.
G.16 References
1. William Guerard, California Department of conservation,
Division of Oil and Gas, telephone*conversation, 30 January
1987.
2. "The Oil and Gas Producing Industry in Your State
1986-1987," Petroleum independent, special issue,
Independent Petroleum Association of America, Washington,
DC, September 1986.
3. Nelson, L., Alaska Department of Revenue, March 1983.
4. Logsden, C., Alaska Department of Revenue, June 1983.
5. "U, S. Lease Price Report," vol. 5 nos. 10 & 11,
October/November 1986, Lierle Newsletters Inc., Aurora, CO.
r
6. Five-Year Oil and Gas Leasing Program, Alaska Department of
Natural Resources, Division of oil and Gas, January 1986.
G-15
-------
TABLE G-4
TWENTY-YEAR AVERAGES FOR RISK-FREE/ CORPORATE BORROWING,
•*
YEAR*
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
Average
Source:
AND
RISK-
FREE
RATE
5.07
5.65
6.67
7.35
6.16
6.21
6.84
7.56
7.99
7.61
7.42
8.41
9.44
11.46
13.91
13.00
11.10
12.44
10.62
7.68
8.63
Economic Report
INFLATION RATES
CORPORATE
BORROWING
RATE
6.23
6.94
7.81
9.11
8.56
8.16
8.24
9.50
10.61
9.75
8.97
9.49
10.69
13.67
16.04
16.11
13.55
14.19
12.72
10.39
10.54
of the President 1987,
INFLATION
RATE
2.6
3.7
4.4
3.6
3.5
2.9
5.5
7.8
8.0
5.3
5.1
6.2
8.5
9.3
9.3
6.2
4.1
4.0
3.7
2.8
5.3
Council of
Economic Advisers, January 1987, Table B-68, 10-year
U.S. Treasury securities, and Moody's Baa corporate
bonds/ Table B-4, inflation rate.
0252V
G-16
-------
TABLE G-5
DEBT/CAPITAL RATIO (%)
MAJOR INTEGRATED
OIL COMPANIES
IN 19-COMPANY
ERG GROUP
(1977-1985)
1977
Amerada Hess
American Petrofina
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oil (Texaco)
Gulf Oil (Chevron)
Kerr-McGee
Mobil Oil
Murphy Oil
Occidental Petroleum
Phillips Petroleum
Shell Oil (Royal Dutch
36.
26.
34.
38.
14.
5.
13.
20.
25.
35.
26.
21.
20.
7
4
2
1
4
8
5
9
2
5
8
0
6
1978
36.0
45.8
34.6
38.4
13.3
4.7
14.1
16.6
25.6
40.5
39.4
16.3
18.4
1979
30.0
40.4
29.4
38.1
13.3
4.0
13.0
20.4
21.3
32.3
39.0
13.6
30.6
1980
29.
33.
27.
36.
12.
10.
10.
24.
19.
19.
25.
12.
33.
5
5
1
0
5
8
7
1
0
1
6
4
0
1981
35.2
28.1
28.9
34.0
12.0
9.8
13.0
33.1
17.3
21.1
20.1
15.0
31.3
1982
38.9
26.0
28.7
34.3
10.6
16.6
14.6
29.7
21.1
16.9
43.5
22.7
27.8
1983
40.3
31.4
26.2
37.0
10.5
—
--
27.1
24.4
15.1
34.0
23.3
19.1
1984
40.1
39.1
26.9
28.1
11.6
--
--
23.5
40.9
14.3
43.3
26.0
17.3
1985
40.6
40.8
43.9
40.7
10.4
--
--
23.4
35.8
13.7
47.6
64.3
14.6
Petroleum)
Standard Oil of California
(Chevron)
Standard Oil of Indiana
(Amoco)
Standard Oil of Ohio
Sun Company
Texaco
Union Oil Company
Unweighted
Company Average3
16.2
25.2
71.9
18.9
19.1
26.8
19.7
23.5
65.4
19.4
24.8
28.6
17.2 13.0
21.1 ll.8
50.3 39.8
16.8 34.5
21.8 18.0
26.0 21.9
12.4 11.3
10.6
43.4 28.9
21.4 22.0 20.1 17.3
36.1 33.8
28.6 24.7
15.1 12.8
18.3 18.6
29.2
24.8
14.1
17.6
16.9
26.4 25.4
25.3 20.7
41.0 31.6
15.3 64.1
26.2 27.6 25.2 23.1 22.7 23.9 23.8 28.2
33.1
Source: "Oil, Basic Analysis," Standard and Poor's Industry Surveys, November 4, 1982
and November 27, 1986.
aSimple average calculated from the ratios for all companies in the sample.
0253V
G-17
-------
TABLE G-6
COST OF CAPITAL CALCULATIONS
PARAMETER
VALUE
SOURCE
Risk*free return
Industry beta
Market risk
8.63% See Table G-4.
0.84% Kavanaugh, M. "Cost of
Capital in the Petroleum
Industry," memorandum to M.
Podar, U.S. Environmental
Protection Agency, 15 January
1987. Average beta for 24
petroleum companies, Standard
& Poor's Stock Reports.
8.00% Brealey and Myers, Principles
Risk premium
Cost of debt
Debt cost
Debt share
Equity share
Inflation rate
Nominal cost
Real cost
6.72%
10.54%
6.96%
25.00%
75.00%
5.30%
13.25%
7.55%
of Corporate Finance, 1985,
p. 129.
Calculated.
See* irable G-4.
Tax Reform Act of 1986,
highest corporate tax bracket
is 34 percent.
See text.
See text.
See Table G-4 .
0254V
G-18
-------
7. Snook, S. B. and Magnuson, W. J. Jr., "The Tax Reform Act's
Hidden Impact on Oil and Gas," The Tax Adviser, December
1986, pp. 777-83.
8. Tax Reform Act of 1986; Analysis, Coopers and Lybrand, NY,
1986.
^,
•
9. Annual Survey of Oil and Gas, 1980, U. S. Department of
Commerce, Bureau of the Census, current industrial Reports,
MA-13M80)-!, March 1982.
10. Annual Survey of Oil and Gas, 1981, U. S. Department of
Commerce, Bureau of the census, current industrial Reports,
MA-13k(81)-l, March 1983.
11. 1984 Survey on Oil and Gas Expenditures, American Petroleum
Institute, Washington, DC, October 1986.
12. "U.S. Government Must Act to Avert
-------
APPENDIX H
ERG ECONOMIC MODEL FOR ONSHORE PETROLEUM PRODUCTION
H.I introduction
The ERG model simulates the costs and petroleum production
dynamics expected in the development and production of an
onshore well for oil and/or gas. Data to define the well and
the petroleum reservoir are entered into the model. Through
the use of internal algorithms, the model calculates the
economic and engineering characteristics of the project.
Outputs from the model include: production volume, project
economics and summary statistics.
The model is structured to be flexible, it is capable of
modeling projects on a single-well or multiple-well basis with
exploration and development occurring within a single year or
over a decade. Flexibility is possible through the use of
user-specified inputs for a wide variety of variables, inputs
include, but are not limited to: lease bids, development
schedules, infrastructure and operating costs, initial
petroleum production, production decline rates, tax rate
schedules, and wellhead prices. The data define the proposed
development project.
From the user-specified data, costs and production
performance are calculated on a yearly basis through a series
of algorithms. The model calculates yearly production, present
value of yearly production and present value of production
income. The model generates a consistent set of annual values
and summary statistics to evaluate the project. All dollar
amounts in this analysis and in the accompanying printout are
in thousands of 1985 dollars.
H-l
-------
H.I.I Model Phases
The project life of an onshore well for oil and/or gas is
divided into four phases: (1) from lease bid to the start of
exploration, (2) from the start of exploration to the start of
development, (3) from the start of development to the start of
production, and (4) production. Since the onshore projects in
•
this report are on a single-well basis, these phases are •
sequential. For all regions except Alaska, production begins
in Year 1. For Alaska, production begins in Year 10 (see
Appendix B for more information on development schedules).
For multiple well projects, the impetus to begin production
is great and the production phase may overlap the development
phase. That is, petroleum production may begin while some
wells are still being drilled. The ERG model is capable of
modeling this situation (see Section H.2).
The project operates for 30 years or for as long as it is
profitable. Project economics are evaluated annually within
the model algorithms and the project is shut down at the first
negative cash flow.
H.I.2 Economic Overview of the Model
The economic character of the model phases is quite
different. Phases one through three generate cash outflows; no
revenues are earned during this period. The fourth phase,
production, generates net cash inflows. During this phase, the
project will continue to operate as long as operating cash
inflows exceed cash expenses.
H-2
-------
H.I.2.1 Cash Flows - categorization
The model deals with a number of basic cash flows (or
resource transfers). The basic cash flows are as follows:
Leasing Phase:
Exploration Phase:
Development Phase:
Lease bid - cost of acquiring
rights to explore and develop
a tract of land.
G & G costs - geological and
geophysical expenses incurred
prior to drilling.
Exploration well costs - cost
of drilling an exploration
well.
NSPS drilling costs -
additional cost of drilling
due to NSPS regulations on
muds and cuttings.
Infrastructure costs - cost
of installing petroleum
production equipment.
£
NSPS capital costs - costs of
additional equipment to
conform to NSPS produced
water regulations.
Revenues from oil and gas
production - production
levels multiplied by price
forecasts.
0 & M costs - cost of
operating and maintaining the
well.
NSPS operating costs - costs
of operating and maintaining
the pollution control system,
e.g., a reinjection well.
The basic cash flows, summarized above, are affected by a
f
number of factors that are depicted in Table H-l below. The
matrix in Table H-l can be illustrated by using the lease bid
Production Phase:
H-3
-------
I
DC
U
J
OQ
<
EH
CJ
CO
£
u
EH
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tH
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CJ
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CJ
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1
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f
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w
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z
CO U
04 04
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z w
o
Z CO
M W
EH CO
< Z
04 W
U 04
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o w
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CJ D
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04 EH 05
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EH CO
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04 04 CO
co <: o
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4-4- 4-
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O 03
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03 0 ?£ -r-l X
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H-4
-------
as an example. Initially, the lease bid generates a cash
outflow in the initial phase of the project. Two factors,
however, will allow a portion of that outflow to be recouped
during the production phase of the project. These factors, the
Federal tax rate and the depletion allowance for major
integrated producers, are denoted by plus signs in the table
because of their positive effect on the project cash flow.
(Major producers are allowed to amortize the leasehold cost
over the productive life of the well and use this allowance to
reduce taxable revenue. For a more detailed discussion of the
depletion allowance, see Section G.6.)
H.2 Step-By-Step Description of the Model
The ensuing discussion is a sequential overview of how the
code operates, it starts with the lease bid and ends with the
shut down of the well either after 30 years of production or
when the project becomes unprofitable'.* To illustrate the code,
the inputs, calculations, and outputs for a single-well project
in Alaska are simulated. Alaska was chosen because this region
has an extended development period; the calculations are
therefore more complex than for the other regions, where
production begins in Year 1.
The discussion is based on the computer printout that is
attached to this appendix, identification numbers for specific
lines are given in the left-hand margin. A list of user-
specified inputs is given in Table H-2. All dollar values
(e.g. costs and revenues) are expressed in thousands of 1985
dollars.
H-5
-------
TABLE H-2
EXOGENOUS VARIABLES PROVIDED TO ERG ECONOMIC MODEL
IDENTIFICATION
NUMBER
PARAMETER
1
2
4
5
8
9
10
11
12
14
25
26
27
28
29
35
44
45
46
50
51
52
53
54
55
56
57
58
59
60
61
62
Lease cost.
Geological and geophysical expense.
Real discount rate.
Years between lease sale and
exploration.
Percent of cost considered intangible
drilling costs.
Drilling mud increment.
Federal corporate tax rate.
State corporate tax rate.
Corporate structure (major or
independent).
Drilling cost per exploratory well.
Discovery efficiency.
Total infrastructure cost.
Years between exploration and
development.
Number of development wells drilled.
Number of development wells drilled per
year.
Drilling cost per development well.
Annual Pollution Control Capital Costs.
Production decline rate.
Cost escalator.
Royalty rate.
Depreciation schedule.
Severance tax rate - oil.
Severance tax rate - gas.
Years between development and
production.
Years at peak production.
Oil - peak production rate (bbl/day).
Gas - peak production rate (MMCF/day).
Number of producing wells.
Number of wells put in service per year
Wellhead price per barrel - oil.
Wellhead price per Mcf - gas.
Total operating costs.
Pollution control operating costs.
0256V
H-6
-------
H.2.1 Phase One - Leasing
The lease cost (line 1) is a user-specified input, the
value of which is based on 1985 lease sales in Alaska. See
Appendix C for regional lease costs and their derivation.
H.2.2 Phase TWO - Exploration
Line 2 represents the costs of geological and geophysical
(G&G) investigation of the site as a percentage of lease cost.
The value shown in line 2 is based on information in the API
cost survey for 1984 (see Section D.I). The total leasehold
cost (line 3) is the sum of the lease bid and G&G expenses.
The total leasehold cost is a cash outflow in Year 0 of the
project; the value on line 3 is therefore the present value of
the leasehold cost. The leasehold cost forms the basis for the
depletion allowance as calculated on a cost basis for major
integrated producers.
Line 4 is the real discount rate, i.e., the cost of
capital. This value will be used throughout the code to
discount future cash inflows, cash outflows, and production in
order to express them in present value terms.
Line 5 is the number of years between the lease bid and the
start of exploration. For Alaska, this is assumed to be two
years, while for other regions, exploration begins in the same
year as the lease sale (see Appendix B).
The petroleum industry has considerable latitude in its
treatment of costs. Unlike most other industries, an oil
company can expense, in the period incurred, costs that would
r*
normally be capitalized. The immediate expensing of a portion
of capital costs provides a significant tax advantage to an oil
company.
H-7
-------
Line 6 contains the percentage of drilling costs that are
considered "intangible Drilling Costs" (iDCs) and are therefore
eligible for expensing. The value of 60% is used in this
analysis and is based on annual surveys of expenditures (see
Section G.8). Under the Tax Reform Act of 1986, independents
may expense 100% of IDCs, while majors may expense only 70% of
the ^iDCs. Since the Alaska project is assumed to be a venture
by a*major company (see line 11), the value shown in line 7 is
42% (.60 x .70).
The additional costs due to NSPS regulations on drilling
muds and cuttings are entered in line 8 as a percentage of
drilling costs. Federal and state corporate income tax rates
are entered on lines 9 and 10, respectively. A flag for
corporate structure occurs on line 11.
The drilling cost for a well depends on the depth drilled,
environmental requirements, and regional costs for parts and
labor. The cost of drilling a well Has been summarized on a
regional basis in Section D.2, and is entered on line 12. The
discovery efficiency, the ratio of productive wells to all
wells drilled, also varies by region, depending upon the
predictability of the reservoir. Three-year regional averages
are used in this study (see line 14, Section D.3). A single
successful well is assumed in these projects (line 15).
Line 16 displays the exploratory well costs for the
project. The exploratory well cost is the sum of the cost of
drilling the well and the drilling mud cost increment divided
by the product of the discovery efficiency and the number of
successful wells. This cost is spread over the number of years
between the start of exploration and the start of development
(see line 26). For the Alaska project, the annual exploratory
f
well costs are:
H-8
-------
Annual /
Explora- = _ (well cost + drilling mud cost) _ / Years
tory Well (discovery efficiency * no. of successes!/ of
/ Development
(3,207 + 0) - $911
(.88 * 1.0)
Four years for exploration are scheduled for an Alaskan project
(line 26).
The annual cost of successful efforts (line 17) is the
product of the annual exploratory well cost and the discovery
efficiency:
Annual cost of = Annual Total Well cost *
Successful Efforts Discovery Efficiency
= ($911 * .88) = $802
Annual expensed costs (line 18) i« the sum of two factors:
H^»«^^^^BHM^^^W 4-
(1) the product of the annual cost of successful efforts times
the percent costs expensed (line 7) and (2) dry hole expenses:
Annual Expensed = (cost of successful efforts x % expensed)
Costs + (exploratory costs x (1-disc. eff.)
= ($802 * .70) + ($911 * .12)
= $446
In other words, the annual expensed cost is the sum of
unsuccessful efforts and the expensable portion of intangible
drilling costs for successful wells.
The expensed cost is $446/yr for each year of exploration.
The actfial cash outflow, however, is dependent upon the
coprorate tax rate. The expenses reduce the tax bill for a
profitable corporation. The calculations to determine the
H-9
-------
actual cash outflow, shown below, assume a marginal corporate
tax rate of 34 percent (see line 19).
Expensed Cash Flows = (1 - tax rate) * Expensed costs
» (1 - .34) * $446 = $294
Capitalized cash flows, line 20, are the exploration costs
fh.
that'are not expensed. The proportion of drilling efforts that
may be expensed depends upon whether the corporation is a major
or independent producer. For the Alaska project, a major
producer is assumed. Under the Tax Reform Act of 1986, a major
may expense 70 percent of the intangible drilling costs and the
IDCs are estimated to be 60 percent of the drilling costs (see
lines 6 and 7). For a major, then, 1 - (.6 x. 7) or 58 percent
of the successful drilling costs are captalized:
Capitalized Cash Flows = 0'.58 * Cost of Successful Effort
(line 17)
= 0.58 * $802 = $465
£
Since capitalized costs generate no tax shield in the year
incurred, the capitalized cash flow is equal to the capitalized
cost.
Once the various exploration costs and cash flows have been
calculated, they are put in present value terms as of the lease
year. For all other regional onshore projects, exploration
costs are incurred in Year 0, the year the lease was obtained.
For these projects, the present value of all exploration costs
are the same as the value for year 0. For Alaska, however,
exploration does not begin until Year 2 and continues through
Year 5. These values must be adjusted by the time value of
money, i.e., the discount rate. For Alaska, exploration costs
are discounted as follows:
«•*
Present Value = cost in Year 2 / 1.082
+ cost in Year 3 / 1.083
+ cost in Year 4 / 1.084
+ cost in Year 5 / 1.085
H-10
-------
Present values are calculated for expensed exploration cash
flows, capitalized exploration cash flows, and all exploratory
costs (lines 21, 22, and 24). The sum of all capitalized
exploration cash flows is given in line 23.
1;J.2.3 Phase Three - Development
The costs of production equipment and other infrastructure
costs are entered in line 25. For Alaska, there are four years
between the start of development and the start of production,
(see line 53). costs of construction are allocated over the
first three years of construction (see line 34).
The development phase in the code is structured to
accommodate the drilling of development wells after a reservoir
has been determined. Separate entries for the total number of
wells in the project, the number of wells drilled each year,
and the drilling cost per well appear in lines 27 through 29,
respectively.
Lines 30 through 35 calculate the costs incurred each year
from the drilling of development wells, and the construction of
production and pollution control facilities. The total annual
capital development costs are given in line 36.
The tax shield, line 37, is the product of the annual total
capital development costs, the corporate tax rate, and the
percent of costs expensed. For Alaska, this is $15,333 x 0.34
x .42 or $2,190. The expensed cash flow, line 38, is the total
annual capital development costs (line 36) times the percentage
of costs expensed (line 7) minus the tax shield (line 37). For
Alaska, this is ($15,333 x .42) - $2,190 or $4,250. The
capitalized cash flow, line 39, is the product of total capital
costs and (1 - tax rate), that is, $15,333 x .58 or $8,893.
H-ll
-------
Note that the sum of the tax shield, the expensed costs and
capitalized costs is equal to the total costs.
As with the exploration costs, development costs are
discounted to determine their present value in the lease year,
Present values of all development costs, expensed development
costs and capitalized development costs are given in lines 40
through 42, respectively.
H.2.4 Phase Four - Production
In the production phase of the project, a variety of
financial and engineering variables interact to form the
economic history of the well. Line 44 provides the production
decline rate for oil and gas. The ERG model incorporates an
exponential function for production decline, i.e., a constant
proportion of the remaining reserves is produced each year.
For every barrel produced in the initial year of operation in
2
Alaska, 0.87 barrel is produced in the second year, 0.87 or
0.76 barrel in the third year, and so forth.
The ERG model is capable of handling cost escalation (see
line 45). In this report, we are considering costs in real
terms, and thus no escalation is assumed.
The royalty rate paid to the lessor of the land is provided
in line 46. The depreciation schedule is listed in lines 49
and 50. State severance taxes on oil and gas are given in
lines 51 and 52, respectively. Note the flag for calculating
severance taxes for Alaska since these must be adjusted by the
Economic Limit Factor (ELF).
From a review of well production data, a single well
typically produces at its peak rate for one year only (line
H-12
-------
54). A field, in contrast, may produce at its peak rate for
several years due to wells continually coming into service.
The peak production rates per well for oil and gas are given in
lines 55 and 56, respectively. Note that these are figures for
daily production and that the units for gas production are
MMcf/day.
'»
Since not all wells are turned into producing wells (e.g.,
exploratory wells in offshore operations or reinjection wells),
lines 57 and 58 specify the number of producing wells and the
rate at which they enter production.
The wellhead prices for oil and gas are entered on lines 59
and 60. Annual operating costs are entered on line 61, while
line 62 contains the additional costs of operation due to
compliance with pollution control regulations.
Line 63 provides the number of producing wells in service
and is calculated from the total number of producing wells and
the number of wells that go into service per year. The barrels
of oil produced per day (line 64) is straightforward in the
single well case:
Daily Production = f of Barrels/day * # of wells
* decline rateyear of production-1
= 3700 * 1 * 0.871 = 3219
for the second year of production. The ERG code is capable of
calculating production when wells go into service in different
years.
The annual oil production is calculated as 365 times the
daily production (line 66). The price per barrel is repeated
in line 67 for convenience in cross-checking the gross revenues
for oil production (line 71). Lines 68, 69 and 70 list the
H-13
-------
^r ^^
daily gas production, annual gas production, and wellhead price
per Mcf.
H.2.4.1 Income Statement
iines 71 through 94 comprise an income statement that is
repeated annually for a thirty-year project lifetime. Since
most projects become uneconomical before this, lines 95 through
102 check for a negative net cash flow and readjust the actual
production, revenues and cash flows to zero when appropriate.
Lines 71 and 72 list the revenues from oil and gas
production. Total cash inflow for the year is given in line
73. Royalty payments and severance taxes are calculated on the
basis of gross revenues (lines 74 through 77, see line 4£ for
the royalty rate and lines 51 and 52 for severance tax rates).
The economic limit factor (ELF) for the calculation of
severances taxes for Alaska is given rn lines 78 and 79 (see
Section G.3 for a more complete discussion of severance tax
calculations for Alaska). Net revenues, line 80, are
calculated as:
Net revenues = Total Gross revenues - royalty payments
- severance taxes
= $23,117 - $3,279 - $26 - $2809 - $0
= $17,002
Operating costs are given in line 81; additional operating
costs due to pollution control appear in line 82. The entry on
line 84 is the sum of the capitalized costs spent in the
development and production phases:
**
Capitalized costs = Capitalized Costs in the Exploration Phase
+ Capitalized Costs in the Development Phase
= $1,860 + $8,893 + $8,893 + $8,893 = $28,539
(line 23) + (entries on line 39)
H-14
-------
The depreciation allowance is listed in line 85. In the
sample project, capitalized costs are all allocated to the
first year of production (line 84). The depreciation schedule
under the Tax Reform Act of 1986 is found on line 50. The
values for line 85 is the product of $28/539 and the
depreciation rate for the appropriate year, e.g. $28,539 x
8.93^% = $2,549 for Year 14 of the project.
»
The operating earnings (line 86) are defined as net
revenues (line 80) minus operating costs (line 81) minus
poolution control operating costs (line 83). For Year 12 of
the project:
Operating Earnings = Net revenues - operating costs
- pollution control operating costs
= $12,869 - $691 - $0 = $12,178
Line 87, earnings before interest and ODA (oil depletion
allowance), subtracts depreciation and amortization from
£
operating earnings. For Year 12,
Earnings Before = $12,178 - $4,992 = $ 7,186
Interest and ODA
For major integrated producers, the depletion allowance
(line 88) is calculated on a cost basis, that is, the leasehold
cost is amortized over the productive life of the well:
Depletion Leasehold Depletion "Year X" Revenues
Allowance = Cost - Allowance x (line 72)
in "Year X" Taken Total Revenues
(line 88) (line 3) (line 88) after "Year X"
for Year 12, the depletion allowance for the Alaska project is:
= ($182 - ($24 - $21)) x ($17,497 /$133,172)
= $18
H-15
-------
Independent producers use a percentage depletion allowance; see
Section G.ll for a more complete description, if the project
ends while a depletion allowance may still be taken, the
depletion allowance in that year and subsequent years is termed
"surplus depletion" (line 89).
Earnings before interest and taxes (line 90) is defined as
the earnings before interest and ODA (line 87) minus the oil
depletion allowance. For year 12 of the Alaska project,
earnings before interest and taxes are $7,186 - $18 = $7,168.
The earnings in line 90 form the basis for both Federal and
State income taxes. These are calculated in lines 91 and 92 on
the basis of information in line 9 (Federal tax rate) and line
10 (State tax rate). Earnings after taxes are given in line 93.
The project cash flows, line 94, are determined by adding
non-cash expenses, depreciation and depletion, to earnings
after taxes. The net cash flow for Year 12 is $4,057 + $4,992
+ 18 = $9,067.
The cash flows forecasted for the project may or may not be
sufficient to justify continuation of operations. If net cash
flow is positive, the model allows for continued operations,
even if earnings before interest and taxes is negative, if
cash flow is negative, the operation is shutdown. The model
prints a "1" in line 94a for years in which the project
operates and a "0" for years in which the project does not
operate.
In the event that the project is shut down, certain
variables must be recalculated to reflect that decision. Lines
95 through 100 restate production volumes, revenues, and cash
flow in light of the shutdown. That is/ prpduction and
revenues are set to zero after the project shuts down. Other
project variables, such as depreciation, are recalculated
H-16
-------
because of the earlier shutdown date. Unexpended capitalized
costs and surplus depreciation are given in lines 101 and 102.
The income statement for the second and third decades of
operation is found on lines 103 through 140 and 141 through
176, respectively.
H.2.5 Summary Statistics
At the end of the project, all costs and revenues are put
in present value terms as of the lease year; see lines 177
through 192. Two terms have not been discussed previously.
Line 180, expensed investment cash flows, is defined as the sum
of the present values for expensed exploration cash flows (line
21) and expensed development costs (line 41) minus the present
value of unexpended expensed investment costs. For the Alaska
project, this is $903 + $7,455 - $0 = $8,358. Line 181,
capitalized costs, is the sum of the present values of
capitalized exploration costs (line 22) and capitalized
development costs (line 42) minus the present value of
unexpended capital costs. For the Alaska project, this is
$1,426 + $15,598 - $0 = $17,024.
The present value of total company costs is the summation
of the present values of the parameters listed in Table H-3,
see line 190. This parameter provides a measure of the present
value of net company resources expended in development and
operation of petroleum projects. Entries marked with a "plus"
in the column contribute to corporate costs. Excess
depreciation and surplus depletion lower corporate costs and
are therefore marked with a "minus".
Total company costs for oil are the present values for oil
royalties and severance taxes and the oil portion of the
remaining costs, see lines 191 and 192. These costs are
H-17
-------
apportioned by the ratio of oil revenues to total revenues. An
analogous procedure is followed to obtain the total company
cost for gas.
Oil and gas production is also discounted to give present
value equivalents; see lines 198 through 200. Corporate costs
per^barrel and corporate costs per Mcf are obtained by dividing
*
the present value of the company cost by the present value
equivalent of production (see lines 193 through 195).
The present value of social costs (lines 205, 207 and 209)
provides a measure of the value of net social resources
expended in the development and operation of onshore petroleum
projects. The difference between company cost and social cost
is that the social cost ignores the effects of transfers that
do not use social resources. The items included in social cost
are listed in Table H-3. Social cost per unit of production is
obtained by dividing the social cost by the present value
equivalent of production, lines 206/208 and 210.
The net present value of the project, line 201, is
calculated as:
Net Present = PV of Cash - PV of Cash
Value Inflows Outflows
= PV of Operating Cash Flows
- PV of Expensed Investment Cash Flows
- PV of Capitalized Costs
- PV of Leasehold Costs
+ PV of Excess Depletion
+ PV of Surplus Depreciation
A positive net present value is indicative of a profitable
project at the assumed discount rate, i.e., it generates more
revenue than investing the capital in a project with that
r
expected rate of return.
H-18
-------
n
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pa
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H-19
-------
The internal rate of return, line 202, is the rate of
return which equates the present value of capital in the
exploration and development of the project with the present
value of the operating cash flows. An internal rate of return
higher than the discount rate is indicative of a profitable
project. The probable ROR, line 203, is an estimate used to
start the iterative process of calculating the internal rate of
>
retflrn in LOTUS 123.
The net present value and the internal rate of return are
inverse methods of evaluating the profitability of a project.
In calculating the net present value/ the discount rate is
fixed and the net present value may vary. In calculating the
internal rate of return, the net present value is set to zero
and the discount rate is allowed the fluctuate.
027,5V
H-20
-------
ft!". Date:
Project Type;
^^sass Cost:
C-JC- £ perse:
Leasehold Cost:
Seal Discount fate:
Tea's Between Lease Sals
ard Star: of Explor,:
:ercent Costs Considered IDC s:
Percent Costs Exijensed:
Drilling flu a Cost Increment;
Corporate Ta* Pate:
State Corporate Ta?; Pate:
Ccrp Structure 'l-«ajar'2-indep/:
lost Per Exploratory rfell;
Drilling HuO Cost Incresent:
Discovery Efficiency:
Successful E-pl. Jteilt
^^Explor. Costs cer Project:
^^ost of Successful Efforts:
E",pensed Costs:
Expense: Cas* :'. o*=:
:apitah:erf Casn ^s:
29-Apr-37
Region 11 - single oil *eii
*lil
12.604
$181
^ i '•.' V 4
fc
sO.OO'i
42.00X
0.007.
347.
9.407.
1
EXPLORATION COSTS
$3,207
$0
0.38
t
Vear rear 'ear 'ear
$91! $Qi: $91! $911 ' '
$802 $802 $802 $802
fiif- $446 $446 f44t
$1*4 $254 *2;4 $234
$465 $465 $4oo 1465
"v :*' Expe'sea Exploration Casi Plows: $903
C'V o* Capitalized E^pl. 'Iash Pious
Total Iapitah:sl E'fpl. Costs:
:'V o» ail E' ploratory Costs:
T::a: Infrastructure Cost;
raar= %^^a- ;»?rt of E-ploration
j'j Start o* De'-elopient:
'<. "be- ;»" neli: D'llied:
'^•?:s- *ell= Drilled Per Year:
1'illng Cost Per «eii:
Drilling Cost <:'er well:
^^Lnlhng «u* I:st here-sent:
^B'-.Ke- of Kslis D-i". lei:
Total Drilling Costs '*or vear;
nrpua In^rastrijctu1"? Cost:
: $1,426
$l,caO
$2,794
DEVELDP«ENT CCS'3
$45,998
4
0
0
$0
Vear fear 'ear r?ar 'ear ''ear 'ear "°ar ?ear
a 7 S 9 JO 1! 12 13
$0 $0 ?0 $0 $0 $0 $0 10
$0 $0 JO JO $0 $0 $0 $0
0 0 '; 0 '.' 0 '.' 0
rO $0 $' $0 $0 $0 JO $0
-Mo,"' $'C,"T $;5,''' JO JO $0 $0 J1'1
v: $y J' $0 $M $0 $0 $0
Line
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
21
28
29
.5;r
;i .:
iij i
$1.' J
='" -'.
f ' *
r . r
H-21
-------
:ta: ^nr-iai Capital lest: 115,333 $15,333 112,3.3
TJV E^iei_: 12,190 12,1=0 12,1=0
F:3*: t4,250 14,250 14,250
n tests: $2M-;
Fy o* E':e"S5C i'evB:cp?9"t Costs: 17,435
PV c; Capital::3;; Crev3lcptept 2:it=: $15,358
:srcent hatsr Cut in 05-5 to Start: II
Oil 2as Prod. Dschi-e Rate.'Vear (?/ 87'/.
Lost Escalator i^,1: 'jj
Faviity Pate iZi: 14.30?
r2derai Tav Rate iXi: 34X
State ^x Rate (?): "X
Average Depreciation Li*e t'years): 1
Dep'ec. '•ate (eacf. year): 14.292
State Severance Tax Rate-Oil: 9900.002
'If Alaska enter 59;
State Severance Tax Rate-Sas: 9900.002
(It Alaska enter ;9!
PRODUCTION DJ5TS
'sa,rc Between Start ot Deveiipsent
aM Etart ct :':ai:ctio" io': 4
N'^oer :f -ears at neac P'od: 1
Gil :ea< =ras. Rate/Hell(Sdi: 3700
Sa= °eai Frod, Sate/heil iftNCF/Dl: 0.686
S'L;T.:er at producing sells: 1
Juicer of rfeils Put in Service/Year 1
:'i:e ct Oil ?er Barrel: tlfc.98
Frice of Sas ?er MCF: 10.74
Tstai Operating Costs ''$000): $691
Fell Cant Dper Costs tlOOO): *0
Davs cf P'cductiar. Per rear: 365
$'!'
10
10
10
$0
$0
*0
tc
10
to
10
$0
to
$0
$0
$0
iO
fn
$0
10
Year Year 'ear •ear fear f"ear fear
10 11 12 13 14 15 lo
Ok PRODUCTION
F'cd'jciig «ieiis in Service; 1 0 •'• J 0
rarre'.i :f Oil =gr Day: ^ 3"00 32l? 2:01 2*36 2120 1844 1604 I3fl6 ;Z:4
Davs c' Croduct:cr Fer 'ear: 365 3o5 3b5 365 3s5 365 365 365 3:3
&a^rei5 cf Gil =er 'ear; 1350500 1174935 10221-3 855306 T73o98 673117 585612 50C463 4-32:0
•:ceftarrei of Jil: $lc,°8 $16.98 $b,93 $lfi.9S $16.95 $16.98 $16.;3 $b.55 lls.'S
H-22
-------
1HCF ?* ta= p?r Da1;;
MHCF s» Gas c'sr Snort i ration ifOOO):
Operating Earnings i$000'':
Earnirgs Before interest and 9DA:
Depletion Allowance:
Surplus Depletion
Earnings Before Interest ana Ta.# 'I:*:
E-jtc*^
Actual 2'ii Grna, ''ear 'rar'eii»;
Actual Er;ss •'eve^'^es (4000!:
A:tuai "Jet 'eve-ues '4000!:
Actual Net 2asT '•'low >$000':
^ctuai Ta' es c;:d 4000; :
Ca::t3li:?d Costs Not Expended:
'-"'-- :'5F^c:ation:
rar-Els Ci! ;2r ;2V.
2a,(S of Pr:oL:t:on -er 'ear:
Earrelr 2:1 :?r '=2-:
Crice -"er rarre. :
«vrr ,3,- pe, r,a,.
!"•;" Ga; PP- rer;
t
250
$0.74
$135
i23, IT
13,275
$24
$2,605
$0
1 , 00
-3.37
$17,002
$691
$0
$0
$26,539
$4,078
41s, 311
$12,233
$24
$0
$12,209
$4,151
$1,146
$6,910
411.,'K
j
1350500
$23,117
417,002
$11,012
45,299
$0
$0
Year
20
uL , "uLa
OjQ
365
335494
$i;,56
S^>- Hh ' )"" ' (l
I)
s2
1
213
$i'l "i
$15,950
flfll
$20,112
$2,853
$23
$2,444
iO
1 . 00
-4.03
$14,7??
$691
$0
$0
40
$t,939
$14,101
$7,112
$21
$0
$7,091
$2,41!
$&o7
f4,013
$!1,J23
i
1174535
•5 j ;
$20,112
$!4,7«2
$11,023
$3,077
$0
f '
Year
-•
uN
?00
363
2918S1
$10.^6
1 1*.
.•,
54
,
1 = 0
$). "4
$17,357
4140
fi:,4v;
$2,i£2
$20
$2,12t
$0
i , 00
-4.78
$12,569
$691
$0
$0
$0
$4,952
$12,178
$7,136
$13
$0
$7,163
$2,43?
167*
$4,057
t C "j j. 1*
!
1022193
4r,45-
412,36"
$5,:i67
$3,111
i u
-r''
•?3-
--
;-;
JUJ
253337
$U,-c
17
$
$15
$15
12
$1
-
$11
$3
$10
$6
$t
$2
J3
$7
68
$15
411
$7
$3
•ea-
__
11
\)
li:
5.74
,100
$122
IT1
I1-"-
,159
$17
, 550
$0
1,00
5.64
,196
$691
$0
$0
$0
,565
,505
,^40
$li
40
,525
,354
$651
,915
,500
1
5303
1 ic
16 J
,222
,1-t,
,500
,005
40
$0
-;
tO:
3i3
.'925
0.-6
,;,
4l
u
143
$0,74
$13,137
$106
$13,244
11,879
$15
4l,o09
$0
1 , 00
-6.63
$5,740
$691
$0
$0
$0
$2,549
$°,049
46,501
$14
40
46^487
$2,206
$o!0
$3,672
$c.,234
-,
773c58
143
$13,244
$9,740
*s,234
$2,315
$0
$0
vear
24
527
3t5
:32205
fio, 53
o
36
T
$11
111
$1
$1
-
$8
$2
$7
$5
15
$1
$2
$5
o7
$1!
$8
$5
$2
v°ar
It
f!
125
'i.74
,430
$92
,322
,634
413
, 400
$0
i . 00
7.77
,474
$691
$0
$0
$0
,546
,783
,238
$12
$0
,226
,777
$491
,556
,515
i
3117
1 Ji«.
,474
,515
,268
JO
$0
25
456
365
7216
o.9S
< i
. i
•"'
105
40.74
$9,544
$60
*1 0,024
$1,422
$11
$1,215
$0
i , 00
-9.09
$7,373
$691
$0
fO
$0
$2,549
f6,c32
$4,133
$10
40
$4,123
$1,402
»TwC
} JLrU
$2,333
$4,352
1
i
5S5sl2
i i" 0
I1.'
$10,024
$7,373
$4,552
$1,755
10
$v
-ear
26
3?5
3t>5
; 45430
416, =3
r,
^_
54
$0.74
$•6,65:
$70
$3,721
$1,237
410
$731
$0
O.fi5
-10.59
$6,743
$651
$0
$0
$0
$1,273
It, 052
t4.775
J5
$0
*4,7-0
$i,s22
$445
$2,700
*-'*3-
505463
0/1
** ^
$8,72i
46,743
$3,562
42.07':
t"
r ,
Vear
*
-47
365
;2o5t"
$10.55
23
t i.
iO.'i *'\"4
$7,32o ii.fJS
$il $33
$7,33^ fi,:vl
$l,0;t $:3:
$5 IE
$5C7 $43
$0 -r
O.c5 ),:
~ 1 ^ j ^ i. ~ . ^ t . *.
i;, 50: f5,:7:
4fi5l ;:,-;
fi'j iO
$0 $0
$C $0
$0 $0
$5,215 IVr!
$5,315 $i,«5:
$E J'
$0 $•'
J:,2:7 $J «7=
$1,".' sl.323
-:4r; :;;.
42, ;4- r :3:
»., .-
4<:23: :E;:2-
r,:r £:,:.;
45,503 -r:..";
$2.:3: -'2,:t:
^~ ~^''' £ -„_
-
-?ar ;=-
.:
2.2 2:2
~ t - " . r
.::.:- :3~:c
f.t.-t -'.:--:
2 .:
H-23
-------
$0,74
*M 7i
$0.74 fO."4 JC',74
$o.74
Reverses ''$000;:
sas levs'iies 'fOOO):
''oyait,- Cavierts-Gas 'too-''1:
Es''9r3rce "axes-Gas ^OoO1:
t'J + cr Alaska Eeve'a^ce "axes-I'ii
EL" tor Alaska Severance Ta>es-Gas
es'$000h
Operating Costs;
E1 sensed co:l.Cont.Cap,Costs iiOOO
foliation Control Operating Costs:
For :v coll, Control:
Depreciation 4 Ascrtuaticn:
Cperatng Earnngs '1000;;
Earnings Before Interest and OCA:
Decletuc ^11 chance;
Ejrpius Depletion:
Earnings Before Interest and Taies
Feaerai Tax:
State '*'•:
rings Sejf3re Interest After Ta,x
P«et Cas", Flow;
Actjai Oil crori,-:c^:::o- "er vear;
*-
el= I-ii ;er "ear:
$5,697 $4
14C
$5,743 $4
$5! 5
r
*351
$0
: 0.55
: -is.iO -1
J4,54i $7
1691
$0
$0
$0
$0
$3,350 $3
$7,850 $3
$0
$0
; $3,844 13
$1,307 $1
$3tl
: $2,176 $1
$2,162 $1
33549s 29
62
$5,743 $4
$4,541 $3
$2,132 $1
$1,668 $1
$(..
$0
Year Year
30
OIL PRODUCTION
229
3s5
23:45 "
$16.93 $1
3A5 PWJCTION
•,'5:
$40
•,996
$70;
$6
$255
*!.>
0.49
9,27
,°56
$691
$0
$0
$0
$0
,296
,296
$5
$0
,2'0
,119
$309
,862
"68
,
1651
54
,996
,996
,5cB
,42t
$0
$0
3i
IPS
365
25 1J
6.98
$4.312
$35
$4,747
$iT
J-
$222
$0
0.42
-22.2s
13,503
$691
fu
$0
!'.'
$0
$2,312
$2,312
$5
$0
$2,50'
$954
f264
$1,589
t i HC7
i
253577
47
$4,347
$7,507
11,597
$1,216
$0
*i
Y a j<~
--
177
7:5
53054
$16,53
J3,75i
$30
?7,782
1536
$4
Hoi
$0
,'.35
-~c 7T
13,030
$651
$0
$0
$0
$0
$2,339
$2,389
$4
$0
$2,355
$511
1224
$1,350
$2,754
220925
41
$3,752
$3,080
$1,354
$1, 035
$0
In
'-*¥
:'~
150
3a5
54883
$lo.9S
17,264
$26
$7,290
J4&7
$4
$110
$0
0.27
-29. 77
$2,710
$691
$0
10
JO
$0
$2,019
$2,019
$7
10
12,015
$635
$)69
$l,'l
i.'
$522
$524
n:n4
- •,
11,565
$i,:l5
J524
$40''
JO
-"'.'
'33'
~" 3
-*
7t:
i. ' _ uZ
H*.^
i;,:27
J17
*;,;.•»'.'
1277
r
*c
$0
1 ' , ; ' ,'
-;0.i5
$:,4:5
*:=!
iC
• j
$0
$"14
$714
$2
$0
$713
$242
i;"
£470
-*".
~~~z±
.E
'-'.,.•*':
$.,-.;
$4"2
i _ ;w
* '
*•'
.^
'-
-r
1 1
---;;
-r.r,:f
ir 5a5 ^er Day:
l"1!3 Gas ;er 'ear;
rice :9r !^'If;
$0.74
$0."4 $0,74
H-24
-------
Oil ^'EVePjES '2\'V{.' !
kac. h?vsr'je: itOt'O'1!
Ctal h'E',9r'J95 '$000'!
frc-altv ^vner.ts-Oii '$0005;
loyalty Favse-ts-Sas '$< 00- ;
Eevsran:= T^-es-jn lyi C':
Se'-erarce Ta'es-I-as 'lO'Oi;
ELC for Alaska Seve-afiCE Taxes-Oil;
ELF for Alaska Severance Ta;'es-3as;
Net Revenues i $000);
Operating Costs;
Fellatio^ Control Operating Ccsts;
For F'V Poll. Control:
Depreciation i A§arti:aticn:
Operating Earnings '$000'':
Earnings Before Interest anc uDA:
Depletion Aiionaice;
Surplus Depletion
Earnings Before interest and Taxes;
Federal Tax:
State Tai:
Earnings before I":erest A'tsr Tax:
Net Cash '•'.GUI
Actual Oil Prcd, »ear 'Barrels! ;
Actual 3as Prca, 'ear 'HHCF;:
Actual 3r;5E s5V8"ues 'JOOO1:
Actual Net :e'.-9nues '$000':
Act^a] Net Casn Fi:» ($000);
Actual Ta^es Fait! -$000i ;
$1,415
$11
$1,427
$202
$2
$v
$0
0,00
-69,86
$1,223
$691
$0
$0
$532
t532
$1
$0
$530
$180
$50
$300
I"!"!1"'
,
93345
15
$1,427
$1,223
$302
$230
$1,231
$10
$!,24;
S'l't
$1
$0
JO
0 . u u
-50.45
11,064
to'!
$0
$0
$373
1373
$1
$0
$371
H26
$:s
$21;
$212
i
72510
13
$1,241
Il,0i4
$212
$16:
$:,/7i
$3
$1,05'.-
H53
$1
i(i
$0
0,00
-C2,s2
J'25
$691
$0
$0
$235
$235
$1
$0
$2:3
$''
$22
$132
$133
53034
i j_
$1,080
$Q25
$133
JlOl
$732
IB
i535
i 1 "'T
11
$0
$0
'.'.UV
-106,61
1805
$69!
$0
$0
$114
$114
11
$0
i!13
$38
11:
$o4
$65
1
54883
10
$93^
$305
$s5
$49
$511
17
*sr
$iif
ti
$0
$0
0.00
-122.69
$700
$69f
JO
$0
$10
$10
$1
$0
$9
$3
$1
$5
$6
1
47743
9
$817
$700
$6
$4
$705
$6
$711
$101
$1
$0
$0
0.00
-141.17
$c09
$691
10
$0
:$82)
($82)
$1
$1
($52)
($28)
(18)
'$47!
'$46)
0
0
0
$0
$0
$0
$0
$6 14
$5
$01'
$SB
$1
$0
$0
0.00
-162.42
15^0
$691
$0
$0
($161)
•$161;
$1
$1
I$161)
i$55;
($15)
'$91!
i$91i
i)
0
0
$0
$'"'
$0
$0
$51*
i4
$538
$76
$1
$0
$0
0,00
-156.84
1461
$691
$0
$0
!$230i
1*230)
$1
$1
!$230!
'$78i
($22)
'H30i
!$13t'"
A
0
(J
JO
$0
$0
£'.'
Jita
54
$4t:
$sc
$1
$•
$i
0/0 '
-21*. 'i
$401
$5=1
$)
$0
l$290;
il2'0)
$!'l
$0
1 $290 '
'J9';
'$27i
'$164'
I1 -d '
V
•j
!'
Ii
fi
1'
i •* '4
s:
Siii-1
$55
$0
$v
JO
0 . 0 0
-247,;6
$14°
^1
$0
f'~:
•*342/
'$342''
$0
$0
!$342-'
(Ills'
i$32'
•I22si
'ill!'
f '"'
:
r ~,
i 'J
H-25
-------
of Net Casl "lows: IZc,GZc
of_E'
-------
APPENDIX I
OIL AND GAS PROJECT
BASELINE CASES
1.
2.^
*
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
Region
2
2
4
4
4
4
5
5
6
6
7
7
7
7
8
8
9
9
10
10
11
Oil
Oil
Oil
Oil
Gas
Gas
Oil
Oil
Oil
Oil
Oil
Oil
Gas
Gas
Oil
Oil
Oil
Oil
Oil
Oil
Oil
and gas
and gas
and gas
and gas
only
only
and gas
and gas
and gas
and gas
and gas
and gas
only
only '
and gas
and gas
and gas
and gas
only
only
and gas
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
Independent
Major
-------
Run Date: 29-Apr-87
Project Type: Region 2 - single oil well
ease Cost: $1
GiS Expense: 58.30X
Leasehold Cost: $2
Real Discount Rate: 8.00/1
Years Between Lease Sale
and Start of Exp^or,: 0
Percent Costs Considered IDC's: 60.OCX
Percent Costs Expensed: 42.00?
Drilling Mud Cost Increient: O.OOX
Corporate Tax Rate: 342
State Corporate Tax Rate: 7.251
Corp Structure U-iajor/2-indep): I
EXPLORATION COSTS
Cost Per Exploratory Hell: $64
Drilling Mud Cost Increment: $0
Discovery Efficiency: 0.8
Successful Expl. Hell: 1
'/ear Year Year Year
0123
Jxplor. Costs Per Project: $80 $0 $0 $0
Jost of Successful Efforts: $64 $0 $0 $0
'Expensed Costs: $43 $0 $0 $0
Expensed Cash Flows: $28 $0 $0 $0
Capitalized Cash Flows: $37 $0 $0 $0
FV at Expensed Exploration Cash Flows: $28
PV of Capitalized Expl. Cash Flows: $37
Total Capitalized Expl. Costs: $37
PV of all Exploratory Costs: $80
DEVELOPMENT COSTS
Total Infrastructure Cost: $45
'Hears Between Start of Exploration
and Start of Development: 0
Nuider of Hells Drilled: 0
Nutber Hells Drilled Per Year: 0
Drilling Cost Per Well: $0
Drilling Cost Per Hell:
Drilling Mud Cost Increient:
)Nuaber of Hells Drilled:
Total Drilling Costs,for /ear:
Annual Infrastructure Cost:
Annual Poll Cont Capital Costs:
/ear
Year
0
$0
$0
0
$0
$45
$0
Year
1
$0
$0
0
$0
$0
$0
/ear
L.
$0
$0
{)
$0
$0
$0
Year
3
$0
$0
0
$0
$0
10
Year
4
$0
$0
0
$0
$0
$0
Year
5
$0
$0
0
$0
$0
$0
Year
6
$0
$0
0
$0
$0
$0
rear
7
$0
$0
o
$0
$0
$0
• ear
S :
$" *:
$0 Iv
u
tit i.'
$o *<:
$,i SO
-------
Total Annual Capital Cost: $45 $0 $0 $0 $0 $0 $0 $0 $0 $0
Tax Shield: $6 $0 $0 $0 $0 *0 $0 10 $0 $0
pensed Cash Flow: $12 $0 $0 $0 $0 10 $0 $0 $0 JO
pitahzed Cash Flow: $26 $0 $0 $0 $0 $0 $0 *0 $0 $0
PV of Ail Developsent Costs: $45
PV of Expensed Developient Costs? $12
PV of Capitalized Deveicpsent Costs: $26
•^
*
FINANCIAL RATES
Percent Mater Cut in 046 to Start: 21
Oil/6as Prod. Decline Rate/Year (Ti 91Z
Cost Escalator (II: 01
Royalty Rate (I): 18.75X
Federal Tax Rate (Z): J4Z
State Tax Rate (I): 11
Average Depreciation Life (years): 7
Deprec. rate (each year!: 14.29X 24.49X 17.49X 12.49Z 8.937. 8.92X 8.937. 4.46X
State Severance Tax Rate-Oil: 4.50Z
(If Alaska enter 99!
State Severance Tax Rate-Sas: O.OOZ
(If Alaska enter 99)
PRODUCTION COSTS
'/ears Between Start of Developnent
and Start of Production (-5!: 1
N'uifaer of fears at Peat Prod: 1
Oil Pear Prod. Rate/Well (fab!: 3
Gas PeaJ Prod. Rate/Well (MCF/D): 0.016
Number of Producing Weils: 1
Nuiiber of Hells Put in Service/Year 1
Price of Oil Per Barrel: $25.20
Price of Sas Per MCF: $3.05
Total Operating Costs ($000): $4
Poll Cont Oper Costs ($000): $0
Days of Production Per Year: 365
Producing Hells in Service:
Barrels of Oil Per flay: •"
Cays of Production Per Year:
Barrels of Oil Per Year:
Pnce''Barrel of Oil:
Year Year
1
OIL PRODUCTION
1
3
365
1095
$25,20 $2
2
0
3
365
v96
5.20
Year
T
J
o
•}
365
907
$25.20
rear
4
0
n
L
365
625
$25.20
Year
5
0
*>
4.
365
751
$25.20
Year
6
n
L
365
683
$25.20
Year
7
n
L
365
622
$25.20
Year
8
2
365
566
$25.20
fear
Q
1
365
515
$25.20
'ear
10
i
To 5
i^
$:s.:o
SAS PRODUCTION
-------
MHCF of Gas Per Dav;
MMCF af Gas Per ^ear:
rice/HCF of 6as:
Annual Oil Revenues ($000):
Annual Gas Revenues !$000i:
Total Revenues i$000):
Royalty Paynents-Oil ($000):
Royalty Faysents-Sas ($000);
Severance Taxes-Oil 1*000):
Severance Taxes-6as ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Sas:
Net Revenues ($000):
Total Operating Costs ($000):
Expensed Pell.Cont.Cap.Costs ($000)
Poll.Con.Operating Costs ($000):
Capitalized Costs ($000):
Depreciation 4 Amortization ($000):
Operating Earnings !$000):
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
.Federal Tax:
State Tax:
Earnings Before Interest After Tax:
Net Cash Flow:
Snutoff
Actual Oil Prod./Year (Barrels):
Actual Sas Prod./Year iMHCF):
Actual Sross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000:
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Yea?:
Barrels Oil Per Year:
Price F-er Barrel:
flHCF Gas Per Day:
WMCF Sas Per fear;
0
6
$3.05
$28
$18
$45
$5
$3
$1
$0
: ERR
: -196.50
$36
$4
) $0
$0
$63
: $9
$32
$23
$0
$0
: $22
$9
$2
: $13
$22
1
1095
6
$45
$36
$22
$9
$0
JO
Year
11
0
5
$3.05
$25
$16
$41
$5
$3
$1
$0
ERR
-205.04
$32
$4
$0
$0
$0
$15
$28
$13
$0
$0
$13
$4
$1
$7
$23
1
996
5
$41
$32
$23
$5
$0
$0
Year
12
0
5
$3.05
$23
$15
$38
$4
$3
$1
$0
ERR
-225.42
$30
$4
$0
$0
$0
$11
$25
$14
$0
$0
$14
$5
$1
$8
$20
1
907
5
$38
$30
$20
$6
$0
$0
fear
13
0
4
$3.05
$21
$13
$34
$4
$3
$1
$0
ERR
-247.82
$27
$4
$0
$0
$0
$8
$23
$15
$0
$0
$15
$5
$1
$9
$17
1
825
4
$34
$27
$17
$6
$0
$0
Year
14
0
4
$3.05
$19
$12
$31
$4
$2
$1
$0
ERR
-272.42
$24
$4
$0
$0
$0
$6
$20
$15
$0
$0
$15
•«
$1
$9
$14
1
751
4
$31
$24
$14
$6
$0
$0
Year
15
0
4
$3.05
$17
$11
$28
$3
$2
$1
$0
ERR
-299.47
$22
$4
$0
$0
$0
$6
$18
$13
$0
$0
$12
$4
$1
$7
$13
1
683
4
$28
$22
$13
$5
$0
$0
Year
16
0
3
$3.05
$16
$10
$26
$3
$2
$1
$0
ERR
-329.18
$20
$4
$0
$0
$0
$6
$16
$11
$0
$0
$10
$4
$1
$6
$12
1
622
3
$26
$20
$12
$4
$0
$0
Year
17
0
J
$3.05
$14
$9
$23
$3
$2
$1
$0
ERR
-361.84
$18
$4
$0
$0
$0
$3
$14
$12
$0
$0
$11
$4
$1
$7
$10
1
5oo
3
$23
$18
$10
$5
$0
$0
Year
18
0
j
$3.05
$13
$8
$21
$2
12
$l
$0
ERR
-397,72
$17
$4
$0
$0
$0
$0
$13
$13
$0
$0
$13
$4
$1
$7
$7
1
515
7
J
$21
$17
$7
$5
$0
$0
'ear
F
0
J
$3.05
$12
$8
$19
$2
$1
$1
$0
ERR
-437.16
$15
$4
$0
$0
$0
$0
$11
$11
$0
$0
$11
$4
$1
$7
$7
1
46?
-,
$19
$15
$7
$5
$0
10
'ear
2'"1
OIL PRODUCTION
1
365
426
$25.20
1
365
388
$25.20
1
365
353
$25.20
1
3o5
321
$25.20
1
365
292
$25.20
1
365
266
$25.20
1
365
242
$25.20
1
365
220
$25.20
1
363
201
$25.20
ti
7o5
182
IZ5.IO
SAS PRODUCTION
0
t.
0
2
o
1
0
-i
o
t
L
0
1
0
1
0
1
u
1
;,
:
-------
Price Per MCF:
$3,05 $3.05 13,05 $3.05 $3,05
$3.05 $3.05 $3.05 $3,05
i.1 Revenues f$000>:
Revenues ($000);
Total Revenues ($000):
Royalty Payients-Oil ($000):
Royalty F'ayients-Sas ($000):
Severance Taxes-Oil (tOOO):
Severance Taxes-Gas ($0001:
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas:
Net Revenues($000):
Operating Costs:
Expensed Poll.Cont.Cap.Costs ($000)
Pollution Control Operating Costs:
For PV Poll, Control:
Depreciation i Amortization:
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes
Federal Tax:
State Tax:
Earnings Before Interest After Tax
et Cash Flow:
ShutofP
Actual Oil Prod./Year (Barrels):
Actual Sas Prod./Year (MHCF):
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash F!ON ($000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels Oil Per Year:
Price Per Barrel:
Sas Per Day:
MHCF Sas Per rear:
Price Per MCF:
$11
$7
$18
$2
$t
$0
$0
: 0.00 0
,: -480.49 -528
$14
$4
) $0
$0
$0
$0
$10
$10
$0
$0
: $10
$3
$1
: $6
$6
1
426
2
$18
$14
$6
$4
$0
$0
Year Year
21
OIL PRODUCTION
0
365
166
$25.20 $25
SAS PRODUCTION
0
1
$3.05 $3
$10
$0
$16
$2
$1
$0
$0
'.00
1. 11
$13
$4
$0
$0
$0
$0
$9
$9
$0
$0
$8
$3
$1
$5
$5
1
388
2
$16
$13
$5
$3
$0
$0
22
0
365
151
.20
0
1
.05
$9
$6
$15
$2
$1
$0
$0
0.00
-580.44
$11
$4
$0
$0
$0
$0
$7
$7
$0
$0
$7
$2
$1
$4
$4
1
353
2
$15
$11
$4
$3
$0
$0
Year
-,7
x. J
(1
365
138
$25.20
0
1
$3.05
$8
$5
$13
$2
$1
$0
$0
0.00
-637.94
$10
$4
$0
$0
$0
$0
$6
$6
$0
$0
$6
$2
$0
$4
$4
1
321
2
$13
$10
$4
$3
$0
$0
Year
24
0
365
125
$25.20
0
1
$3.05
$7
$5
112
$1
$1
$0
$0
0,00
-701.14
$10
$4
$0
$0
$0
$0
$5
$5
$0
$0
$5
$2
$0
•13
$3
1
292
2
$12
$10
$3
$2
$0
$0
Year
25
0
365
114
$25.20
0
1
$3.05
$7
$4
$11
$1
$1
$0
$0
0.00
-770.58
$9
$4
*o
$0
$0
$0
$5
$5
$0
$0
$5
$2
$0
$3
$3
1
266
1
$11
$9
$3
$2
$0
$0
Year
26
0
365
104
$25.20
0
1
$3.05
$6
$4
$10
$1
$1
$0
$0
0.00
-846.89
$8
$4
$0
$0
$0
$0
$4
$4
$0
$0
$4
$1
$0
$2
$2
1
242
I
$10
$8
$2
$2
$0
$0
Year
27
0
365
94
$25.20
0
1
$3.05
$6
$4
$9
$1
$1
$0
$0
0.00
-930.75
$7
$4
$0
$0
$0
$3
$3
$0
$0
$3
$1
$0
$2
$2
1
220
1
$9
$7
$2
$1
$0
$0
Year
28
0
365
86
$25.20
0
0
$3.05
$5
$3
$8
$1
$1
$0
$0
0.00
-10-22.90
$7
$4
$0
$0
$0
$2
$2
$0
$0
$2
$1
$0
$1
$1
1
201
1
$8
$7
$1
$1
$0
$0
rear
2?
0
3t5
78
$25.20
0
0
$3.05
15
$3
$8
$1
$1
$0
$0
0.00
-1124.16
$6
$4
$0
$0
$0
$2
$2
$0
$0
$2
$1
$0
$1
$1
1
182
1
$8
$o
$1
$1
$0
$0
Tear
30
0
365
71
$25.20
U
u
$3. ';5
-------
Oil Revenues (tOOO):
ts Revenues 1*000):
tal Revenues (*000):
yalty Paysents-Qil (*000):
Royalty Pay«nts-Sas (tOOO):
Severance Taxes-Oil ($000):
Severance Taxes-Sag ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-6as:
Net Revenues itOOOj;
Operating Costs:
Pollution Control Operating Costs:
For PV Foil. Control;
Depreciation & Atortiration:
Operating Earnings itOOO):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
Net Cash Flow:
|nutofP
Ictual Oil Prod. /Year (Barrels):
Actual Sas Prod. /Year (HHCF):
Actual Gross Pevenues !*000):
Actual Net Revenues ($000):
Actual Net Cash Flow (tOOO):
Actual Taxes Paid ($000):
t4
$3
*7
*i
*i
$0
*0
0.00
-1235.44
$5
$4
$0
tO
$1
*1
*0
to
$1
*0
to
tl
$1
1
166
1
t7
$5
tl
ti
14
t2
ti
$1
to
to
to
0.00
-1357.73
15
$4
to
to
tl
tl
to
to
tl
to
to
to
to
1
151
1
t6
t5
to
to
*3
t2
t6
tl
to
to
to
0.00
-1492.11
t4
*4
to
to
to
to
to
to
to
to
to
to
to
1
138
1
t6
$4
to
to
t3
$2
t5
tl
to
to
to
0.00
-1639.78
t4
t4
to
to
!tO)
(tOi
to
to
(tOi
(tO)
(tO)
(tO)
ItO)
0
0
0
to
to
to
to
$3
t2
t5
tl
to
to
to
0.00
-1802.05
t4
t4
to
to
ftOi
(tO)
to
to
ItO)
itO)
itO)
(tO)
(tO)
•o
0
0
to
to
to
to
t3
*2
t4
to
to
to
to
0.00
-1980.37
13
t4
to
to
(tl)
(tl)
to
to
(tl)
(tO)
(tO)
(tO)
(tO)
0
0
0
to
to
to
to
12
12
t4
to
to
to
to
0.00
-2176.33
*3
*4
to
to
(tl;
(tl)
to
to
(tl)
(tO)
(tO)
(tl)
(tl)
0
0
0
to
to
to
to
$2
tl
t4
to
to
to
to
0.00
-2391.67
t3
t4
to
to
(tl)
(tl)
to
to
(tli
(tO)
(tO)
(tl)
(tl)
0
0
0
to
to
to
to
t2
$1
t3
to
to
to
to
0..00
-2618.31
*3
t4
to
to
Ct2;
(*2)
to
to
(t2)
(tl)
cto>
(tl)
(tl)
0
0
0
to
to
to
to
tl
tl
t3
to
to
to
to
0.00
-2888.35
t2
t4
to
to
(t2)
<*2)
to
to
(t2)
(tli
(tO)
(tli
(tl)
0
< i
0
to
to
to
to
-------
of Net Cash Flows: 1117
of Excess Depletion: 10
PV of Surplus Depreciation: $0
PV of Expensed Invest Cash Flans: Ml
PV of Capitalized Costs: $63
PV of Leasehold Cost: $2
PV Poll. Cont. Costs:* $0
PV of Royalties - Oil: $15
PV of Royalties - 6as: $10
PV of Severance Taxes - Oil: $4
PV of Severance Taxes - Sas: $0
PV of Operating Costs: $21
FV of Inco« Taxes: $47
PV of Total Coipany Costs: $202
FV of Total Coipany Costs -Oils $124
PV of Total Coipany Costs - Sas: $78
Amortized Company Cost per HH8TU: $2.84
Amortized Coipany Cost per bbl: $19.66
Asortized Coipany Cost per HCF: $2.31
Wellhead Price on MMBTU basis - Oil $4.34
Hell head Price on MMBTU basis - 6as $2.99
PV Equiv. of Oil Prod.(bb): 6,316
PV Equiv. of Sas (NMCF): 34
PV Equiv. of Prod. (WBTU): 71,023
Met Present Value of Projec $11
Internal Rate of Return: 0.103
Probable ROR: 0.5
Annuahzed Poll.Cont.Costs: $0
PV of Social Costs - Matt $147
Amortized Social Cost/NMBTU $2.07
PV of Social Costs - Oil: $89
Aaortized Social Cast/bill: $14.13
PV of Social Costs - 6as: $58
Hicrtized Social Cost/HCF: $1.71
-------
Run Date; 29-Apr-87
Project Type: Region 2 - single oil Nell
lase Cost: $1
546 Expense: 58,302
Leasehold Cost: $2
Real Discount Rate: 8,002
Years Between Lease Sale
and Start of Explor.: 0
Percent Costs Considered IDC's: 60.001
Percent Costs Expensed: 60.002
Drilling Mud Cost Increment: 0.002
Corporate Tax Rate: 342
State Corporate Tax Rate: 7.252
Corp Structure (l-iajor/2-indep): 2
EXPLORATION COSTS
Cost Per Exploratory Hell: $64
Drilling Hud Cost Increment: $0
Discovery Efficiency: 0,8
Successful Expl. Hell: 1
Year Year Year Year
0123
Explor. Costs Per Project: $80 $0 $0 $0
"lost of Successful Efforts: $64 $0 $0 $0
Expensed Costs: $54 $0 $0 $0
Expensed Cash Flows: $36 $0 $0 $0
Capitalized Cash Flows: $26 $0 $0 $0
PV of Expensed Exploration Cash Flows: $36
PV of Capitalized Expl. Cash Flows: $26
Total Capitalized Expl. Costs: $26
PV of all Exploratory Costs: $80
DEVELOPMENT COSTS
Total Infrastructure Cost: $45
Years Between Start of Exploration
and Start of Development: 0
Number of Hells Drilled: 0
Nuafaer Wells Drilled Per Year: 0
Driiling Cost Per Hell: $0
Year
Year
0
Year
1
Year
i
L
Year
3
4
Year
Year
5
Year
6
Year
7
fear
8
9
Drilling Cost Per Hell: $0 $0 $0 $0 $0 $0 $0 $0 $0 JO
Drilling Mud Cost Increment: $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
kNutber of Hells Drilled: 00000 000 ri 0
'Total Drilling Costs for Year; $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Annual Infrastructure Cost: $45 $0 $0 $0 $0 $0 $0 $0 $0 $0
Annual Poll Cont Capital Costs: $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
-------
Total Annual Capital Cost; $45 $0 $0 10 $0 $0 $0 $0 $0 10
Tax Shield: $9 $0 $0 10 $0 $0 $0 ID 10 10
tpensed Cash Flow: $18 $0 $0 $0 $0 $0 $0 $0 $0 JO
Ipitali zed Cash Flow: $18 $0 $0 10 10 10 $0 $0 10 10
PV of All Development Costs: $45
PV of Expensed Development Costs:. $18
PV of Capitalized Deveiopient Costs: $18
A
FINANCIAL RATES
Percent Water Cut in 066 to Start: 21
Oil/Gas Prod. Decline Rate/Year (2)
-------
MHCF of Bas Per Day:
MMCF of Gas Per 'fear:
tice/MCF of Gas:
Annual Oil Revenues ($000):
Annual Sas Revenues ($000):
Total Revenues ($000):
Royalty Payients-Qil 1*000):
Royalty Payients-Sas (*000):
Severance Taxes-Oil $000):
Severance Taxes-6as (*000):
ELF for Alaska Severance Taxes-Oil
ELF for Alaska Severance Taxes-Gas
Net Revenues (*000>;
Total Operating Costs 1*0001:
Expensed Poll.Cont.Cap.Costs (*000)
Poll.Con.Operating Costs (*000):
Capitalized Costs ($000):
Depreciation & Asortization 1*000):
Operating Earnings 1*000):
Earnings Before Interest and ODA:
Depletion Allowance;
Surplus Depletion:
Earnings Before Interest and Taxes:
federal Tax:
>tate Tax:
"Earnings Before interest After Tax:
Net Cash Flo*:
ShutofP
Actual Oil Prod./Year (Barrels):
Actual 6as Prod./Year (MMCF):
Actual Gross Revenues (*000):
Actual Net Revenues 1*000):
Actual Net Cash Flow (*000):
Actual Taxes Paid (*000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels Oil Per Year:
Price Per Barrel:
MMCF Gas Per Day:
MMCF Gas Per /ear:
0
6
0
5
*3.05 *3.05
$28
$18
*45
$5
*3
*1
*0
: ERR
$25
*16
$41
*5
$3
$1
*0
ERR
: -196.50 -205.04
$36
*4
i *0
*0
*44
: *6
*32
*25
*4
*0
: *25
*9
*2
: *15
*21
(
1095
6
*45
$36
*21
*10
*0
*0
Year Year
11
OIL PRODUCTION
1
365
426
$25.20 $25
SAS PRODUCTION
0
1
i.
*32
$4
*0
*0
$0
$11
$28
*1B
*4
$0
$18
*6
$1
$10
$21
1
996
5
$41
$32
$21
$7
$0
$0
12
1
365
388
.20
0
n
L
0
5
$3.05
$23
$15
$38
$4
$3
$1
$0
ERR
-225.42
$30
$4
*0
*0
*0
$8
$25
*18
*4
$0
$18
*6
*1
$10
$18
1
907
5
$38
$30
$18
$7
$0
$0
Year
13
1
355
353
$25.20
l)
2
0
4
$3.05
$21
$13
$34
$4
$3
$1
*0
ERR
-247.82
*27
*4
*0
$0
$0
$5
$23
$17
$3
$0
$17
$6
$1
$10
$16
1
825
4
$34
$27
$16
$7
$0
$0
rear
14
1
365
321
$25.20
0
n
L
0
4
$3.05
$19
$12
$31
$4
$2
$1
$0
ERR
-272.42
$24
$4
*0
*0
$0
$4
*20
$16
*3
$0
$16
•*6
$1
$10
$14
1
751
4
$31
$24
$14
$7
$0
$0
iear
15
1
365
292
$25.20
0
i
4.
0
4
$3.05
$17
$11
$28
$3
*2
*1
*0
ERR
-299.47
*22
*4
*0
*0
*0
*4
*1B
$14
*3
*0
$14
*5
*]
$8
$12
1
683
4
$28
*22
$12
$6
$0
$0
Year
16
1
365
266
$25.20
0
1
0
3
$3.05
$16
$10
$26
$3
$2
$1
*0
ERR
-329.18
*20
$4
*0
*0
*0
$4
$16
$12
$3
$0
$12
*4
$1
$7
$11
1
622
3
$26
$20
$11
$5
$0
$0
Year
17
1
365
242
$25.20
0
1
0
3
$3.05
$14
$9
$23
$3
$2
$1
$0
ERR
-361.84
$18
$4
*0
*0
$0
$2
$14
$12
$2
$0
$12
$4
$1
$7
$9
1
566
3
$23
$18
$9
$5
$0
$0
Year
18
1
365
220
*25.20
0
1
0
3
$3.05
$13
$8
$21
$2
*2
$1
• $0
ERR
-397.72
$17
$4
*
-------
Price Per HCF:
$3,05 $3.05 $3.05 $3.05 $3.05
$3.05 $3.05 $3.05 $3,05 $:,'>5
jl Revenues ($000):
5 Revenues t$000):
Total Revenues ($000):
Royalty Pay§ents-0il ($000):
Royalty Pay«ents-Bas ($000;:
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas:
Net Revenues($000):
Operating Costs:
Expensed Poll,Cont.Cap.Costs ($000)
Pollution Control Operating Costs:
For Pv Poll. Control:
Depreciation i Aaortization:
Operating Earnings i$000):
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
'(let Cash Flow:
Shutoff"
Actual Oil Prod./Year (Barrels):
Actual Sas Prod./Year fHNCF):
Actual Bros5 Revenues ($000):
Actual Net Revenues (1000):
Actual Net Cash Flo* i$000):
Actual 'axes Paid '$0001:
Capitalized Costs Not Expended:
Surplus Depreciation:
$11
$7
$13
$2
$1
$0
$0
0.00
•480.49
$14
$4
$0
$0
$0
$0
$10
$10
$2
$0
$10
$3
$1
$6
$6
1
426
2
$18
$14
$6
$4
$0
$0
$10
$6
$lt>
$2
$1
$0
$0
0.00
-528.11
$13
$4
$0
$0
$0
$0
$9
$9
$2
$0
$8
$3
$1
$5
$5
1
388
i
$16
$13
$5
$3
$0
$0
$9
$6
$15
$2
$1
$0
$0
0.00
-580.44
$11
$4
$0
$0
$0
$0
$7
$7
$1
$0
$7
$2
$1
$4
$4
1
353
2
$15
$11
$4
$3
$0
$0
$8
$5
$13
$2
$1
$0
$0
0.00
-637.94
$10
$4
$0
$0
$0
$0
$6
$6
$1
$0
$6
$2
$0
$4
$4
1
321
fc'
$13
$10
$4
$3
$0
$0
$7
$5
$12
$1
$1
$0
$0
0.00
-701.14
$10
$4
$0
$0
$0
$0
$5
15
$1
$0
$5
$2
$0
$3
$3
1
292
2
$12
$10
$3
$2
$0
$0
$7
$4
$11
$1
$1
$0
$0
0.00
-770.58
$9
$4
$0
$0
$0
$0
$5
*5
$1
$0
$5
$2
$0
$3
$3
I
266
1
$11
$9
$3
$2
$0
$0
$6
$4
$10
$1
$1
$0
$0
0.00
-846.89
$8
$4
$0
$0
$0
$0
$4
$4
$1
$0
$4
$1
$0
$2
$2
I
242
1
$10
$8
$2
$2
$0
$0
$6
$4
$9
$1
$1
$0
$0
0.00
-930.75
$7
$4
$0
$0
$0
$3
$3
$1
$0
$3
$1
$0
$2
$2
1
220
1
i9
$7
$2
$1
$0
$0
$5
$3
$8
$1
$1
$0
$0
0.00
-1022.90
$7
$4
$0
$0
$0
$2
$2
$1
$0
$2
$1
$0
$1
$1
1
201
1
$6
$7
$1
$1
$0
$0
15
$3
$8
$1
$1
$0
$0
0.00
-1124.16
$6
$4
$0
$0
$0
$2
$2
$1
$0
$2
$1
$0
$1
$1
1
!B2
i
$6
$6
$1
$i
i
$0
Barrels Oil Per Day:
Days of Production Per rear:
Parrels Oil Per Year: *
Price Per Barrel:
Year Year year ''ear fear Year
21 22 23 24 25
OIL PRODUCTION
0 0 0 0 0
365 365 3*5 365 365
166 151 138 125 114
$25.20 $25.20 $25.20 $25.20 $25.20
Year Year »ear
26 27 28
rear
0 0 0 0 0
365 365 365 365 To3
104 94 86 78 ^
$25.20 $25,20 $25.20 $25.20 $25.ZO
BAS PRODUCTION
MHCF Sas Per Day:
HHCF Sas Per fear:
Price Per 1CF:
i.i y i.i 0 0
11111
$3.05 $3.05 $3,05 $7.05 $3.05
0 0 0 0 ':
1 1 0 0 J
$3.05 $3.05 $3.05 $3.05 $:. o
-------
Oil Revenues 'WOO): *4 *4 *3 $3 *3 *3 *2 *2 t2 H
s Revenues i*000): *3 *2 $2 *2 *2 *2 *2 *1 tl $1
tal Revenues f*000): *7 to t6 t5 *5 *4 *4 t4 t3 t3
Royalty Payments-Oil (WOO): *1 tl 11 tl tl tO W *0 W ' tO
Royalty Payients-6as (WOO): tl tO tO *0 W tO W W W tO
Severance Taxes-Oil (WOO): W *0 W W W tO W *0 W W
Severance Taxes-Sas (WOOi; *0 tO W tO tO W W W W W
ELF for Alaska Severance Taxes-Oil: 0,00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0/00 0.00
ELF for Alaska Severance Taxes-Sas: -1235.44 -1357.73 -1492.11 -1639.78 -1802.05 -1980.37 -2176.33 -2391.67 -2628.31 -2888.35
Net Revenues (WOO): *5 *5 *4 *4 *4 *3 *3 *3 *3 *2
Operating Costs: *4 *4 *4 *4 *4 *4 *4 *4 *4 *4
Pollution Control Operating Costs: *0 tO *0 *0 *0 W *0 W W W
For PV Poll. Control: *0 W W W W W W tO *0 $0
Depreciation 4 Aiortization:
Operating Earnings (WOO): tl tl W (W) (W) !*1) itl) (tl) (*2) <*Z'
Earnings Before Interest and ODA: tl *i W 1*0) (W) (tl) (*1) itl) <*2) -'*2i
Depletion Allowance: tl tl tl tl W W W W *0 to
Surplus Depletion: *0 tO W *0 W W W W W tO
Earnings Before Interest and Taxes: *1 *1 W (W) (W) (*1) t*l) (*1) t*2) (*2i
Federal Tax: *0 tO W i*0) (W) (W) (W) 1*0) (tl; itl!
State Tax: W W tO <*0) (W) (W) (W) (W) (W) i*0<
Earnings Before Interest After Tax: *i tO W (Wi (W) (W) (*1) (tl) (tl) itl)
Net Cash Flow: tl W *0 (W) (W) (*0) (*1) <'*li (*!- itl>
11100 000 0
"Actual Oil Prod,/Year (Barrels): 166 151 138 0 0 0 0 0 0
Actual Sas Prod./Year (HKCF): 11100 0 0 0 0
Actual Gross Revenues (WOO): *7 ti *6 tO W *0 W *0 W I
Actual Net Revenues (WOO): *5 *5 *4 *0 tO *0 *0 tO tO 5
Actual Net Cash Flow (*000>: *1 *0 *0 *0 *0 tO W tO W I
Actual Taxes Paid (WOO): tl W W W W W W W W i
-------
of Net Cash Flows: $110
of Excess Depletion: $0
PV of Surplus Depreciation: $0
PV of Expensed Invest Cash Flows: $54
PV of Capitalized Costs: $44
PV of Leasehold Cost: $2
PV Poll. Cont. Costs: $0
PV of Royalties - Oil: $15
PV of Royalties - Bas: $10
PV of Severance Taxes - Oil: $4
PV of Severance Taxes - Bas: $0
PV of Operating Costs: $21
PV of Incoie Taxes: $53
PV of Total Coipany Costs: $202
PV of Total Cotpany Costs - Oil: $124
PV of Total Coipany Costs - Bas: $78
Aiortized Cotpany Cost per MM8TU: $2.84
Aiortized Coipany Cost per bbl: $19.62
Aiortized Coipany Cost per MCF: $2.31
Wellhead Price on MBTU basis - Oil $4.34
Wellhead Price on MMBTU basis - Bas $2.99
PV Equiv. of Oil Prod.(bb): 6,316
PV Equiv. of Bas (HHCF): 34
PV Equiv. of Prod. (HHBTU): 71,023
Net Present Value of Projec $11
Internal Rate of Return: 0.105
prodable ROP: 0.5
Annuah:ed Poll.Cont.Costs: $0
PV of Social Costs - Totak $147
Amortized Social Cost/MBTU $2.07
pv of Social Costs - Oil: $89
Aicrtized Social Cost/bbi: $14.13
of Social Costs - Gas: $58
Amortized Social Cost''MCF: $1.71
-------
Run Date: Z9-ftpr-87
Project Type: Region 4 - single oil well
ase Cost: $!9
&G Expense: 5B.IOZ
Leasehold Cost: $31
Real Discount Rate: 8.00Z
Years Between Lease Sale
and Start of Expior.: 0
Percent Costs Considered IDC's: oO.OOZ
Percent Costs Expensed: 42.00'i
Drilling Mud Cost Increient; 0,002
Corporate Tax Rate: 34Z
State Corporate Tax Rate: 5.00Z
Corp Structure U-iajor/2-indep): 1
EXPLORATION COSTS
Cost Per Exploratory Hell: $244
Drilling Mud Cost Increment; $0
Discovery Efficiency: 0,59
Successful Expl. Nell: 1
Year Year '"ear Year
Explor. Costs Per Project: $414 $0 $0 $0
t of Successful Efforts: $244 $0 $0 $0
Expensed Costs: $272 $0 $0 $0
Expensed Cash Flows: $180 $0 $0 $0
Capitalized Cash Flows: $142 $0 $0 $0
PV af Expensed Exploration Cash Flows: $180
PV of Capitalized Expl. Cash Flows: $142
Total Capitalized Expl. Costs: $142
PV of all Exploratory Costs: $414
DEVELOPMENT COSTS
Total Infrastructure Cost: $73
rears Between Start of Exploration
and Start of Developient: 0
Nunsber of Hells Drilled: 0
Nusaer Hells Drilled Per Year: 0
Drilling Cost Per Bell: $0
Drilling Cost Per Hell:
Drilling Mud Cost Increient:
Nuiber of Hells Drilled:
Total Drilling Costs for Year:
Annual infrastructure Cost:
Annual Poll Ccmt Capital Costs:
Year
Year
0
$0
$0
(i
$0
$73
*0
Year
1
$0
$0
0
$0
$0
$0
rear
n
i.
$0
$0
0
$0
$0
$0
Year
^
j
$0
$0
o
$0
$0
$0
Year
4
$0
$0
0
$0
$0
$0
Year
5
$0
$0
0
$0
$0
$0
Year
6
$0
$0
0
$0
$0
$0
Year
7
$0
$0
0
$0
$0
$0
•ear
8
$0
$u
u
$0
$0
$0
Y
tr,
10
0
$0
$0
$'j
-------
Gtai Annual Capital Cost: $73 $0 JO JO JO JO JO JO JO JO
ax Shield: $10 JO JO JO JO JO JO JO JO JO
.xpensed Cash Flow: $20 $0 JO JO JO JO $0 $0 JO n
italizsd Cash Flo*: $42 $0 JO JO JO JO JO JO JO JO
PV of All Developient Costs: $73
PV of Expensed Developient Costs: $20
PV of Capitalized Deveiopsent Costs: 142
FINANCIAL RATES
Percent Mater Cut in O&G to Start: 21
Oil/Gas Prod. Decline Rate/Year (X) 70X
Cost Escalator iZ): OX
Royalty Rate (V: 1B.75X
Federal Tax Rate (!/.): 34Z
State Tax Rate (X): 5X
Average Depreciation Life (years): 7
Deprec. rate (each year): 14.29X 24.49? 17.49X 12.49X 8.93X 8.92X 8.93X 4.46Z
State Severance Tax Rate-Oil: IO.OOX
- (If Alaska enter 99!
State Severance Tax Rate-Sas: IO.OOX
(If Alaska enter 99)
PRODUCTION COSTS
Years Betxeen Start of Development
and Start of Production (-5): i
Nuiber of Years at Peak Prod: 1
Oil Peak Prod. Rate/Wellifab): 36
Gas Peak Prod. Rate/Well(HHCF/D): 0.068
Nuiber of Producing Wells: i
Nuaoer of Hells Put in Service/Year 1
Price of Oil Per Barrel: J26.07
Price of Gas Per NCF: J3.02
Total Operating Costs ($000): J13
Foil Cent Oper Costs ($000;: $0
Days of Production Per Year: 365
Producing Hells in Service:
Barrels of Oil Per Day:
Days of Production Per fear:
Barrels of Oil Per fear:
Price/Barrel of Oil:
Year
OIL
J
Year
1
PRODUCTION
1
36
365
13140
26.07 J2
2
0
25
365
9198
6.07
Year
j
fj
18
365
6439
$26.07
'ear
4
0
12
365
4507
$26.07
Year
5
0
9
365
3155
$26.07
Year
6
6
365
2208
$26.07
Year
7
4
365
1546
$26.07
fear
8
3
365
1082
$26.07
tear
9
i.
3&5
757
$26.07
Year
10
;
3o5
530
J2& , 0~
GAS PRODUCTION
-------
MflCF o+ Sas Per Day:
HMCF of Gas Per Year:
Frice/HCF of Sas:
Rnnual Oil Revenues ($0001;
Annual Eas Revenues ($000):
Total Revenues ($000):
Royalty Payients-Qil 'tWji:
Royalty Faysents-Sas tfOOO);
Severance Taxes-Oil ($000):
Severance Taxes-Sas ($000*:
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-6as:
Net Revenues ($000):
Total Operating Costs ($000);
Expensed Poll.Cont.Cap.Costs ($000)
Poll.Con.Operating Costs ($000):
Capitalized Costs ($000!:
Depreciation 4 Anorhzatian ($000):
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
JJtate Tan
Earnings Before Interest After Tax:
Net Cash Flow:
ShutcfP
Actual Oil Prod./Year (Barrels':
Actual Sas Prod./Year (HHCF>:
Actual Gross Revenues ($000':
Actual Net Revenues i$000i:
Actual Net Cash Flo* t*000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Da-'s of Production Per rear:
Barrels Oil Per Year:
Price Per Barrel:
MCF Gas Per Day:
MMCF Sas Per fear:
0
i. J
$3.02
$343
$75
$418
$64
$14
$34
$7
: ERR
,: -43.12
$297
$13
') $0
$0
$184
: $26
$284
$258
$9
$0
: $249
$85
$12
$152
$1S7
1
13140
25
$418
$297
$187
$97
$0
$0
Year
11
0
17
$3.02
$240
$52
$292
$45
$10
$24
$5
ERR
-62.03
$208
$13
$0
$0
$0
$45
$195
$150
$6
$0
$143
$49
$7
$87
$139
1
91=38
17
$292
$208
$139
$56
$0
$0
Year
1 "l
i j.
0
12
$3.02
$168
$37
$205
$31
$7
$17
$4
ERR
-39.04
$146
$13
$0
$0
$0
$32
$132
$100
$4
$0
$96
$33
$5
$58
$95
£
643"
12
$205
$146
$v5
$37
$0
$0
Year
::
0
9
$3.02
$117
$26
$143
$22
$5
$12
$3
ERR
-127.62
$102
$13
$0
$0
$0
$23
$89
$66
$3
$0
$63
$21
$3
$38
$64
1
4507
9
$143
$102
$64
$24
$0
$0
^ear
14
0
6
$:.02
$82
$18
$100
$15
$3
$8
$2
ERR
-182.75
$71
$13
$0
$0
$0
$16
$58
$42
$2
$0
$39
$13
$2
$24
$43
1
3155
6
$100
$71
$43
$15
$0
$0
$0
$•:•
$o
rear
-------
Price Per MCF:
$3.02 $3.02 $7.02 17.02
Oil Revenues ($000):
Bs Revenues ($000):
ioiil Revenues ($000):
Royalty Parents-Oil ($000);
Royalty Fayients-Sas ($000):
Severance Taxes-Oil ($000);
Severance Taxes-bas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Sas:
Net Revenues ($000):
Operating Costs:
Expensed Poll. Cant. Cap. Costs ($000)
Pollution Control Operating Costs:
For PV Poll. Control:
Depreciation i A«orti:ation:
Operating Earnings i*000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
iMet [ash Flow:
w
Shuto^f"
Actual Oil Prod.. 'Year (Barrels):
Actual 6as Prod. //ear (HMCF):
Actual Sross Revenues ($000! :
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per rear:
Barrels Oil Per 'rear:
Price Per Barrel:
MHCF bas Per Day:
MCF Gas Per Year:
Frice Per HCF:
$10
$2
$12
$2
$0
$1
$0
0.00 0
-1560.82 -2230
$8
$13
$0
$0
$0
$0
i$5!
($5)
$0
$0
($5)
($2)
($0)
($3;
($3)
0
0
0
$0
$0
$0
$0
$0
$0
Year Year
21
OIL PRODUCTION
0
365
10
$26.07 $26
GAS PRODUCTION
0
0
$3.02 $3
$7
$1
$8
$1
$0
$1
$0
.00
.18
$6
$13
$0
$0
$0
$0
($7)
($7!
$0
$0
($8)
($3)
i*0)
($5)
i*4)
0
0
0
$0
$0
$0
$0
$0
$0
22
0
365
7
.07
0
o
.02
$5
$1
$6
$1
$0
$0
$0
0.00
-3186.39
$4
$13
$0
$0
$0
$0
i*9)
($9)
$0
$0
i$9)
($3)
t$0)
1*6)
($6)
0
ij
0
$0
$0
$0
$0
$0
$0
'rear
_' j
0
365
5
$26.07
,;,
(i
$3.02
$3
$1
$4
$1
$0
$0
$0
0.00
-4552.42
$3
$13
$0
$0
$0
$0
($10)
($10)
$0
$0
($111
($4)
($1)
($6)
($6)
0
0
0
$0
$0
$0
$0
$0
$0
fear
24
0
365
4
$26.07
n
0
$3.02
$2
$1
$3
$0
$0
$0
$0
0,00
-6503.89
$2
$13
$0
$0
$0
$0
($11)
($11)
$0
$0
($11)
($4)
($1)
($7)
($7)
0
o
0
$0
$0
$0
$0
$0
$0
Year
25
0
365
j
$26.07
0
o
$3.02
$2
$0
$2
$0
$0
$0
$0
0.00
9291.70
$1
$13
$0
$0
$0
$0
($12)
($12)
$0
$0
($12)
($4)
($1)
($7)
($7)
0
0
0
$0
$0
$0
$0
$0
$0
$1
$0
$1
$0
$0
$0
$0
0.00
***********
$1
$13
$0
$0
$0
$0
($12)
($12)
$0
$0
($12)
($4)
($1)
($8)
i$8)
0
0
0
$0
$0
$0
$0
$0
$0
$1
$0
$1
$0
$0
$0
$0
0.00
*********
$1
$13
$0
$0
$0
($13)
($13)
$0
$0
($13)
($4!
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
$1
$0
$1
$0
$0
$0
$0
0.00
*********
$0
$13
$0
$0
$0
($13)
!$13)
$0
$0
($13)
($4)
i*U
($8'
<$S'
0
0
u
$0
$0
$0
$0
$0
$0
JO
$>
It
$(
$'
$0
$0
0 . 00
*******
$0
$;3
$0
$0
$0
.*13)
($13)
$0
$0
'.$13i
i$4)
i$n
1$?!
• *;
i
$
;
1
£
i
Year Vear '"ear 'ear
26 27 26
U i; u
365 365 3o5 :
2111
$26.07 $26.07 $26.07 $2s.07 $2c.
0 0
0 0
$3.02 $3.02
0
$3.u2
$3,::
-------
Oil Revenues ($000;:
Gas Revenues i$000):
jtal Revenues ($000):
Royalty Payaents-Oil ($000):
Royalty Fayients-Sas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($0001;
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-6as:-55289.63
Net Revenues($000i:
Operating Costs:
Foilution Control Operating Costs:
For PV Poll. Control:
Depreciation & Aiortiration:
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
Net Cash Flow:
ShutofP
ual Oil Prod./Year (Barrels):
Actual Bas Prod./Year (NHCF):
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000):
$0
$0
$0
$0
$0
$0
$0
0.00
19.63 *«
$0
$13
$0
$0
($13)
($13)
$0
$0
($13)
($4)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
*********
$0
$13
$0
$0
($13i
($13)
$0
$0
($13)
($4)
($1)
($8)
($81
0
i)
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
*********
$0
$13
$0
$0
($13)
($13)
$0
$0
($13)
($5)
($1)
($8)
t$8)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
*********
$0
$13
$0
$0
($131
($131
$0
$0
i$13)
($51
t$l)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
*******-3
$0
$13
$0
$0
i$13!
($13)
$0
$0
($13)
($5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
28972.82
$0
$13
$0
$0
($13)
i$13)
$0
$0
($13)
($5!
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$1)
$0
$0
$0
$0
0.00
10
id
$0
$0
$0
$0
$0
0.00
$0
$0
10
$0
$0
$0
$0
0.00
************************************
$0
$13
$0
$0
($13)
($13)
$0
$0
($13)
($5)
($1)
($8!
($8)
0
0
0
$0
$0
$0
$0
$0
$13
$0
$0
($13!
($13)
$0
$0
($13)
($5)
($1)
($8)
($81
0
0
0
$0
$0
$0
$0
$0
$13
$0
$0
($13)
($13)
$0
$0
($13)
($5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$13
$0
$0
($13i
($13)
$0
$0
($13)
($5)
($1!
($9)
($9)
0
0
o
$0
$0
$0
JO
-------
_PV of Net Cash Flows: $481
of Excess Depletion: $0
FV of Surplus Depreciation: $0
PV of Expensed Invest Cash Flows: $200
PV of Capitalized Costs: " $184
FV of Leasehold Cost: $11
Pv Poll. Cont, Costs: $0
FV of Royalties - Oil: $83
PV of Royalties - Gas: $18
PV of Severance Taxes -Oil: $44
PV of Severance Taxes - Gas: $10
PV of Operating Costs: $42
PV of Incoie Taxes: $202
PV of Total Cotpany Costs: $813
PV of Total Coipany Costs - Oil: $668
PV of Total Coipany Costs - 6as: $146
Anorhzed Coipany Cost per HH8TU: $3.11
Amortized Cotpany Cost per bbl: $19.70
amortized Coipany Cost per HCF: $2.28
Wellhead Price on HHBTU basis - Oil $4.49
Wellhead Price on MHBTU basis - Gas $2.96
PV Equiv. of Oil Prod.fbbi: 33,881
PV Equiv. of Sas (MMCF): 64
PV Equiv. of Prod. (HHBTU): 261,850
Net Present Value of Projec $67
Internal Rate of Return: 0.148
Frobable ROR: 0.5
Annualized Poll.Cant.Costs: $0
PV cf Social Costs - Total: $540
Afflortired Social Cost.'HHBTU $2.06
PV of Social Costs -Oil: $443
Mortized Social Cost/bbl: $13.08
PV of Social Costs - Gas: $97
lAncrtized Social Cost/MCF: $1.52
-------
Run Date; 29-ftpr-87
Project Type: Region 4 - single oil well
lase Cost: $19
646 Expense: 58.30Z
Leasehold Cost: $31
Real Discount Rate: 8.00Z
V'ears Between Lease Sale
and Start of Explor.: 0
Percent Costs Considered IDC's: 60,OCX
Percent Costs Expensed: 60.0QZ
Drilling Mud Cost Incresent: O.OOZ
Corporate Tax Rate: 34Z
State Corporate Tax Rate: 5.00Z
Corp Structure (l-«ajor/Z-indep!: 2
EXPLORATION COSTS
Cost Per Exploratory Hell: $244
Drilling Hud Cost Increient: $0
Discovery Efficiency: 0.59
Successful Expl. Well: 1
Year Year Year Year
0123
Expior. Costs Per Project: $414 $0 $0 $0
Cost of Successful Efforts: $244 $0 $0 $0
Expensed Costs: $316 $0 $0 $0
Expensed Cash Flows: $209 $0 $0 $0
Capitalized Cash Flows: $?8 $0 $0 $0
?V of Expensed Exploration Cash Flows: $209
PV of Capitalized Expl. Cash Flows: $98
Total Capitalized Expl. Costs: $98
PV o* all Exploratory Costs: $414
DEVELOPMENT COSTS
Total Infrastructure Cost: $73
'ears Between Start of Exploration
and Start of Developaent: 0
Niftier of Wells Drilled: 0
Nuiber Wells Drilled Per Year: 0
[Tilling Cost Per Well: $0
Drilling Cost Per Weil:
Drilling Mud Cost Increient:
kNuiber of Wells Drilled:
Total Drilling Costs for Year:
Annual Infrastructure Cost:
Annual Poll Cont Capital Costs:
Year
Year
0
$0
$0
0
$0
$73
$0
Year
1
$0
$0
0
$0
$0
$0
Year
1
$(/
$0
0
$0
$0
$0
Year
•J
$0
$0
0
$0
$0
$0
Year
4
$0
$0
0
$0
$0
$0
Year
5
$0
$0
0
$0
$0
$0
Year
6
$0
$0
o
$0
$0
$0
'tear
7
$0
$0
0
$0
$0
$0
fear
S
$0
$0
0
$0
$0
$1.1
9
$y
$0
0
$0
$0
iO
-------
Tctal Annual Capital Cost: $73 $0 $0 $0 $0 $0 $0 $0 $0 10
Tax Shield: $15 $0 $0 $0 $0 $0 $0 $0 $0 $0
xpensed Cash Flo*: $29 $0 $0 $0 $0 $0 $0 $0 $0 $0
'pitalized Cash Flon: $29 $0 $0 $0 $0 $0 $0 $0 $0 $0
PV of All Developient Costs: $73
PV of Expensed Development Costs: $29
PV of Capitalized Development Costs: $29
FINANCIAL RATES
Percent Mater Cut in Otfi to Start: 21
Oil/Gas Prod. Decline Rate/Year (Ti 701
Cast Escalator t2i: 02
Royalty Rate (I): 18.752
Federal Tax Rate (2): 342
State Tax Rate (21: 52
Average Depreciation Life (years): 7
Deprec. rate -each year): 14.292 24.492 17.497. 12.492 8.932 8.922 8.932 4.462
State Severance Tax Rate-Oil: 10,002
(If Alaska enter 99!
State Severance Tax Rate-6as: 10.002
(If Alaska enter 99)
PRODUCTION COSTS
Years Between Start of Developnent
and Start of croduction (-5): 1
Nuaber of Years at Peak Prod: 1
Oil Peal Prod. Rate/Well(fab): 36
Sas Peat Prod. fate/HelliNRCF/D): 0.068
Nuiber of Producing Weils: 1
Nusber of Hells Put in Service/Year 1
Price of Oil Per Barrel: $26.07
Price of Gas Per MCF: $3.02
Total Operating Costs ($000': $13
Poll Cont Qper Costs ($000): $0
Davs of Production Per Year: 365
Producing Keils in Service:
Barrels of Oil Per Day: „
Days of Production Per v'ear:
Barrels of Oil Per Year;
Price/Barrel of Oil;
Year Year
I
OIL PRODUCTION
1
36
365
13140
$26.07 $2
•:
0
25
365
9198
6.07
Year
!f
18
JUU
o439
$26.07
-'ear
4
0
12
365
4507
$16.07
rear
5
0
9
3o5
3155
$26.07
Year
6
6
365
2208
$26.07
fear
7
4
365
1546
$26.07
Year Vear
8 9
T -
365 3e5
1082 757
$26.07 $26.07
tear
1
3i5
f 30
$2o.OT
SAS PRODUCTION
-------
•
Wlf
«HCF of Sas Per Day:
HKCF of Gas Per rear:
ice/MCF of Sas:
mnual Oil Revenues ($000):
Annual Sas Revenues i$000):
Total Revenues ($000):
Rovalty Payaents-Oil ($000':
Royalty Faytents-Gas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000);
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas:
Net Revenues l$000):
Total Operating Costs ($000):
Expensed Poll.Cont.Cap.Costs ($000)
Poll.Con.Operating Costs ($000):
Capitalized Costs ($000):
Depreciation 4 Aiortization ($000);
Operating Earnings i$000i:
Earnings Before Interest and 01
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
jtate Tax;
Earnings Before Interest After Tax:
Net Cash Flow:
ShutofP
Actual Oil Prod..'Year (Barrels)
Actual Sas Prod..'rear (HNCFl:
Actual Sross Revenues ($000i:
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Ta'/es Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Cil Per Dav:
Davs at" Production Per /ear:
Barrels Oil ?er Year:
Price Per Barrel:
CIMCF Gas Per Day:
UUCP Gas Per fear:
0
25
0
17
$3.02 $3.02
$343
$75
$418
$64
$14
$34
$7
: ERR
,: -43.12 -6
$297
$13
) $0
$0
$127
: $18
$284
$266
$41
$0
: $257
$87
$13
: $157
$184
1
13140
25
$418
$297
$184
$100
$0
$0
Year Year
11
OIL PRODUCTION
1
365
371
$240
$52
$292
$45
$10
$24
$5
ERR
2.03
$208
$13
$0
$0
$0
$31
$195
$164
$29
$0
$157
$54
$8
$96
$133
1
9198
17
$292
$208
$133
$61
$0
$0
12
1
365
260
$26.07 $26.07
6AS PRODUCTION
o
1
o
0
u
12
$3.02
$lo8
$37
$205
$31
$7
$17
$4
ERR
-89.04
$146
$13
$0
$0
$0
$22
$132
$110
$20
$0
$106
$36
$5
$65
$91
1
6439
12
$205
$146
$91
$41
$0
$0
vear
i j
U
363
1B2
$26.07
ij
o
o
9
$3.02
$117
$26
$143
$22
$5
$12
$3
ERR
-127.62
$102
$13
$0
$0
$0
$16
$89
$73
$14
$0
$70
$24
$3
$43
$62
1
4507
9
$143
$102
$62
$27
$0
$0
Year
14
0
365
127
$26.07
0
0
o
0
$3.02
$82
$18
$100
$15
$3
$8
$2
ERR
-182.75
$71
$13
$0
$0
$0
$11
$58
$47
$10
$0
$45
$15
$2
$27
$41
1
3155
6
$100
$71
$41
$17
$0
$0
Vear
15
0
365
89
$26.07
u
0
0
4
$3.02
$58
$13
$70
$11
$2
$6
$1
ERR
-261.50
$50
$13
$0
$0
$0
$11
$37
$25
$7
$0
$24
$8
$1
$15
$27
1
2208
4
$70
$50
$27
$9
$0
$0
fear
16
0
365
62
$26.07
o
0
0
3
$3.02
140
$9
$49
$8
$2
$4
$1
ERR
-373.99
$35
$13
$0
$0
$0
$11
$22
$10
$5
$0
$9
$3
$0
$6
$18
1
1546
J
$49
$35
$18
$4
$0
$0
tear
17
0
365
44
$26.07
,;,
o
0
~
i.
$3.02
$28
$6
$34
$5
$1
$3
$1
ERR
-534.71
$24
$13
$0
$0
$0
$6
$11
$5
$3
$0
$5
$2
$0
$3
$9
1
1082
L
$34
$24
$9
$2
$0
$0
Year
ie
0
365
31
$26.07
U
o
U
]_
$3.02
$20
$4
$24
$4
$1
$2
$0
EFR
--64.2"
$17
$13
$0
$0
$0
$0
$4
$4
$2
$0
$3
$1
$0
t2
$3
i
~ /
$24
$17
$3
$1
JO
?<:<
tear
i'
3o5
21
'— 7
,,
,.
$i4
13
$r
$1
$o
$o
$0
$0
!$!'
'$!•
$2
$0
iO
$0
$0
$'.'
$0
-------
Price Per MCF:
$3.02 $3.02 $7,02 $3.02 $3.02
$3.02 $3,02 $3.01 $3.02 $7.02
Jil Revenues ($000):
Bs Revenues i*000>:
Total Revenues ($000):
Royalty Parents-Oil {$000);
Royalty Paytents-Sas ($000):
Severance Taxes-Oil (*000):
Severance Taxes-Sas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF tor Alaska Severance Taxes-6as:
Net Revenues(*000>:
Operating Costs:
Expensed Pal l.Cont. Cap. Costs ($000)
Pollution Control Operating Costs:
For PV Poll. Control;
Depreciation 4 Anortizatton:
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Ta»:
State Tax:
Earnings Before Interest After Tax:
|et Cash Flow:
w
Shutoff
Actual Oil Prod. /Year (Barrels):
Actual Gas Prod. /Year (MMCF):
Actual Brass Revenues ($000):
Actual Net Revenues 1*000):
Actual Net Cash Ho* (*000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per lew,
Barrels Oil Fer Year:
$10
$2
$12
$2
$0
$1
$0
0.00 0
-1560.82 -2230
$8
$13
$0
$0
$0
$0
($5)
($5!
$1
$0
($5)
($2)
i*0!
(*3)
($3)
0
0
0
$0
$0
$0
$0
$0
$0
Year fear
21
OIL PRODUCTION
0
365
10
$7
$1
$8
$1
$0
$1
$0
.00
.18
$6
$13
$0
$0
$0
$0
($7)
($7)
$1
$0
($8)
($3)
($0)
($5)
($4)
0
0
0
$0
$0
$0
$0
$0
$0
22
0
365
7
$5
$1
$6
$1
$0
$0
$0
0.00
-3186.39
$4
$13
$0
$0
$0
$0
C$9!
i*9)
$1
$0
t$9>
($7!
i*0)
(*6)
i$6i
0
0
0
$0
$0
$0
$0
$0
$0
Year
23
o
363
5
$3
$1
$4
$1
$0
$0
$0
0.00
-4552.42
$3
$13
$0
$0
$0
$0
($10)
($10)
$0
$0
i$lli
(*4)
(*n
($6)
($6)
0
0
0
$0
$0
$0
$0
$0
$0
rear
:4
0
365
4
$2
$1
$3
$0
$0
$0
$0
0.00
-6503.89
$2
$13
$0
$0
$0
$0
($11)
($11)
$0
$0
($11)
($4)
($1)
($7)
($7)
0
0
0
$0
$0
$0
$0
$0
$0
tear
25
0
365
3
$2
$0
$2
$0
$0
$0
$0
0.00
-9291.70
$1
$13
$0
$0
$0
$0
($12)
($12)
$0
$0
(*12)
(*4)
($1)
($7)
($7)
0
0
0
$0
$0
$0
$0
$0
$0
fear
26
0
365
i.
$1
$0
$1
$0
$0
$0
$0
0.00
*********
$1
$13
$0
$0
$0
$0
($12)
($12)
$0
$0
($12)
($4)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
Year
27
0
365
1
$1
$0
$1
$0
$0
$0
$0
0.00
*********
$1
$13
$0
$0
$0
($13)
($13)
$0
$0
($13)
($4)
($1)
($8)
($8;
0
0
0
$0
$0
$0
$0
$0
$0
rear
28
0
365
1
$1
$0
$1
$0
$0
$0
$0
0 . 00
************
$0
$13
$0
$0
$0
($13)
($13)
$0
$0
($13)
($4)
($1)
1*8)
i$8)
0
0
0
$0
$0
$0
$0
$0
$0
rear tea
-'
0
765
i
$0
$0
$0
$0
$0
$0
$0
0 . 00
******
$0
$13
$0
$0
$0
i*13i
<*13)
$0
$0
(*13)
i$4l
i*n
i$9)
i*9i
V
U
o
$0
$0
$0
$0
$0
$0
r
-•'-'
,1
7o5
0
Price Fer Barrel:
$26.07 $26.07 $26.07 $26.07 $26.07 $26.07 $26,07 $26.07 *2s.07 $2fc.0~
F Sas Per Day:
HNCF Gas per 'ear:
Price Per MCF:
GAS PRODUCTION
0 0 0 0 0
0 0 0 0 0
$3.02 $3.02 $3.02 $7.02 $3.02
0 (j 0 j
0 0 0 0
$3.02 $3,02 $3.02 $7.02 $7. 2
-------
0:1 Revenues ($000):
Eas Revenues ($000):
^ktal Revenues '$000):
^royaltv rayaents-Oil ($000):
Royalty Payments -Gas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Sas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Sas:
Net Revenues ($000):
Operating Costs:
Foliation Control Operating Costs:
For PV Poll. Control:
Depreciation i Aaorti:ation:
Operating Earnings ($000);
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax;
State Tax:
Earnings Before Interest After Tax:
Net Cash Flow:
^^h ut off
Actual Oil Prod, /Year (Barrels):
Actual Gas Prod. ./Year (flMCF):
Actual Gross Revenues (*000>:
Actual Net Revenues ($000):
Actual Net Lash Flo* ($000):
Actual Taxes Paid ($000):
$0
$0
$0
$0
$0
$0
$0
0.00
-55189,63
$0
$13
$0
$0
($13!
($13)
$0
$0
($23)
($4)
($1)
($8)
<$8)
0
0
0
$0
$0
$0
$0
$e
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
(-.00
*m**«*****«*«m*m*f****mH***-328972.S2
$0
$13
$0
$0
($13)
($13)
$0
$0
($13)
($4)
($1!
($8)
($6!
0
0
0
$0
$0
$0
$0
$0
$13
$0
$0
'$13)
($13)
$0
$0
($13)
($5)
(*1)
($8)
i$S)
0
o
0
$0
$0
$0
$0
$0
$13
$0
$0
($13)
($13!
$0
$0
($13)
($5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$13
$0
$0
($13)
($13)
$0
$0
($131
($5)
($1!
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$13
$0
$0
($13)
($13)
$0
$0
($13)
(*5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
t*ttt**ftf»**tt*tf *{**»*************
$0
$13
$0
$0
!$13)
($13)
$0
$0
($13)
($5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$13
$0
$0
($13)
($13)
$0
$0
($13)
1*5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$13
$0
$0
($13)
($131
$0
$0
($13)
($5)
($1)
($8)
($8)
0
0
$0
$0
$0
$0
$0
$!3
$0
$0
i*13i
($13)
$0
$0
i*13)
($5)
($1)
($9)
($91
0
0
$0
10
$•:•
$0
-------
PV of Net Cash Flows: $4&4
of Excess Depletion: $0
of Surplus Depreciation: JO
PV of Expensed Invest Cash Flows: $238
PV 3t Capitalized Costs: *127
PV 3f Leasehold Cost: $31
PV Poll. Cent. Costs: JO
PV of Royalties - Oil: $83
PV of Royalties - Sas: $18
PV of Severance Taxes - Oil: $44
PV of Severance Taxes - 6as: $10
PV of Operating Costs: $42
PV of Jncoie Taxes: $220
PV of Total Co«pany Costs: $811
FV of Total Cospany Costs - Oil: $666
PV of Total Coapany Costs - Gas: $146
ftiiortized Coipany Cost per HM8TU: $3,10
Aiorhzed Coapany Cost per bbl: $19.65
Mortized Coipany Cost per 1CF: $2,28
Wellhead Price on MMBTU basis - Oil $4.49
Wellhead Price on HHBTU basis - Sas $2.96
FV Equiv. of Oil Prod.ibb): 33,881
PV Equiv. of Gas (NHCF): 64
PV Equiv. of Prod. (HHBTU): 261,850
Net Present Value of Projec $69
Internal Rate of Return: 0.154
Probable PGP: 0.5
Annuah:ed Poll.Cont.Costs: $0
PV of Social Costs - Total: $540
Aiortized Social Cost/HHBTt) $2.06
FV of Social Costs - Oil: $443
Aiortned Social Cost/bbl: $13.08
F1/ of Social Costs - Sas: $97
Asorhzed Social Cost/HCF: $1.52
-------
Pun Sate: 29-Apr-87
Project Type: Region 4 - single gas well
lase Cost: $154
6*8 Expense: 58.30Z
Leasehold Lost: 1244
Peal Discount Rate: 8.OCX
Years Between Lease Sale
and Start of Explor,: 0
Percent Costs Considered IDC's: 60.007.
Percent Costs Expensed: 42.00?
Drilling Mud Cost Incretent: O.OOZ
Corporate Tax Rate: 347.
State Corporate Tax Rate: 5.OCX
Corp Structure (l-iajor/2-indep): 1
EXPLORATION COSTS
Cost Per Exploratory Hell: $640
Drilling Mud Cost Incresent: $0
Discovery Efficiency: 0,59
Successful Expl. Weil: 1
fear Year Year Year
0123
Explor. Costs Per Project: $1,085 $0 $0 $0
ost of Successful Efforts: 1640 $0 $0 $0
Expensed Costs: $714 $0 $0 $0
E.-pensed Cash Flows: $471 $0 $0 $0
Capitalized Cash Flows: $371 $0 $0 $0
FV of Expensed Exploration Cash Flows: $471
FV of Capitalized Expl. Cash Flows: $371
Total Capitalized Expl. Costs: $371
PY of all Exploratory Costs: $1,085
DEVELOPMENT COSTS
Total Infrastructure Cost: $35
'ears Between Start of Exploration
and Start of Development: 0
NuMer of Wells Drilled: 0
Nusber Wells Drilled Per Year: 0
Drilling Cost Per Hell: $0
Drilling Cost Fer Hell:
Drilling Hud Cost Increment:
fluiber of Hells Drilled;
FTotal Drilling Costs for 'rear:
Annual Infrastructure Cost:
Annual Poll Cent Capital Costs:
Year
Year
0
$0
$0
0
$0
$35
$0
Year
1
$0
$0
0
$0
$0
$0
Year
2
$0
$0
o
$0
$0
$0
Year
J1
$0
$0
0
$0
$0
$v
Year
4
$0
$0
o
$0
$0
$0
Year
5
$0
$0
0
$0
$0
$0
Year
6
$0
$0
0
$0
$0
$0
Vear
T
/
$0
$0
0
$0
$0
$0
'ear
3
$0
$0
1)
$u
$0
JO
9
JO
$0
$0
*0
$'.>
-------
Total Annual Capital Cost: $35 $0 $0 $0 $0 10 $0 $0 $0 $0
Tax Shield: $5 $0 $0 $0 $0 $0 $0 $0 $0 $0
Censed Cash Flow: $10 $0 10 $0 $0 $0 $0 $0 $0 $0
Vitalized Cash Flow: $20 $0 $0 $0 $0 $0 $0 $0 $0 $0
PV at All Develapient Costs: $35
PV of Expensed Developnent Costs: $10
PV of Capitalized Developient Costs: $20
FINANCIAL RATES
Percent Water Cut in 0&6 to Start: 21
Oil/Gas Prod. Decline Rate/Year (X) 70Z
Cost Escalator i'Z): OX
Royalty Rate (X): 18.75Z
Federal Tax Rate (XI: 34X
State Tax Rate (X): 5Z
Average Depreciation Life (years): 7
Deprec. rate (each year): 14.29X 24.49X 17.491 12.49X 8.93X B.92X 8.93X 4.46X
State Severance Tax Rate-Oil: 10.00X
(li Alaska enter 99)
State Severance Tax Rate-Gas: IO.OOZ
(If Alaska enter 99)
PRODUCTION COSTS
Vears Between Start of Developient
and Start of Production (-5): 1
Nuiber of Years at Peak Prod: i
Oil Peai- Prod. Rate/Well (bb): 0
Gas Peak Prod. Rate/Well(NHCF/D): 0.971
Nunber at" Producing Hells: 1
Nuiber of Hells Put in Service/Year 1
Price of Oil Per Barrel: $26.07
Price of Bas Per HCF: $3.02
Total Operating Costs ($000): $18
Poll Cont Oper Costs ($000): $0
Days of production Per Year: 365
Producing Wells in Service:
Barrels of Oil Per Day:
Days of Production Per Year:
Barrels of Oil Per Year:
Price/Barrel of Oil:
Year Year
1
OIL PRODUCTION
1
0
365
0
$26.07 $26
tear
-i -*
0 0
0 0
ij 6 D j 0 J
0 0
.07 $26,07
fear
4
0
0
365
0
$26.07
Year
5
0
o
365
0
$26.07
Year
6
0
365
0
$26.07
Vear
7
0
365
ij
$26.07
Year year rear
8 ' iO
0 ' '
3&5 363 TD!
0 •'•
$26.07 $26.0^ $Zi.:~
GAS PRODUCTION
-------
MMCF of Sas Per Day:
MMCF of Sas Per Year:
ice/MCF of Gas:
i
Annual Qii Revenues ($000):
Annual Sas 5evenues ($000):
Total Revenues ($000):
Royalty Paysents-Oil ($000):
Royalty Payaents-Sas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil
ELF for Alaska Severance Taxes-Gas:
Net Revenues ($000):
Total Operating Costs ($000):
Expensed Poll.Cont.Cap.Costs ($000)
Poll.Con.Operating Costs ($000):
Capitalized Costs ($000):
Depreciation fc Amortization ($000):
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
It ate Tax;
Earnings Before Interest After Tax:
Net Cash Flow:
Snutcfr
Actual Oil Prod./Year (Barrels):
Actual Sas Prod./Year (MMCF):
Actual Gross Revenues ilOQO):
Actual Net Revenues ($000):
Actual Net Cash Flo* ($000):
Actual Taxes Paid i$000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels Oil Per Year:
Price Per Barrel:
HKCF Sas Per Day:
MCF Gas Per Year:
i
354
$3,02
$0
$1,070
11,070
$0
$201
$0
$107
ERR
-2.09
$763
$18
$0
$0
$392
$56
$744
$688
$0
$0
$686
$234
$34
$420
$476
1
0
354
$1,070
$763
$476
$268
$0
$0
Year
11
1
248
$3.02
$0
$749
$749
$0
$140
$0
$75
ERR
-3.41
$534
$18
$0
$0
$0
$96
$515
$419
$0
$0
$419
$143
$21
$256
$352
1
0
248
$749
$534
$352
$164
$0
$0
Year
12
(i
174
$3.02
$0
$524
$524
$0
$98
$0
$52
ERR
-5.31
$374
$18
$0
$0
$0
$69
$355
$287
$0
$0
$287
$97
$14
$175
$2*3
1
0
174
$524
$3^4
$243
$112
$0
$0
Year
13
0
122
$3.02
$0
$367
$367
$0
$&9
$0
$37
ERR
-8.01
$262
$18
$0
$0
$0
$49
$243
$194
$0
$0
$194
$66
$10
$118
$167
1
0
122
$367
$262
$167
$76
$0
$0
fear
14
o
85
$3.02
$0
$257
$257
$0
$48
$0
$26
ERR
-11.87
$183
$18
$0
$0
$0
$35
$165
$130
$0
$0
$130
$44
$6
$79
$114
1
0
85
$257
$183
$114
$51
$0
$0
'fear
15
0
60
$3.02
$0
$180
$180
$0
$34
$0
$18
ERR
-17.38
$128
$18
$0
$0
$0
$35
$110
$75
$0
$0
$75
$25
$4
$46
$81
1
0
60
$180
$128
$81
$29
$0
$0
'"ear
16
0
42
$3.02
$0
$126
$126
$0
$24
$0
$13
ERR
-25.26
$90
$13
$0
$0
$0
$35
$71
$36
$0
$0
$36
$12
$2
$22
$57
1
0
42
$126
$90
$57
$14
$0
$0
Year
17
0
29
$3.02
$0
$86
$88
$0
$17
$0
$9
ERR
-36.52
$63
$18
$0
$0
$0
$17
$44
$27
$0
$0
$27
$9
$1
$16
$34
1
0
2?
$88
$63
$34
$10
$0
$0
Year
18
o
10
$3.02
$0
$fc2
$62
$0
$12
$0
$6
ERR
-52.59
$44
$18
$0
$0
$0
$0
$25
$25
$0
$0
$25
$9
$1
$16
$16
1
0
20
$62
$44
$lo
$10
$0
$0
Year
19
14
$3.0;
$0
$43
$43
$0
$8
$0
$4
ERR
-75.56
$31
$18
$0
$0
$0
$0
$12
$12
$0
$0
$12
$4
$1
$3
$8
i
0
14
$43
$31
$3
$5
$0
$0
Year
20
OIL PRODUCTION
0
365
0
$26.07
0
365
0
$26.07
0
365
0
$26.07
0
365
0
$26.07
0
365
0
$26.07
0
365
0
$26.07
0
365
0
$26.07
0
365
0
$26.07
0
365
0
$26,07
j
3o5
0
$Zo.'j7
GAS PRODUCTION
0
10
0
7
0
5
0
7
j
0
i
0
2
0
1
0
1
l)
1
*j
-------
Price Per MCF:
$3.02 $3.02 $3,02 $3.02 $3.02
$3.02 $3.02 $3.02 $3.02 *3.vZ
il Revenues '$000!:
'as Revenues ($000):
Total Revenues ($000):
Royalty Payients-Oil 1*000):
Royalty Payients-Sas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas (*000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-6as:
Net Revenues(*000):
Operating Costs:
Expensed Poll.Cont.Cap.Costs ($000)
Pollution Control Operating Costs:
For PV Poll. Control:
Depreciation i Amortization:
Operating Earnings ($000):
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
Net Cash Flo*:
ShutofP
Actual Oil Prod./Year (Barrels):
Actual 6as Prod./Year (MMCF):
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flo* ($000):
Actual Taxes Paid t*000):
Capitalized Costs Not Expended:
Surplus Depreciation:
$0
$30
$30
$0
$6
$0
$3
0.00
108.38
$22
$18
$0
$0
$0
$0
*3
$3
$0
$0
$3
$1
$0
$2
$2
I
0
10
$30
$22
$2
$1
$0
*0
$0
$21
$21
$0
$4
$0
$2
0.00
-155.25
$15
$18
$0
$0
$0
$0
($3)
($3)
$0
$0
($3)
($1)
($0)
($2)
($2)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$15
$15
$0
$3
$0
$1
0.00
-222.22
$11
$18
$0
$0
$0
$0
1*8)
($8)
$0
$0
($8)
t*3i
($0)
($5)
i*5)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$10
$10
$0
$2
$0
$1
0.00
-317.88
$7
$18
$0
$0
$0
$0
itll)
($11)
$0
$0
i*li)
($4!
($1)
($7)
($7)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$7
$7
$0
$1
$0
$1
0.00
-454.54
$5
$18
$0
$0
$0
$0
($13)
($13)
$0
$0
($13)
($5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$5
$5
$0
$1
$0
$1
0.00
-649.78
$4
$18
$0
$0
$0
$0
($15)
($15)
$0
$0
($15)
($5)
($1)
($9)
($9)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$4
$4
$0
$1
$0
$0
0.00
-928.68
$3
$18
$0
$0
$0
$0
($16)
($16)
$0
$0
($16)
($5)
($1)
($10)
($10)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$2
$2
$0
$0
$0
$0
0.00
-1327.11
$2
$18
$0
$0
$0
($17)
($17!
$0
$0
($17)
($6)
($1)
($10)
($10)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$2
$2
$0
$0
$0
$0
0.00
-1896.31
$1
$18
$0
$0
$0
($17)
($17)
$0
$0
($17)
($6)
l*D
i$lb
i*ll;
u
0
0
$0
$0
$0
$0
$0
$0
it.
$1
»i
$0
$0
$0
$0
0.00
-2709.44
$1
$18
$0
$0
$0
($18)
i$18)
$0
$0
($18;
($6)
i*li
•*1Z<
•*i:>
0
0
i !
$0
$0
$0
$0
$0
$0
Year
Year
Year
rear
21 22 23
OIL PRODUCTION
Year
24
Barrels Oil Per Day:
Days of Production Per Year:
Barrels Oil Per Year:
Price Per Barrel:
MMCF 6as Per Dav:
MCF Gas Per Year:
Price Per MCF;
Year
0 0 0 0
0000
$3.02 $3.02 $3,02 $3,02
25
0 0 0 0 0
365 365 3i5 365 365
0 0000
$26.07 $26.07 $26.07 $26.07 $26.07
5AS PRODUCTION
Year
26
Year
year
27
fear
0 0 0 0 0
365 365 365 365 3e5
0 0 0 0 0
$26.07 $26.07 $26.07 $26.07 $2o.07
0 0 0 0 <
o o o o •:
$3,02 $3.02 $3.02 $3,02 *3.0;
-------
Oil Revenues ($000):
^ks Revenues ($000):
^Ktal Revenues ($000):
Royalty Pay«ents-0il ($000):
Royalty F'ay«ents-Sas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-6as ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas:
Net Revenues ($000):
Operating Costs:
Pollution Control Operating Costs:
For PV Poll. Control:
Depreciation 4 Amortization:
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax;
Earnings Before Interest After Tax:
Net Cash Flow:
^phutoff"
Actual Oil Prod. /Year (Barrels):
Actual Gas Prod. /Year (NNCFi:
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000):
$0
$1
$1
$0
$0
$0
$0
0.00
-3871.05
$1
$18
$0
$0
($18)
($18)
$0
$0
($18)
($6)
($1)
($11)
($11)
0
0
0
$0
$0
$0
$0
$0
$1
$1
$0
$0
$0
$0
0.00
-5530.50
$0
$18
$0
$0
i$18)
($18)
$0
$0
($18)
($6)
($1)
($11)
($11)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
-7901.15
$0
$18
$0
$0
($18)
($18)
$0
$0
($18)
($6)
($1)
($11)
($11)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
******************
$0
$18
$0
$0
Ifl8)
($18)
$0
$0
($18)
($6)
($1)
($11)
i$ll)
0
0
0
$0
$0
$0
$0
$0
$18
$0
$0
($18)
($18)
$0
$0
($18)
($6)
($1)
($11)
($11)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
-23037.33
$0
$18
$0
$0
($18)
($18)
$0
$0
($18)
($6)
($1)
($11)
($11)
0
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
$0
$0
$0
$0
$0
$0
$0
0.00
************************************
$0
$18
$0
$0
($18)
($18)
$0
$0
($18)
($6)
($1)
($11)
($11)
0
0
0
$0
$0
$0
$0
$0
$18
$0
$0
($18)
($18!
$0
$0
($18)
($6)
($1)
i$ll)
($11)
0
0
0
$0
$0
$0
$0
• $0
$18
$0
$0
($18)
($18)
$0
$0
($18)
($6)
($1)
($11)
($11)
0
0
0
$0
$0
$0
$0
$0
$18
$0
$0
($181
($18;
$0
$0
($18)
i$6)
($11
($12)
($12)
&
i '
o
$0
$0
$0
$0
-------
PV of Net Cash Flows: $1,251
PV of Excess Depletion: $0
of'Surplus Depreciation: $0
FV of Expensed Invest Cash Flows: $481
PV of Capitalized Costs: $392
FV of Leasehold Cost: $244
PV Doll. Cent. Costs: $0
PV of Royalties - Oil: $0
PV of Royalties - Bas: $2b2
PV of Severance Taxes -Oil: $0
PV of Severance Taxes - Bas: $140
PV of Operating Costs: $66
FV of Incoie Taxes: $608
PV of Total Coipany Costs: $2,192
FV of Total Coipany Costs -Oil: $0
PV of Total Conpany Costs - Sas: $2,192
Asortized Company Cost per HHBTU: $2.32
Amortized Cospany Cost per bbl: ERR
Anorhzed Coipany Cost per HCF: $2.37
Wellhead Price on HHBTU basis - Oil $4.49
iiellhead Price on HHBTU Sasis - 6as $2.96
PV Equiv. of Oil Prod.(bbl: 0
PV Equiv. of Sas (HHCF): 925
PV Equiv. of Prod. (HHBTU): 9*4,182
Met Present Value of Projec $134
Internal Rate of Return: 0.129
Probable ROR: 0.5
Annuahzed Poll.Cont.Costs: $0
PV of Social Costs - Total: $1,276
Amortized Social Cost/HHBTU $1.35
PV cf Social Costs - Oil: ' $0
Amortized Social Cast/bill: ERR
F'V of Social Costs - 5as: 11,276
Amortized Social Ccst/HCF: $1.38
-------
Run Date:
reject Type:
lease Cost:
GiS Expense:
Leasehold Cost:
Feal Discount Rate:
Years Between Lease Sale
and Start of Explor.:
Percent Costs Considered IDC's:
Percent Costs Expensed:
Drilling Hud Cost Increient:
Corporate Tax Rate:
State Corporate Tax Rate:
Corp Structure ii-iajor/2-indep):
Cost Per Exploratory Hell:
Drilling Hud Cost Increient:
Discovery Efficiency:
Successful Expi. Well:
2
-------
Total Annual Capital Cost; $35 $0 $0 $0 $0 $0 $0 $0 $0 JO
Tax Shield: $7 $0 JO $0 $0 $0 $0 $0 $0 $0
«ensed Cash Flo*: $14 $0 $0 $0 $0 $0 $0 $0 $0 $0
, itahred Cash Flow; $14 $0 $0 $0 $0 $0 $0 $0 $0 $0
F'V of All Developsent Costs: $35
FV of Expensed Developsent Costs: $14
PV of Capitalized Develapient Costs: $14
FINANCIAL RATES
Percent later Cut in OfcG to Start: 21
Oil/Sas Prod. Decline Rate/Year (?) 70Z
Cost Escalator iZi: OX
Royalty Rats (I): 18.752
Federal Tax Rate (1): 34X
State Tax Rate (I): 5X
Average Depreciation Life (years): 7
Deprec. rate (each year): 14.29X 24.49? 17.49? 12.49? B.93Z 8.927. 8.93? 4.46?
State Severance Tax Rate-Oil: 10.00?
(If Alaska enter 99)
State Severance Tax Rate-6as: 10.00X
(If Alaska enter 99!
PRODUCTION COSTS
Years Betneen Start of Developsent
and Start of Production (\5): 1
Nuaber of 'fears at Peak Prod: 1
Oil Pea). Prod. Rate/Hell (fab): 0
das Pea* Prod. Rate/Well (NMCF/D): 0.971
Number of Producing Wells: 1
Nunoer of Wells Put in Service/Year 1
''nee of Oil Per Barrel: $26.07
Price of Gas Per «CF: $3.02
Totai Operating Costs ($000): $18
Foil Cont Oper Costs ($000): $0
Davs of Production Per Year: 365
producing Weils in Service:
Barrels of On Ff Day:
Days of Production Per Year:
Barrels of Oil Per rear:
Price/Barrel of Oil:
Year Year
1
OIL PRODUCTION
1
0
365
0
$26.07 $26
2
0
0
365
0
.07
Year
J
ft
U
365
0
$26.07
fear
4
0
0
365
0
$26.07
Vear
s
u
0
0
3fc5
0
$26.07
Year
6
0
365
0
$26.07
Year
7
0
365
0
$26.07
fear fear 'ear
8 ' 10
0 0 v
365 3t>5 3o5
0 0 v
$26.07 $26.07 $:5..,7
bAS PRODUCTION
-------
MHCF of Gas Per Day;
HHCF of Gas Per Year;
pice/HCF of Sas:
Annual Oil Revenues ($000!;
Annual Sas Revenues ($000):
Total Revenues ($000):
Royalty Payients-Qil ($000):
Royalty Paynents-Sas ($000):
Severance Taxes-Oil ($000):
severance Taxes-6as ($000):
ELF for Alaska Severance Taxes-Oil
ELF for Alaska Severance Taxes-Sas
Net Revenues ($000):
Total Operating Costs ($000):
Expensed Poll.Cont.Cap.Costs >'$000i
Poll.Con.Operating Costs ($000):
Capitalized Costs '$0001:
Depreciation i Aaortization ($000):
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
federal Tax:
fetate Tax:
Earnings Before Interest After Tax:
Net Cash Flow;
Shutoff
Act'jai Oil Prod.//ear (Barrels):
Actual Sas Prod./Year (HHCF):
Actual Brass Revenues ($000):
Actual Net Revenues ($000;:
Actual Net Cash Flow ($000);
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day;
Days of Production Per /ear:
Barrels Oil per Year:
Price Per Barrel:
1HCF Sas cer Day:
HHCF Sas Per Year;
1
354
$3.02 $
$0
$1,070
$1,070
$0
$201
$0
$107
ERR
-2.09 -
$763
$18
$0
$0
$270
$39
$744
$706
$106
$0
$706
$240
$35
$430
$469
I
0
354
$1,070
$763
$469
$275
$0
$0
Year Year
11
OIL PRODUCTION
0
365
0
$26.07 $2
SAS PRODUCTION
0
10
1
243
3.02
$0
$749
$749
$0
$140
$0
$75
ERR
3.41
$534
$18
$0
$0
$0
$66
$515
$449
$74
$0
$449
$153
$22
$274
$340
1
0
248
$749
$534
$340
$175
$0
$0
12
0
365
0
6.07
0
7
o
174
$3.02
$0
$524
$524
$0
$98
$0
$52
ERR
-5.31
$374
$18
$0
$0
$0
$4?
$355
$308
$52
$0
$308
$105
$15
$138
$235
1
0
174
$524
$374
$235
$120
$0
to
•ear
13
0
365
0
$26.07
,,
5
0
122
$3.02
$0
$367
$367
$0
$69
$0
$37
ERR
-8.01
$262
$18
$0
$0
$0
$34
$243
$209
$36
$0
$209
$71
$10
$128
$161
1
0
122
$367
$262
$161
$82
$0
$0
Year
14
0
365
0
$26.07
0
?
(i
85
$3.02
$0
$257
$257
$0
$48
$0
$26
ERR
-11.87
$183
$18
$0
$0
$0
$24
$165
$140
$25
$0
$140
$48
$7
$36
$110
1
0
85
$257
$183
$110
$55
$0
$0
fear
15
0
365
0
$26.07
0
2
0
60
$3.02
$0
$180
$180
$0
$34
$0
$18
ERR
-17.38
$128
$18
$0
$0
$0
$24
$110
$86
$18
$0
$86
$29
$4
$52
$76
1
0
60
$180
$128
$76
$33
$0
$0
Year
16
0
365
0
$26.07
0
2
0
42
$3.02
$0
$126
$122
$0
$24
$0
$13
ERR
-25.26
$90
$18
$0
$0
$0
$24
$71
$47
$12
$0
$47
$16
$2
$29
$53
1
0
42
$126
$90
$53
$18
$0
$0
Year
17
0
365
0
$26.07
0
1
0
29
$3.02
$0
$88
$38
$0
$17
$0
$9
ERR
-36.52
$63
$18
$0
$0
$0
$12
$44
$32
$9
$0
$32
$11
$2
$20
$32
1
0
29
$88
$63
$32
$13
$0
$0
Year
18
0
365
0
$26.07
0
1
M
20
$3.02
$0
$62
$62
$0
$12
$0
$6
ERP
-52.59
$44
$18
$0
$0
$0
$0
$25
$25
$6
$0
$25
tl
$1
$16
$16
1
u
20
$62
$44
$lt>
$10
$0
$0
''ear
19
o
365
i;
$2o.'r
.;,
l
14
$3.02
$0
$43
$43
$0
$8
$0
$4
EPR
-75.56
$31
$18
$0
$0
$0
$0
$12
$12
$4
$0
$12
$4
$1
$3
SE
i
0
14
J43
$3!
$6
15
$0
JO
rear
''•'
i'l
3o5
;<
ili.v7
'",
-------
Price Per NCF;
$3.02 $3.02 $3.02 $3.02 $3.02
$3.02 $3.02 $3.02 $3.02
[1 Revenues '$000):
Gas Revenues ($000);
Total Revenues ($000);
Royalty Payaents-Qii ($000):
Royalty Paytents-fias i*000):
Severance Taxes-Oil ($000);
Severance Taxes-Bas ($000):
ELF for Alaska Severance Taxes-Oil
ELF for Alaska Severance Taxes-Sas
Net Revenues($000):
Operating Costs:
Expensed Poll.Cont.Cap.Costs <*000)
Pollution Control Operating Costs:
For PV Poll. Control:
Depreciation i Aiortuation:
Operating Earnings '$000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
arnings Before Interest After Tax:
let [ash Flow;
Shutoff"
Actual Oil Prod./Year (Barrels):
Actual 6as Prod./Year <«HCF):
Actual cross Revenues ($000):
Actual Net Revenues '$000):
Actual Net Cash Flow i*000':
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Der Day:
Days of Production Per fear:
Barrels Oil Per fear:
Pnce Per Barrel:
10
$30
$30
$0
$6
$0
$3
: 0.00 0
: -108.38 -155
$22
$18
) $0
$0
$0
$0
$3
$3
$3
*0
: $3
$1
$0
: $2
$2
1
0
10
$30
$22
$2
$1
*0
*0
Year Year
21
OIL PRODUCTION
i)
365
$0
$21
$21
$0
$4
$0
$2
.00
.25
$15
$16
$0
$0
$0
$0
($3)
($3)
$2
$0
($3)
(*li
($0)
($2)
(*2)
0
0
0
$0
$0
$0
$0
$0
$0
">?
0
365
to
$15
$15
$0
$3
$0
$1
0.00
-222.22
$11
$18
$0
$0
$0
$0
(*8/
($8)
$1
$0
($3)
•$3)
($0)
($5!
i*5)
0
0
0
*0
$0
$0
$0
$0
$0
Year
:3
h
3o5
$0
$10
$10
$0
$2
$0
$1
0.00
-317.88
$7
$18
$0
$0
$0
$0
($11)
($11)
$1
$0
i*lD
($4)
($11
($7)
($71
0
0
0
$0
$0
$0
$0
$0
*0
rear
24
0
365
$0
$7
$7
$0
$1
*0
$1
0.00
-454.54
$5
$18
$0
$0
$0
$0
($13)
($13)
$1
$0
(*13)
($5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
*0
$0
$0
Vear
25
0
365
$0
$5
$5
$0
$1
$0
$1
0.00
-649.78
$4
$18
$0
$0
$0
$0
(*15)
(*15)
*1
$0
i*15)
!*5)
(*1)
(*9)
($9)
0
0
0
$0
$0
$0
$0
$0
$0
Year
26
0
365
$0
$4
$4
$0
$1
$0
$0
0.00
-928.68
$3
$13
$0
$0
$0
$0
($16)
($16)
$0
$0
($16)
($5)
($1)
($10)
(*10)
0
0
0
$0
$0
$0
$0
$0
$0
Year
27
0
365
$0
$2
$2
$0
$0
$0
$0
0.00
-1327.11
$2
$13
$0
$0
$0
($17)
($17)
$0
$0
($17)
($6)
($1)
($10)
1*10)
,;,
0
0
$0
$0
$0
$0
$0
10
Year
28
0
365
$0
$2
$2
$0
$0
$0
$0
0.00
-18*6.31
$1
$13
$0
$0
$0
($17)
($17)
$0
$0
($17)
(*6)
(*D
(*lli
($11)
i)
u
Ij
$0
$0
$0
$0
$0
$0
Year
2'
1*1
3&5
$0
$1
$1
$0
$0
$0
$0
0.00
-2709.44
$1
$13
to
$0
$0
i*18)
($18)
$0
$0
t$18i
($6)
i$li
i*12)
1*1:.
i ;
o
0
$0
$0
$0
$0
$0
$0
Year
30
M
3i5
0 0 0 0 0
$26.07 $26.07 $26.07 $2o.07 $26.07
0000
$26.07 $26.07 $26.07 $26.07
HMCF Sas Per Day:
MHCF 3as Per Year:
Price Per MCF;
6AS PRODUCTION
0 0
0 0
$3.02 $3.02
u
0
$3.02
0 0 0 0 0 ii
0 0 0 0 0 0
$3.02 $3.02 $3.02 $3.02 $3.02 *!.;2
-------
JO
Jl
$1
JO
JO
JO
JO
0.00
JO
$1
Jl
JO
JO
JO
JO
0.00
JO
JO
JO
JO
JO
JO
JO
0.00
JO
JO
JO
JO
JO
JO
JO
0.00
JO
JO
to
$0
JO
JO
JO
0.00
JO
JO
JO
JO
JO
JO
JO
0.00
JO
JO
JO
JO
JO
JO
JO
0.00
JO
JO
JO
$0
JO
JO
$0
0.00
$0
JO
JO
JO
$0
JO
JO
0.00
JO
JO
JO
$0
JO
JO
JO
0.00
1 Revenues ($000):
is Revenues (*000):
ital Revenues ($000):
Royalty Payients-Qil '$000!:
Foyalty Paynents-Sas ($000):
Severance Taxes-Oil p'$000i;
Severance Taxes-Gas ($000):
EL*7 for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas: -3871.05 -5530.50 -7901.15 *»*+*************» -23037.33 ******»***+****«*»***********»*****
Net Revenues($0001; $1 $0 JO $0 $0 $0 $0 $0 $0 $0
Operating Costs: $18 $18 $18 J18 J18 J18 $18 $18 $18 $18
Pollution Control Operating Casts: $0 $0 JO $0 $0 JO $0 $0 JO $0
For PV Poll. Control: $0 JO JO JO $0 $0 $0 $0 $0 JO
Depreciation I Aiortization:
Operating Earnings (JOOO): ($18) i$18i ($18) ($18) ($18) ($18) ($18) ($18) ($18) i$iS)
Earnings Before Interest and OCA: ($18) ($18) ($18> ($18) ($18) ($18) ($18) ($18) ($18) i$18)
Depletion Allowance: $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Surplus Depletion: $0 $0 $0 $0 $0 $0 $0 $0 $0 JO
Earnings Before Interest and Taxes: ($18) i$18) ($18; ($6) ($61
State Tax: l$l.> ($1) <$i) ($1) ($1) ($1) ($1) i$li i$l) i$H
Earnings Before Interest After Tax: ($11) ($11) iJll) ($11; ($11; ($11) ($11; t$lli ($11; -$12)
Net Cash Flow: ($11) i$lD ($11; i$ll) ($11) i$ll) ($11) ($11) >$!!! 'Ji:>
Shut off 0 0 0 0 0 0 0 0 ') :
Actual Oil Prod..'fear "Barrels': 0 0 0 0 0 0 0 0 0 0
Actual Gas Prod./Year
-------
PV at Net Casi F1QW5: $1,214
_PV of Excess Depletion: $0
of Surplus Depreciation: $0
PV 3* Expensed Invest Cash Flows: $56i
FV at Capitalized Costs: $270
PV of Leasehold Cost: $244
PV =oll. Cont. Casts: $0
FV of Royalties -Oil: $0
PV of Royalties - Gas: $262
PV of Severance Taxes - Oil: $0
F'V of Severance 'axes - Bas: $140
PV of Operating Costs: $66
F'V of Incase Taxes: $644
PV of Total Coipany Costs: $2,187
FV of Total Company Costs - Oil: $0
PV of Total Cospany Costs - Bas: $2,187
Anortized Coipany Cost per HHBTU: $2,32
Aiortized Coipany Cost per bbl: ERR
Amortized Coipanv Cost per ffCF: $2.36
Wellhead Price on MHBTU basis - Oil $4.49
Wellhead Price on MMBTu basis - Sas $2,96
?V Equiv. of Oil Prod.(bb): 0
?V EQUIV. of Gas iMHCF;: 925
F'V Equiv, of Prod, irtHBTU): 944,182
Net Present Value of Projec $139
Internal Rate of Return: 0.133
Frobabie ROR: 0.5
Annuahzed Poll.Cont.Costs: $0
FV of Social Costs - Total: $1,276
Amortized Social Cost/HHETU $1.35
F'V of Social Costs - Oil: $0
Auertized Social Cost/bbl: ERR
FV of Social Costs - Sas: $1,276
..Amortized Social Cost/HCF: $1.38
-------
Run Date: 2
-------
Total Annual Capital Cost: $45 $0 $0 $0 $0 $0 $0 10 $0 $0
Tax Shield: $6 $0 $0 $0 $0 $0 $0 *0 $0 $0
;.pensed Cash Flow: $12 $0 $0 $0 $0 $0 10 $0 fO $0
,pitah:ed Cash Flan: $26 $0 $0 $0 $0 $0 $0 $0 $0 10
F'V of All Developaent Costs: $45
F'V of Expsnsed Bevelopient Costs: $12
F'V of Capitalized Developient Costs: $26
FINANCIAL RATES
Percent Water Cut in 0&6 to Start: 21
Qu/Bas Prod. Decline Rate/Year (X) 68X
Cost Escalator HJ: 01
Royalty Rate (X): 12.SOX
Federal Tax Rate >.X): 34X
State Tax Rate (X!: 4X
Average Depreciation Life (years): 7
Deprec. rate ieach year): 14.29X 24.49'i 17.49X 12.49X S.93X S.92X 8.93X M6X
State Severance Tax Rate-Oil: O.OOX
(If Alaska enter 99)
State Severance Tax Rate-Sas: O.OOX
(If Alaska enter 99)
PRODUCTION COSTS
'''ears Between Start of Developaent
and Start of Production i-,5!: 1
Nutber of '"ears at Peak Prod: 1
Oil Peak Prod. Rate/Well(bb): 12
Gas Peat Prod. Rate/Well(NNCF/D): 0.016
Number of Producing hells: 1
Nuiber of Hells Put in Service/Year 1
Price of Oil Per Barrel: $26.25
Price of Sas Per HCF: $3.09
Total Operating Costs ($000i: $7
Fell Cont Doer Costs ($000): $0
Davs of Production Per Year: 365
Year Year Year 'ear tear Year fear 'ear year rear
12345 6 7 8 = 10
OIL PRODUCTION
Producing Weils in Service: 1 0 0 0 0
Barrels of Oil Per Day: - 12 3 6 4 3 2111
Days cf Production Per /ear: 365 365 3e5 365 365 365 365 365 3e5
Barrels of Oil Per Year: 4380 2978 2025 1377 937 &37 433 294 ZOO
Price/Barrel of Oil: $26.25 $26.25 $26.25 $26.25 $26.25 $26.25 $26.25 $26.25 $26.25
SA5 PRQDUCTIC
-------
flNCF of Sas Per Day:
HMCF of Gas Per rear:
rice'HCF of Gas:
Annual Oil Revenues ($000):
Annual Sas Revenues ($000):
Total Revenues ($000):
Royalty Payaents-Oil ($000):
Royalty Payients-Sas ($000):
Severance Taxes-Oil ($000!:
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-6as:
Net Revenues 1*000):
Total Operating Costs ($000):
Expensed Poll.Cont.Cap.Costs ($000)
Poll.Con.Operating Costs ($000):
Capitalized Costs ($000):
Depreciation 4 Amortization ($000):
Operating Earnings ($000):
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
^Federal Tax:
State Tax;
Earnings Before Interest After Tax:
Net Cash Flow:
ShutofP
Actual Gil Prod./Year (Barrels):
Actual Sas Prod./Year (MHCF):
Actual Brass Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Ta*es Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year;
Barrels Oil Per Year:
Price Per Barrel:
M»CF Gas Per Day:
MHCF Gas Per rear;
0
6
$3.09 $3
1115
$18
$133
$14
$2
$0
$0
: ERR
: -186.50 -274
$116
$7
) $0
$0
$97
: $14
$110
$96
$1
$0
: $95
$32
$4
: $59
$74
1
4380 2
6
$133
$116
$74
$36
$0
$0
Year Year
11
OIL PRODUCTION
o
365
'3
$26.25 $26
SA5 PRODUCTION
0
0
0
4
.09
$78
$12
$90
$10
$2
$0
$0
ERR
.74
$79
$7
$0
$0
$0
$24
$73
$49
$1
$0
$48
$16
$2
$30
$54
1
l
978
4
$90
$79
$54
$18
$0
$0
12
0
365
63
.25
0
0
')
-
$3.09
$53
$8
$62
$7
$1
$0
$0
ERR
-404.49
$54
$7
$0
$0
$0
$17
$47
$30
$0
$0
$30
$10
$1
$19
$3o
I
2025
7
j
$62
$54
$36
$11
$0
$0
Year
] "T
0
365
43
$26.25
i)
0
!)
T
J_
$3.09
$36
$6
$42
$5
$1
$0
$0
ERR
-595.31
$37
$7
$0
$0
$0
$12
$30
$18
$0
$0
$18
$6
$1
$11
$23
1
1377
T
$42
$37
$23
$7
$0
$0
Year
14
0
365
29
$26.25
0
0
(l
1
$3.09
$25
$4
$18
$3
$0
$0
$0
ERR
-875.93
$25
$7
$0
$0
$0
$9
$18
$10
$0
$0
$10
$3
$0
$6
$15
1
937
1
$28
$25
$15
$4
$0
$0
Vear
15
0
365
20
$26.25
u
o
0
1
$3.09
$17
$3
$19
$2
$0
$0
$0
ERR
-1288.61
$17
$7
$0
$0
$0
$9
$10
$2
$0
$0
$2
$1
$0
$1
$10
1
637
1
$19
$17
$10
$1
$0
$0
Year
16
0
365
13
$26.25
0
0
0
1
$3.09
$11
$2
$13
$1
$0
$0
$0
ERR
-1895.48
$12
$7
$0
$0
$0
$9
$5
($4)
$0
$0
($4)
i.$l)
($0)
($2)
$6
1
433
1
$13
$12
$6
($1)
$0
$0
Year
17
0
365
9
$26.25
0
o
0
0
$3.09
$8
$1
$9
$1
$0
$0
$0
ERR
-2787.94
$6
$7
$0
$0
$0
$4
$1
($3)
$0
$0
($3)
($1)
($0)
i$2)
$2
1
294
0
$9
$8
$2
($1)
$0
$0
Year
18
0
365
6
$26.25
0
0
o
u
$3.09
$5
$1
$6
$1
$0
$0
• $0
ERR
-4100.38
$5
$7
$0
$0
$0
$0
($1)
($1)
$0
$0
($1)
( $0 '/
i$0)
i*l;
!$!''
•)
u
0
$0
$0
$0
$0
$0
$0
'fear
19
0
365
4
$26.15
,-,
;)
'}
o
$3.09
$4
11
$4
$0
$0
$0
$0
ERR
-6030.44
$4
$7
$0
$0
$0
$0
($3)
($31
$0
$0
i$3i
!$ll
<$0i
•$Zi
!$:.•
0
'J
u
$0
$0
$0
$0
$0
$0
rear
~fi
; t
7:>3
-
$25.25
-------
Price Per flCF;
$3,09 $3.09 13.0? $3.0? $3.09
$3.09 $3.09 $3.0? $3.0;
Jil Revenues ($000):
PIS Revenues '$000);
Total Revenues ($000):
Royalty Payients-Oii ($000):
Royalty Payaents-Bas i$000):
Severance Taxes-Oil ($0001:
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Sas:
Net Revenues ($000):
Operating Costs:
Expensed Poll. Cont. Cap. Costs ($000/
Pollution Control Operating Costs:
For FV Poll. Control:
Depreciation 4 Amortization:
Operating Earnings t$000):
Earnings Before Interest and ODA:
Depletion Allowance;
Surplus Depletion:
Earnings Before Interest ard Taxes:
Federal Ta*:
State Tax;
Earnings Before Interest After Tax:
Wet Cash Flow:
ShutofP
Actual Oil Prod. /Year (Barrels):
Actual Gas Prod. /Year (CHCFl:
Actual Brass Revenues '$000;:
Actual Net Revenues ($000) :
Actual Net Cash Fie* ($000):
Actual Ta/es Paid <$000):
Capitalized Costs Not Expended:
Eurplus Depreciation:
Barrels Oil Per Dav;
Da/s at Production Per Year;
Barrels Oil Per Year;
Price Per Barrel;
$2
$0
$3
$0
$0
$0
$0
0.00
-5668.77 ****
$2
$7
$0
$0
$0
$0
i $4)
($4)
$0
$0
($4)
($1)
i$0!
($3)
($2!
0
0
o
$0
$0
$0
$0
$0
$0
Year Year
21
OIL PRODUCTION
o
JU J
1
$26.25 $2
$2
$0
$2
$0
$0
$0
$0
0.00
*****
$2
$7
$0
$0
$0
$0
($51
($5)
$0
$0
($5)
($2)
($0)
($3)
($3)
0
0
0
$0
$0
$0
$0
$0
$0
•n
0
365
1
6.25
$1
JO
$1
$0
$0
$0
$0
0.00
**********
$1
$7
$0
$0
$0
$0
($5)
($5)
$0
$0
($5-
($2)
i$0>
($3)
($3)
0
0
0
$0
$0
$0
$0
$0
$0
year
-~-
o
^ fc S
JUU
1
$26,25
$1
$0
$1
$0
$0
$0
$0
0.00
*********
$1
$7
$0
$0
$0
$0
($6)
!$6i
$0
$0
($6i
($2i
($01
($41
i$4)
0
0
0
$0
$0
$0
$0
$0
$0
• ear
24
0
365
1
$26.25
$1
$0
$1
$0
$0
$0
$0
0.00
*********
$1
$7
$0
$0
$0
$0
i$6)
($6)
$0
$0
i$6)
($2)
($0)
($4)
($4)
0
o
o
$0
$0
$0
$0
$0
$0
Year
25
y
365
0
$26.25
$0
$0
$0
$0
$0
$0
$0
0.00
-61004.30
$0
$7
$0
$0
$0
$0
($6!
($61
$0
$0
($6)
($2)
($0!
($4)
($4)
0
0
0
$0
$0
$0
$0
$0
$0
Year
26
0
365
0
$26.25
$0
$0
$0
$0
$0
$0
$0
0.00
**********
$0
$7
$0
$0
$0
$0
($6;
($6)
$0
$0
($6)
($2)
($0)
($4)
($4)
0
0
0
$0
$0
$0
$0
$0
$0
year *
27
0
365
0
$26.25
$0
$0
$0
$0
$0
$0
$0
0.00
********
$0
$7
$0
$0
$0
($6)
($61
$0
$0
($6)
($2)
($0)
($4)
($41
0
0
0
$0
$0
$0
$0
$0
$0
ear
28
0
365
0
$26.25
$0
$0
$0
$0
$0
$0
$0
0.00
**********
$0
$7
$0
$0
$0
($6)
($6)
$0
$0
($6!
($2)
($(V
($4;
•$4i
ij
•')
•'i
$0
$0
$0
$0
$0
$0
Tear ''
;q
0
365
0
$26.25
$0
$0
$0
$0
$0
$0
$0
0.00
********
$0
$7
$0
$0
$0
!$oi
($61
$0
$0
1$6)
($2;
($0)
•$4i
'"'
o
$0
$0
$0
$0
$0
f l'(
e-r
30
I
7-5 j
J
$26.1!
F Sas Per Day:
1HCF Gas Per 'rear;
P'ice Per KCF:
5AS PRODUCTION
0 0 (.1 0
$3.09 $3.09 $3,09 *3.0
-------
Oil Revenues ($000):
"as Revenues i*000):
ital Revenues '.$000):
Royalty Payaients-Qil ($000):
Royalty Fayaents-Sas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-6as ($000):
ELC for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Sas:
Net revenues 1*000);
Operating Costs:
Pollution Control Operating Costs:
For PV Foil. Control:
Depreciation i Aiortizatian:
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
Net Cash Flow:
Actual Oil Prod.,'Year (Barrels):
Actual Gas Prod./'ear (MHCF):
Actual Brass Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow i*000':
Actual Ta;es Paid '$000):
$0
$0
$0
$0
$0
$0
$0
0.00
, JL*Jt Jt JL AX
TTTTTTTK
$0
$7
$0
*0
t$6)
($6;
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i $6i
($2;
1*0)
i*4)
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0
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10
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, X JL Jt Xi Jt Jt
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0
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,JLJLJliAiJiJvJL
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$0
$7
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($4)
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1 a A it E JL A
rTTlrirT T
$0
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$0
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«;.
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$0
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1*01
•*4i
•J4,
10
-------
PV of Net [as* Flaws: $162
PV cf E'-cess Depletion: $0
of Surplus Depreciation: $0
PV at" Expensed Invest Cash Flows: $78
PV of Capitalized Costs: $97
Fv of Leasehold Cost: $2
FV -oil, Cont. Costs: $0
PV of Royalties - Oil: $18
FV of Royalties - 8as: $3
FV cf Severance Taxes - Oil: $0
F'V of Severance Taxes - Sas: 10
PV of Operating Costs: $19
PV of Incoae Taxes: $65
PV of Total Cotpany Costs: $281
FV of Total Coipany Costs - Oil: $243
PV of Total Coapany Costs - Bas: $38
Atortized Company Cost per MMBTU: $3.67
Amortized Coipany Cost per bbl: $22.72
Amortized Coipany Cost per MCF: $2.67
Wellhead Price on HHBTU basis - Oil $4.53
Wellhead Price on MMBTU basis - Sas $3.03
FV Equiv, of Oil Prod.(bb): 10,680
FV Equiv. o* Gas (MMCF): 14
PV Equiv. of Prod. (HHBTU): 76,480
Net fresent Value of Projec $5
Internal Rate of Return: 0.092
Frooable ROR: 0,5
Annuaiized Poll.Cont.Costs: $0
PV of Social Costs - Total: $234
Amortized Social Cost''MMBTU $3.06
PV cf Social Costs - Oil: - $202
Amortized Social Cost/bbi: $18.96
FV of Social Costs - Sas: $32
Asortized Social Cost/MCF: $2.23
-------
Run Sate: 29-ftpr-S7
Project Type: Region 5 - single oil well
lase Cost: $2
B&G Expense: 58.30Z
Leasehold Cost: $2
Real Discount Rate: 8,002
Years Between Lease Sale
and Start of Explor.: 0
Percent Costs Considered IDC's: 60.00Z
Percent Costs Expensed: 60.002
Drilling Mud Cost Increaent: O.OOZ
Corporate Tax Rate: 342
State Corporate Tax Rate: 4.00X
Carp Structure (l-iajor/2-indep): 2
EXPLORATION COSTS
Cost Per Exploratory Hell: $122
Drilling Mud Cost Increaent: $0
Discovery Efficiency: 0.72
Successful Expl. Hell: 1
Year Year Year fear
0123
Explor. Costs Per Project: $170 $0 10 $0
Jost of Successful Efforts: $122 $0 $0 $0
Expensed Costs: $121 $0 $0 $0
Expensed Cash Flows: $80 $0 $0 $0
Capitalized Casn Flows: $49 $0 $0 $0
FV of Expensed Exploration Cash Flows: $80
FV of Capitalized Expi. Cash Flows: $49
Total Capitalized Espl. Costs: $49
Pv of all E>ploratory Costs: $170
DEVELOPMENT COSTS
Tatal Infrastructure Cost: $45
'ears Between Start of Exploration
and Start of Develop*ent: 0
Number of Hells Drilled: 0
Nuaber Hells Drilled Per Year: 0
Drilling Cost Per Hell: $0
Drilling Cost Per Hell:
Drilling Mud Cost Increment:
kNuaber at Hells Drilled:
Total Drilling Costs for Year:
Annual Infrastructure Cost:
Arnual Foil Cont Capital Costs:
fear
Year
0
$0
$0
0
$0
$45
$0
Year
1
$0
$0
0
$0
$0
$0
'ear
$0
$0
o
$0
$0
$0
Year
3
$0
$0
0
$0
$0
$0
Year
4
$0
$0
0
$0
$0
$0
Year
5
$0
$0
0
$0
$0
$0
fear
6
$0
$0
0
$0
$0
$0
tear
7
$0
$0
V
$0
10
$0
fear
3 ;
$0 JO
$0 *0
1!
10 £ "•
$11 Jl
$.' $.
-------
Total Annual Capital Cost; $45 10 $0 $0 10 $0 $0 $0 $0 »0
Tax Shield: $9 $0 $0 $0 $0 $0 $0 $0 $0 *0
.xpensed Cash Flow: 118 $0 *<) $0 10 10 10 $0 $0 10
"pitah:ed Cash Flo*: 118 10 $0 10 $0 $0 $0 $0 $0 10
FY of All Developaent Casts: $45
PV of Expensed Development Costs; $16
FV of Capitalized Developnent Costs: $18
FINANCIAL RATES
Percent Water Cut in OfcS to Start: 21
Oil/Gas Prod. Decline Rate/Year (X) 682
Cost Escalator (2): 02
Royalty Rate (X>: 12.507.
Federal Tax Rate d): 342
State Tax Rate (21: 42
Average Depreciation Life (years): 7
Deprec. rate (each year): 14.292 24.49? 17.492 12.492 8.932 B.92X 8.932 4.462
State Severance Tax Rate-Oil: 0.002
(H Alaska enter 99)
State Severance Tax Pate-Sas: 0.002
(If Alaska enter 99)
PRODUCTION COSTS
years Between Start of Deveiopsent
and Start of Production <-5): 1
Nuiber of fears at Peak Prod; 1
Gil FeaJ Pra3. Rate/Well (bb): 12
Sas Peak Prod. Rate/Well (MNCF/D): 0.016
Nunder of Producing Wells: 1
Nuaber of Wells Put in Service/Year 1
:'rice of Oil Per Barrel: $26.25
Frice of Sas Per MCF: $3.09
Tctal Operating Costs ilQGO): $7
Poll Cont Oper Costs ($000): $0
Days of Production Per Year: 365
Producing Wells in Service:
Barrels of Oil Per Day:
Days of Production Per Year:
Barrels of 0:1 Per Year:
Price/Barrel of Oil-
Year Year
1
OIL PRODUCTION
1
12
365
4380 2
$26.25 $26
-
0
8
365
^
6AS PRODUCTION
-------
HHCF of 5as Per Day:
of Sas ?sr Year:
-ice'HCF cf Sas:
Annual Oil Revenues ($000):
Annual Sas Revenues ($000):
Total Revenues ($000):
Royalty Payserts-Oii i$000i;
Rcyaity F'aynents-Sas ($000;:
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Ta*es-6as:
Net Revenues '$000!:
Total Operating Costs ($000):
Expensed Foil, Cent. Cap. Costs ($000)
foil. Con. Operating Costs ($000;:
Capitalized Costs ($000);
Depreciation 4 Aacrtization <$000):
Operating Earnings i*OOQ):
Earnings Before Interest and ODA:
Depletion allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Ta.x;
ptate Tax:
''Earnings Before Interest After Tax:
Net Cash Flan;
Shutoff
Actual Oil frad. "fear 'Barrels';:
Actual Gas Prcfl.'Year iMKCF):
Actual Brass Revenues i$000i:
Actual Net Revenues ''$0001:
Actual Net Cash Flow ($000);
Actual Ta>es Paid ($000):
o
&
$3.09
$115
$18
$133
$14
$2
$0
$0
ERR
186.50
$116
$7
$0
$0
$67
$10
$110
$100
$15
$0
$100
$34
$4
$62
$72
1
4380
6
$133
$116
$72
$33
0
4
$3.09
$78
$12
$90
$10
$2
$0
$0
ERR
-274.74
$79
$7
$0
$0
$0
$16
$73
$56
$10
$0
$56
$19
$2
$35
$51
1
i
2978
4
$90
$79
$51
$21
0
•*
$3.09
$53
$6
$62
$7
$1
$0
$0
ERR
-404.49
$54
$7
$')
$0
$0
$12
$47
$36
$7
$0
$35
$12
$1
$22
$34
j
2025
j
$62
$54
$34
$13
j
i.
$3.09
$36
$6
$42
$5
$1
$0
$0
ERR
-595.31
$37
$7
$0
$0
$0
$8
$30
$22
$5
$0
$22
$7
$1
$13
$22
1
1377
"i
$42
$37
$22
$8
o
1
$3.09
$25
$4
$28
$3
$0
$0
$0
ERR
-675.93
$25
$7
$0
$0
$0
$6
$18
$12
$3
$0
$12
$4
$0
$8
$14
1
937
1
$28
$25
$14
$5
0
1
$3.09
$17
$3
$19
$2
$0
$0
$0
ERR
-1288.61
$17
$7
$0
$0
$0
$6
$10
$4
$2
$0
$4
$1
$0
$3
$9
1
i
&37
1
$19
$17
$9
$2
0
1
$3.09
$11
$2
$13
$1
$0
$0
$0
ERR
-1895.43
$12
$7
$0
$0
$0
$6
$5
($1)
$2
$0
t$l)
i*0i
i*0)
1*1)
$5
1
433
1
$13
$12
$5
i$0<
0
0
$3.09
$8
$1
$9
$1
$0
$0
$0
ERR
-2787.94
$3
$7
$0
$0
$0
$3
$1
'$2)
$1
$0
($2!
i*li
($0)
!$li
$2
j
294
0
$9
$8
$2
i$D
1 i
(J
$3.09
$5
$1
$6
$1
$0
$0
$0
ERR
-4iOO,38 -&
$5
$7
$0
$0
$0
$0
($1)
1*1)
$1
$0
!$ii
i$0
($0'
!'$!''
l$l'
o
o
0
$0
$0
$0
$0
lj
$3.09
$4
$1
$4
$0
$0
$0
$0
ERR
030.44
$4
$7
10
$0
$0
$0
(*3i
($3i
$0
$0
'$3i
•$!'
• $o<
$Zi
!$2'
.;<
$•:•
$0
$0
$'"•
Capitalized Casts Not Expended:
Surohs Depreciation:
$0 $0 $0 $0 $0 $0 $0 $0 $0
$0 $0 $0 $0 $0 $0 $0 $0 $•)
$•;•
Year Year »ear •'sar Vear rear rear r'ear vear
11 12 ;3 14 15 16 17 18 19
OIL PRODUCTION
Barrels Oil Fer Day;
Days of FrQUucuon ?er rear;
Barrels Oil fer 'ear:
Price Fer Barrel:
0 0 0 0
3o5 365 3&5 365
93 63 43 29
$26.25 $26.25 $2o.Z5 $26.25
0
365
20
$2o,25
o o o >>
365 365 365 3s5 :
13 9 6 4
$26.25 $26.25 $26.25 $26.25 $2i.
5AS PRODUCTION
MfCF 5as -er Day:
-------
Fries Per HCF:
$3.09 $3.Of 13,09 $3.0? $3.09
13.09 $3.i
«I Revenues '$000):
is Revenues t*000):
Total ^e^enues $000' :
Royalty Payaents-Oil '.tOOO):
Royalty Payments-Gas ($000);
Severance Taxes-Oil i$000i:
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas;
Net Revenues ($000):
Operating Costs:
Expensed Poll. Cont. Cap. Costs ($000)
Pollution Control Operating Costs:
For FV Poll. Control:
Depreciation 4 Aaortization:
Operating Earnings ($000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
^Net Cash Flow;
Shutoff
Actual Oil Prod. /Year (Barrels):
Actual Gas Prod, /Year (HHCFi:
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow 1*000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels Oil Per Year:
Pace Per Barrel:
^
^^ HHCF Gas Per Day:
HHCF Gas Per r'ear:
Price Per MCF;
$2
to
$3
$0
$0
$0
$0
0.00 0
-3866.77 *****
$2
$7
$0
$0
$0
$0
($4)
($4)
$0
$0
($4)
(*1)
($0;
($3)
!*2)
0
0
0
$0
$0
$0
*0
*0
*0
Year Year
21
OIL PRODUCTION
0
365
1
i.
$26.25 $26
GAS PRODUCTION
0
0
$3.09 $3
$2
$0
$2
$0
$0
$0
$0
.00
***!
$2
$7
10
$0
$0
$0
($5)
($5)
$0
$0
($5)
($2)
($0!
($3)
t*3)
0
0
0
$0
$0
$0
$0
$0
$0
22
0
365
1
.25
0
0
.09
$1
$0
$1
$0
$0
$0
$0
0.00
**********
$1
$7
$0
$0
$0
$0
i$5)
($5)
$0
$0
($5)
($2)
($0)
($3)
'$3)
0
0
0
$0
$0
$0
$0
$0
$0
Year
i-
o
365
1
$2o,25
0
0
$3,09
$1
$0
$1
$0
$0
$0
$0
0.00
*********
$1
$7
$0
$0
*0
$0
($6)
($6)
$0
$0
($6)
($2)
($0)
($4)
($4)
0
0
0
$0
$0
$0
$0
$0
$0
'ear
24
0
365
1
$24.25
0
0
$3.09
$1
$0
$1
$0
$0
$0
$0
0 . 00 0
********* -61004
$1
$7
$0
$0
$0
$0
($6)
(*6i
$0
$0
1*6)
($2)
($0)
(*4)
f$4)
(i
0
0
$0
$0
$0
$0
$0
$0
tear Year
25 •
0
365
0
$26.25 $26
0
0
$3.09 $3
$0
$0
$0
$0
$0
$0
$0
. 00
.30
$0
$7
$0
$0
$0
$0
($6)
(*6!
$0
$0
($6!
($2)
($0)
($4)
($4)
0
0
0
$0
$0
$0
$0
$0
$0
26
0
365
0
.25
0
0
.09
$0
$0
$0
$0
$0
$0
$0
0.00
*********
$0
$7
$0
$0
$0
$0
1*6)
(*6)
*0
$0
($6)
($2)
($0)
($4)
($4)
0
0
0
$0
$0
$0
$0
$0
$0
rear
27
0
365
0
$26.25
o
0
$3.09
$0
$0
$0
$0
$0
$0
$0
0.00
*********
$0
$7
$0
$0
$0
($6)
l $6)
$0
$0
i$6i
t*2)
($0i
(*4i
($4)
0
0
tj
$0
$0
$0
$0
$0
$0
tear
23
0
365
0
$16.25
0
0
$3.09
$0
to
$0
*ii
$0
$0
$0
0.00
********41
$0
$7
$0
$0
$0
($6)
1*6)
$0
$0
($6)
($2)
($0)
<$4f
o
0
SJ
$0
$0
$0
$0
$0
$0
'ear
Zv
u
3fc5
0
$2i.25
i,
|7. v5
$0
$0
$0
$c
i'j
$0
$0
0, 00
tt******t
$0
$T
$0
$0
$0
($01
•to;
$0
$0
($0'
i $2i
iiO!
•Hi
• IJ.
{•:•
JM
$0
$0
to
r •
rp.r
"* i"j
:::
*Z.,Z<:
$3. :
-------
Oil Revenues I'tOOO):
s Revenues 1*000):
tal Revenues (tOOO/:
Royalty Payments-Oil itOOO):
Royalty Pay«ents-6as (tOOO):
Severance Taxes-Oil (tOOO):
Severance Taxes-Sas itOOOi:
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Sas:
Net RevenuesftOOO):
Operating Costs:
Pollution Control Operating Costs:
For PV Poll. Control:
Depreciation 4 Aiorti:ation:
Operating Earnings (tOOO):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax;
Earnings Before Interest After Tax:
Net Cash Flow:
utoff?
ictua! Oil Prod,/Year 'Barrels):
Actual Gas Prod./rear fMMCF);
Actual Gross Revenues 'tOOOi:
Actual Net Revenues (tOOO):
Actual Net Cash He* (tOOO):
Actual Taxes Paid itOOOl;
tO
$0
$0
$0
10
$0
tO
0.00
^4HHHHH
10
$7
$0
$0
1*6)
($6)
*0
to
t*6)
($2)
itO)
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.$4)
o
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(
tl
tO
$0
to
to
$0
10
to
to
to
to
0.00
Jt X Jt & £ A 4 4 •)
•frTTTTTTTt
to
17
to
to
(*6!
($6)
to
to
($6)
(t2)
i*0)
(t4)
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0
0
0
to
to
to
to
to
to
to
to
to
to
to
0.00
ji ji « a a a x i J
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to
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to
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(t6)
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to
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($4)
0
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u
to
to
to
to
to
to
to
to
to
to
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0.00
•K ima *j
T XTTTTlTl
to
17
to
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(16)
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0
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0
to
to
to
to
to
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to
to
to
to
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0.00
JLJtXi JL JL J
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to
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to
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to
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(*6)
(*6)
to
to
(t6)
($2)
itO)
1*4)
<*4)
0
0
0
to
to
to
to
to
to
to
to
to
to
to
0.00
AJLiJLiJtiiJL
TTTTTTTTT
to
t7
to
to
i.t6)
1*6)
to
to
(*6)
(*2)
itO)
(*4i
(*4)
0
0
0
to
to
to
to
to
to
to
to
to
to
to
0.00
XJIJLJLJIJI.JLJLJL
Tf"f TTTTTT
to
*7
to
to
1*6)
(*6)
to
to
1*61
($21
ttOi
(t4)
i*4l
&
0
0
to
to
to
to
to
to
to
to
to
to
to
0.00
jjtA**Jt*JlJl
TTwTTTTTT
to
*7
to
to
iti.'
1*6)
to
to
1*6)
ttZ)
i*0)
1*4)
i*4 "'
i_'
0
0
to
to
to
to
to
to
to
10
to
to
to
0.00
Jt i » J 1( H V
Tt TTTfTW T
to
t/
to
to
(*6;
1*6)
to
to
(t6)
i*2)
i*0)
(t4i
't4i
n
0
:j
to
to
$0
to
-------
PV of Net Cash Flows: $173
Pv of Excess Depletion: $0
J'V of Surplus Depreciation: $0
FV of Expensed Invest Casn Flows: $98
PV at Capitalized Costs: $67
FV of Leasehold Cost: $2
FV poll. Cont, Costs: $0
PV of Royalties - Oil: $!8
PV of Royalties - Bas: 13
PV of Severance Taxes - Oil: $0
PV of Severance Taxes - Sas: $0
PV of Operating Costs: $19
PV of Incoie Taxes: 173
PV of Total Coipany Costs: $279
PV of Total Coapany Costs - Oil: 1241
PV of Total Company Costs - Sas: $38
Amortized Company Cast per M1BTU: $3.65
Aiortized Company Cost per bbl: $22.40
Aiortized Coipany Cost per NCF; $2.66
Wellhead Price on MHBTU basis - Oil $4.53
Heiihead Price on HHETU basis - Sas $3.03
FV Eqinv. of Oil Prod,«'bb): 10,660
PV Equiv. 3f Sas iMMCFi: 14
PV Equiv. of Prod. (MHBTU): 76,480
Net Present Value of Projec $6
Internal Rate of Return: 0.097
Frooadle ROR: 0.5
Arnualized Poll.Cont.Costs: $0
PV of Social Costs - Total: $234
Amortized Social Cost/MHBTU $3.06
FV of Social Costs - Oil: - $202
Anortized Social Cost/bbl: $18.96
PV of Social Costs - Sas: $32
Amortized Social Cost/MCF: $2.23
-------
Run Date: 2?-Apr-B7
Project Type: Region 6 - single oil well
ease Cost: $2
Expense: 58.302
Leasehold Cost: $3
Real Discount Rate: ' 8.00Z
Years Between Lease Sale
and Start of Explor.: 0
Percent Costs Considered IDC's: 60.001
Percent Costs Expensed: 42.00Z
Drilling Mud Cost Increient: O.OOZ
Corporate Tax Rate: 34Z
State Corporate Tax Rate: 6.75X
Corp Structure (l-iajor/2-indep): 1
EXPLORATION COSTS
Cost Per Exploratory Well: $186
Drilling Mud Cost Increient: $0
Discovery Efficiency: 0.52
Successful Expl. Well: 1
Year Year 'fear Year
0123
Explor. Costs Per Project: $358 $0 $0 10
Cost of Successful Efforts: $186 $0 $0 $0
'Expensed Costs: $250 $0 $0 $0
Expensed Cash Flows: $165 $0 $0 $0
Capitalized Cash Flows: $108 $0 $0 $0
PV of Expensed Exploration Cash Flows: $165
PV of Capitalized Expl. Cash Flows: $108
Total Capitalized Expl. Costs: $108
PV of all Exploratory Costs: $358
DEVELOPMENT COSTS
Total Infrastructure Cost: $82
»ears Between Start of Exploration
and Start of Development: 0
Nuifaer of Wells Drilled: 0
Nuiber Wells Drilled Per Year: 0
Drilling Cost Per Well: $0
Drilling Cost Per Well:
Drilling Mud Cost Increient:
iber of Weils Drilled:
'Total Drilling Costs for fear:
Annual Infrastructure Cost:
Annual Poll Cont Capital Costs:
Year
Year
0
$0
$0
0
$0
$82
$0
Year
1
$0
$0
0
$0
$0
$0
rear
i.
$0
$0
0
$0
$0
$0
re;
3
$0
$0
0
$0
$0
$0
ir rear
4
$0
$0
0
$0
$0
$0
Year
5
$0
$0
0
$0
$0
$0
Year
6
$0
$0
0
$0
$0
$0
Year
7
$0
$0
0
$0
$0
$0
fear
8
$0
$0
0
$0
$0
$0
9
$0
$0
-:•
$0
JO
$;
-------
Total Annual Capital Cast: $82 $0 $0 $0 $0 $0 $0 $0 $0 $0
Tax Shield: $12 $0 $0 $0 $0 $0 $0 $0 $0 $0
.xpen'sed Cash Flow: $23 $0 $0 $0 $0 $0 $0 $0 $0 JO
' pitahzed Cash Flan: $47 $0 $0 $0 $0 $0 $0 $0 $0 $0
FV of All Developtent Costs: $82
PV of Expensed Developsent Costs: $23
PV of Capitalized Deveiopient Costs: $47
FINANCIAL RATES
Percent Water Cut in 066 to Start: 27.
Oil/Bas Prod. Decline Rate/Year (X) SOX
Cost Escalator iZ): OX
Royalty Rate (X): 12.50X
Federal Tax Rate (?.): 34X
State Tax Rate (X): 7X
Average Depreciation Life (years): 7
Deprec. rate ieach year): 14.29? 24.49X 17.49X 12.49X 8.93X 8.92X B.93X 4.46X
State Severance Tax Rate-Oil: 8.00X
'If Alaska enter 99)
State Severance Tax Rate-Sas: 8.00X
(If Alaska enter 99)
PRODUCTION COSTS
''ears Between Start of Development
and Start of ^reduction (-.5): 1
Nuiber af fears at Peak Prod: I
Oil Peak Prod. Rate/Hell(bb): 26
Sas Peak Prod. Rate/Well(HMCF/D): 0.034
Nuiber of Producing Hells: 1
Nuaber of Hells Put in Service/Year 1
Drice of Oil Per Barrel: $25.47
Price Q* 6as Per HCF: $2.17
Total Operating Costs ($000): $15
Poll Cont Oper Costs ($000): *0
Days of P-cfluction Per Year: 365
Producing Wells in Service:
Barrels of Oil Per Day:
Days of Production Per Year;
Barrels of Oil Per Year:
Price/Barrel of Oil:
Y
0
ear Year
1
IL PRODUCTION
1
26
365
9490 7
$25.47 $25
1
0
21
365
592
.47
Year
j
0
F
365
6074
$25.47
fear
4
0
13
365
4859
$25.47
»sar
5
0
11
365
3887
$25.47
Year
6
9
365
3110
$25.47
Year
7
7
t
365
2488
$25.47
Year
8
5
365
1990
$25.47
Year
Q
4
3fc5
1592
$25.47
fear
10
T
3 • j j
iri
$15.47
5A5 PRODUCTION
-------
HHCF of Sas Per Day:
UUCP of Gas Per Year:
Frice/KCF of Sas:
Annual Oil Revenues ($000);
Annual Sas Revenues ($000):
Total Revenues f*000i:
Royalty Payments-Oil ($000!:
Royalty F'ayuents-Sas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-6as:
Net Revenues ($000):
Total Operating Costs ($000):
Expensed Poll.Cont.Cap.Costs i*GGO)
Poll.Con.Operating Costs ($000):
Capitalized Costs ($000):
Depreciation 4 Amortization ($000):
Operating Earnings ifGGO):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
Net Cash Flow:
Shutoff?
Actual Oii Prod./Year (Barrels):
Actual Sas Prod./Year (MNCFi:
Actual Sross Revenues ($000i;
Actual Net Revenues ($000):
Actual Net Cash Flow i$000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Zays at Production Per Year:
Barrels Oil Per Year:
Frice Per Barrel:
riMCF Sas Per Day:
MMCF Bas Per fear:
0
12
$2.17
$242
$27
$269
$30
$3
$19
$2
ERR
i -87.24
$214
$15
$0
$0
$156
$22
$199
$177
$1
$0
$176
$60
$12
$104
$127
1
9490
12
$269
$214
$127
$72
$0
$0
Year
11
0
10
$2.17
$193
$22
$215
$24
$3
$15
$2
ERR
-109.29
$171
$15
$0
$0
$0
$38
$156
$118
$1
$0
$118
$40
$8
$70
$108
1
7592
10
$215
$171
$108
$48
$0
$0
Year
i-
0
8
$2.17
$155
$17
$172
$19
$2
$12
$1
ERR
-136.87
$137
$15
$0
$0
$0
$27
$122
$95
$0
$0
$95
$32
$6
$56
$84
1
6074
8
$172
$137
$64
$3'
$0
$0
tear
13
0
6
$2.17
$124
$14
$138
$15
$2
$10
$1
ERR
-171.33
$109
$15
$0
$0
$0
$19
$95
$75
$0
$0
$75
$26
$5
$44
$64
1
4859
6
$138
$109
$64
$31
$0
$0
vear
14
0
5
$2,17
$99
$11
$110
$12
$1
$8
$1
ERR
-214.42
$87
$15
$0
$0
$0
$14
$73
$59
$0
$0
$59
$20
$4
$35
$49
1
3887
5
$110
$87
$49
$24
$0
$0
Vear
15
0
4
$2.17
$79
$9
$88
$10
$1
$6
$1
ERR
-268.27
$70
$15
$0
$0
$0
$14
$55
$42
$0
$0
$41
$14
$3
$25
$39
1
3110
4
$68
$70
$39
$17
$0
$0
Year
16
0
•^
$2.17
$63
$7
$70
$8
$1
$5
$1
ERR
-335.59
$56
$15
$0
$0
$0
$14
$41
$28
$0
$0
$27
$9
$2
$16
$30
1
2488
3
$70
$56
$30
$11
$0
$0
fear
17
0
T
$2.17
$51
$6
$56
$6
$1
$4
$0
ERR
-419.74
$45
$15
$0
$0
$0
$7
$30
$23
$0
$0
$23
$8
$2
$14
$21
i
1990
3
$56
$45
$21
$9
$0
$0
''ear
18
0
-\
$:.i7
$41
$5
$45
$5
$1
$3
$0
ERR
-524.92
$36
$15
$0
$0
$0
$0
$21
$21
$0
$0
$21
$7
$1
$:3
$13
i
1:92
^
$45
$!i
$:3
*<;
$0
$.-.
fear
I5
OIL PRODUCTION
-j
3o5
1019
$25.47
SAS PRQDUC
u
1
-\
365
815
$25.47
nos
0
1
-
3&5
s52
$25.47
0
1
1
365
522
*Z5,47
0
1
1
3e5
417
$25.47
o
1
1
365
334
$25.47
0
0
1
365
267
*25.47
0
i)
i
3&5
214
$25.47
!j
0
J'J J
1T1
tZf.r
$2.1'
$3Z
$4
$36
$0
$3
$0
ERR
$15
$i
$•
$i
$14
$14
$0
$0
$14
$!
t-
$35
I-
-------
Price Per MCF:
$2.1? $2.17 $2.17 $2.17 $2.17
$2.17 $2.17 $2.17 $2.17 $2.T
.il Revenues <$000>:
s Revenues ifOOO):
Total Revenues ($000):
Royalty Payments-Oil ($000>:
Royalty Payeents-Gas i$000i:
Severance Taxes-Oil ($0001:
Severance Taxes-Sas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Sas:
Net Revenues($000):
Operating Costs:
Expensed Poll.Cont.Cap.Costs ($000)
Pollution Control Operating Costs;
For Pv> Poll. Control:
Depreciation i Asortization:
Operating Earnings i$000):
Earnings Before Interest and ODA:
Depletion Allowance;
Surplus Depletion;
Earnings Before Interest and Taxes;
Federal Tax:
State Tax;
Earnings Before Interest After Tax:
Het Cash
ShutofP
Actual Oil Prod./Year (Barrels);
Actual Sas Prod.,'Year (H«CF):
Actual Gross Revenues ($000):
actual Net Revenues ($000!:
Actual Net Cash F;o« ($000):
Actual Ta-es Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrel; Oil Per Day;
Days of Production per Year;
Barrels Oi: c'er /ear:
Price Per Barrel:
Gas Per Day:
(MCF Gas Per /ear:
Fric? Per MCF;
-6
Year
OIL
$
SA5
$26
$3
$29
$3
$0
$2
$0
0.00 0
!20,76 -1026
$23
$15
$0
$0
$0
$0
$8
$8
$0
$0
$8
$3
$1
$5
$5
1
1019
1
$29
$23
$5
$3
$0
$0
Year
21
PRODUCTION
0
365
109
25.47 $25
PRODUCTION
i)
0
$21
$2
$23
$3
$0
$2
$0
.00
.19
$18
$15
$0
$0
$0
$0
$4
$4
$0
$0
$4
$1
$0
$2
$2
1
815
1
$23
$18
$2
$2
$0
$0
22
0
365
88
.47
0
y
$17
$2
$18
$2
$0
$1
$0
0.00
-1282.9''
$15
$15
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
1
652
1
$16
$15
$0
$0
$0
$0
Year
_ j
r,
365
70
$25.47
0
0
$13
$1
$15
$2
$0
$1
$0
0.00
-1603.99
$12
$15
$0
$0
$0
$0
($3)
($3)
$0
$0
($3)
($1)
($0)
($2!
($2)
0
0
0
$0
$0
$0
$0
$0
$0
'ear
24
0
365
56
$25.47
0
0
$11
$1
$12
$1
$0
$1
$0
0.00
-2005.24
$9
$15
$0
$0
$0
$0
($5)
($5)
$0
$0
($5)
($2)
($0)
($3;
($3)
0
0
0
$0
$0
$0
$0
$0
$0
rear
25
0
365
45
$25.47
o
\1
$9
$1
$9
$1
$0
$1
$0
0.00
-2506. SO
$8
$15
$0
$0
$0
$0
!$7S
($7)
$0
$0
($7)
($2)
($0)
($4!
($4)
0
0
0
$0
$0
$0
$0
$0
$0
rear
26
0
365
36
$25.47
0
$7
$1
$8
$1
*0
$1
$0
0.00
-3133.75
$6
$15
$0
$0
$0
$0
($9)
($9i
$0
$0
($9)
($3)
($1)
($5)
($5)
0
0
0
$0
$0
$0
$0
$0
$0
fear
27
0
365
29
$25.47
0
ij
$5
$1
$6
$1
$0
$0
$0
0.00
-3917.43
$5
$15
$0
$0
$0
($101
i$10)
$0
$0
($10)
($31
($1)
($6!
($6)
0
0
0
$0
$0
$0
$0
$0
$0
'ear
28
0
365
23
$25. 47
0
0
$4
$0
$5
$1
$0
$0
$0
0.00
-48'7.04
$4
$15
$0
$0
$0
($11)
($11/
$0
$0
($11)
($4)
($D
'$&.'
'$6''
i)
o
y
$0
$0
$0
$0
t'j
$0
tear
29
,'i
3s5
id
$25.47
13
$0
$4
$0
$0
$0
$0
0 . 00
-6121.55
$3
*15
$0
$0
$0
,m,
l$lll
$0
$0
l$lli
i$4i
•tii
'$3;
*s.
0
•j
$0
$0
$1
$0
$0
$0
rear
:':'
- J J
i C
$2:.4~
$2.17 $2.17 $2.17 $2.17 $2.17
$2.17
$2.1
-------
Oil Revenues '$000):
fias Revenues i$000'':
"ctal Revenues '$000):
"oyalty Parents-Oil ($000'<:
Royalty Payients-Sas ($000):
Severance Taxes-Oil \IOOO):
Severance Taxes-6as ($000':
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Ta*es-Gas:
Net Revenues ($000;:
Operating Costs:
Pollution Control Operating Costs:
For PV Poll. Control:
Depreciation 4 Aiorti:ation:
Operating Earnings ($000):
Earnings Before Interest ard ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
Net Cash Flow:
ChutofP
Actual Oil Prod. /Year (Barrels):
Actual Gas Frod./Year (HHCF);
Actual Sross Revenues <$GOO):
Actual Net Revenues ($00(0:
Actual Net Cash Flcn i$000.';
Actual Taxes Paid i$000*:
$3
$0
$3
$0
*0
$0
$0
0.00
-7&52.19
$2
$15
$0
$0
($12)
($12)
$0
$0
($12)
(*4)
(*!'
|.*7i
1*71
u
0
0
$0
to
*0
$0
$;
$0
$2
$0
$0
$0
$0
0.00
-9565.49
$2
$15
$0
$0
i*13)
($13)
$0
$0
• *13)
($4)
($1!
($7)
(J7i
0
0
0
$0
$0
$0
$0
$2
$0
$2
$0
$0
$0
$0
0.00
***********
$2
$15
$0
$0
($13)
($13)
$0
$0
($13)
!$4>
i*l)
i*8i
'«.-
0
o
0
$0
$0
$0
$0
$1
$0
$2
$0
$0
$0
$0
0.00
*********
$1
$15
$0
$0
($13)
i*13)
$0
$0
i*13)
($5!
($1)
($8i
(*8)
0
0
0
$0
$0
$0
$0
$1
$0
$1
$0
$0
$0
$0
0.00
*******
$1
$15
$0
$0
($14)
($14)
$0
$0
i$14)
($5)
itl)
($8)
($8)
0
0
0
$0
$0
$0
$0
$1
$0
$1
$0
$0
$0
$0
0.00
-23354.69
$1
$15
$0
$0
($14)
($14)
$0
$0
($14)
($5)
($1)
($8)
($8)
0
0
0
$0
$0
$0
$0
$1
$0
$1
$0
$0
$0
$0
0.00
***********
$1
$15
$0
$0
($14)
($14)
$0
$0
i*14)
1*5)
($1)
($8)
($6)
0
0
0
$0
$0
$0
$0
$1
$0
$1
$0
$0
JO
$0
0.00
*********
$1
$15
$0
$0
($14)
i*14)
$0
$0
i*14)
($5)
($1)
1*8)
i$8i
,5
0
0
$0
$0
$0
$0
$0
$0
$1
$0
$0
$0
$0
0.00
*********
$0
$15
$0
$0
($141
($14)
$0
$0
($14,'
($5;
'.$8)
'H;
M
!J
0
$0
$0
$0
$0
i:
$0
$0
$0
$0
JO
$0
0.00
********
$0
$15
$0
*0
i$14)
'$14!
10
$0
!*14)
t$5>
l$i'
i$?i
•$='•
s.
1
I
1
-------
cv of Net Lash Plows; $425
PV of Excess Depletion: $0
JV of Surplus Depreciation: $0
PV OT E-pensed Invest Casn Flows: $188
fv cf Cap:tah:ed Costs: $156
PV of Leasehold Cost: *3
FV =oll, Cent. Costs: $0
PV of Royalties - Oil: $53
PV of Royalties - Sas: $6
PV of Severance Taxes -Oil: $34
PV of Severance Tam - Gas: $4
PV of Operating Costs: $57
FV of Incote Taxes: $208
FV of Total Cosoany Costs: $709
PV of Total Cospany Costs - Oil: $638
PV of Total Company Costs - Sas: $71
Mortized Cotpany Cost per !4
Wellhead Price on MMBTU basis - Oil $4.39
Wellhead Price on HUBTU basis - Bas $2.13
F-J Equiv. of Oil Prod.ibb): 33,208
PV Equiv. of Gas (NMCF:: 43
FV Equiv. of Prod. iNNBTU': 236,942
Net Present Value of Projec $78
Infcernal Rate of Return: 0.155
:--obable ROP: 0.5
Annuahzed Poll.Cont.Costs: $0
°V of Social Costs - Total: $499
Mortized Social Cost/HHBTU $2.11
:'V cf Social Costs - Oil: ' $449
Afortized Social Cost/bbl: $13.52
FV of Social Costs - Sas: $50
Amortized Social Cost/HCF: $1.15
-------
Kun Date: 2
$0
o
$0
$0
$0
ir rear
$0
$0
0
$0
$0
$0
Year
4
$0
$0
o
$0
$0
$G'
Year
5
$0
$0
0
$0
$0
$0
Year
6
$0
$0
l)
$0
$0
$0
Year rear
7 3
$0 $u
$0 $0
0
$0 $'i
$0 I'"
$u i
;
$'"'
i'.
f'
!'':
-------
Total Annual Capital Cost;
Ta<; Shield:
Expensed Cash Row;
pit3h:ed Cash Flow:
Fv at" Ail Deveiopssnt Casts:
FV of £': OZ
Pcyalty Rate (l>\ 12.50Z
Federal Tax Pate (Z): 34Z
State Tax Rate (7.1: 7?
Average Depreciation Life (years); 7
Deprec. rate 'each yean: 14.297.
State Severance Tax Rate-Oil: 8.007.
(If Alaska enter 99!
State Severance Tax Rate-Gas: 8.00?
'If Alaska enter v?i
24.49? 17.45? 12.49? 8.93?
8.527. B.93? 4.46?
PRODUCTION COSTS
'ears Between Start of Oevelopaent
aid Start of Production (.5): 1
Nueber of y'ears at Peak Frod: 1
Cii f'ej* r-od. Rate/Well (bfai: 26
Sas Peai' p-ad. Rate/iear
'fear
Year
'ear
Tear
w'ear
Producing Wells in Service:
Barrel; of Oil Per Day:
Days of Production Per Year:
Barrels of Oil Per Year:
Price/Barrel of Oil:
OIL PRODUCTION
1
26
365
9490
$25.47
0
21
365
7592
$25.47
o
17
3i5
tO 74
$25.47
0
13
365
4859
$25.47
0
11
3c5
JS67
$25.47
9
365
3110
$25.47
7
3&5
2488
$25.47
i_>
365
19^0
$25.47
4
Tt5
::^2
$15.47
nS PRODUCTION
-------
MflCF of Gas Fer Day;
HMCF of Gas Per fear:
^rice/hTF of Gas:
Annual Oil Revenues ($000): $242 $193 $155 $124 $99 $7- $63 $51 $41 $72
Annual Sas Revenues ($000): $27 $22 $17 $14 $11 $9 $7 $5 $5 $4
Total Revenues ($000); . $269 $215 $172 $138 $110 $83 $70 $56 $45 $3c
Royalty Pa?aents-0ii '$000); $70 $24 $19 |[5 $12 $10 $8 $6 $5 $4
Royalty Payments-Gas i$000): $3 $3 $2 $2 $1 $1 $1 $1 $1 $0
Severance Taxes-Oil ($000): $19 $15 $12 $10 $8 $& $5 $4 $3 $3
Severance Taxes-Gas ($000!: $2 $2 $1 $1 $1 $1 $1 $0 $0 $0
EL" for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas:
Net Revenues <$000':
Total Operating Costs ($000): $15 $15 $15 $15 $15 $15 $15 $15 $15 $15
Expensed Pol I.Cent.Cap.Costs '$000) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Poll.Con.Operating Costs ($000): $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Capitalized Costs i*000): $107 $0 $0 $0 $0 $0 $0 $0 $0 $0
Depreciation 4 Aaortnation ',$0001: $15 $26 $19 $13 $10 $10 $10 $5 $0 $0
Operating Earnings !$000): $199 $156 $122 $95 $73 $55 $41 $30 $21 $14
Earnings Before Interest and ODA: $184 $130 $103 $81 $63 $46 $32 $25 $21 $14
Depletion Allowance: $31 $25 $20 $16 $13 $10 $8 $6 $5 $4
Surplus Depletion: $0 $0 $') $0 $0 $0 $0 $0 $0 $0
Earnings Before Interest and Taxes: $183 $130 $103 $81 $63 $46 $32 $25 $21 $14
Federal ^i $62 $44 $35 $23 $21 $16 $11 $9 $7 $5
tate Tan;
arnings Before Interest After Tax:
Net Cash Pbw:
Snutcf*'1
Actual Oil Prod./Year (Barrels):
Actual Sas Prod./fear fNNCF;:
Actual Gross Revenues ($000):
Actual Net Revenues !$000i:
Actual Net Cash Flow <.$000);
Actual Ta>es Paid '$000):
Capitalized Costs Not Expended: $0 $0 $0 $0 $0 $0 $0 $0 $•: $:
Burpijs Depreciation:
Barrels Oil Per Day:
Days of Product:en Per /ear;
Barrels Oil :'er fear;
c'nce Fer Barrel;
Gas '-?'• Day:
Gas Fe^ 'ear;
0
12
$2.17
$242
$27
$269
$70
$3
$19
$2
ERR
-37.24
$214
$15
$0
$0
$107
$15
$199
$184
$31
$0
$183
$62
$12
$103
$124
1
9490
12
$269
$214
$124
$75
$0
$0
Year
11
0
10
$2.17
$193
$22
$215
$24
$3
$15
$2
EPR
-109.29
$171
$15
$0
$0
$0
$26
$156
$130
$25
$0
$130
$44
$9
$77
$104
1
i
7592
10
$215
$171
$104
$53
$0
$0
Year
12
o
3
$2.17
$155
$17
$172
$19
$2
$12
$1
ERR
-176.87
$137
$15
$0
$0
$0
$19
$122
$103
$20
$')
$103
$35
$7
$61
$80
•
s074
8
1-172
$137
$60
$42
$0
$0
YDjr
-
0
6
$2.17
$124
$14
$138
$15
$2
$10
$1
ERR
-171.33
$109
$15
$0
$0
$0
$13
$95
$81
$16
$0
$81
$23
$5
$48
$62
1
4359
6
$133
$109
$62
$33
$0
$0
'ear
14
0
5
$2.17
$99
$11
$110
$12
$1
$8
$1
ERR
-214.42
$87
$15
$0
$0
$0
$10
$73
$63
$13
$0
$63
$21
$4
$37
$47
1
3887
5
$110
$87
$47
$26
$0
$0
tear
15
0
4
$2.17
$7-
$9
$83
$10
$1
$6
$1
ERR
-268.27
$70
$15
$0
$0
$0
$10
$55
$46
$10
$0
$46
$16
$3
$27
$37
1
3110
4
$88
$70
$37
$19
$0
$0
rear
16
0
T
$2.17
$63
$7
$70
$8
$1
$5
$1
ERR
-335.59
$56
$15
$0
$0
$0
$10
$41
$32
$8
$0
$32
$11
$2
$19
$29
1
2488
j
$70
$56
$29
$13
$0
$0
tear
17
0
•J
$2.17
$51
$6
$56
$6
$1
$4
$0
ERR
-419.74
$45
$15
$0
$0
$0
$5
$30
$25
$6
$0
$25
$9
$2
$15
$20
i
1990
J
$56
$45
$20
$10
$0
$0
/ear
13
i_
$2.17
$41
$5
$45
$5
$1
$3
$0
ERR
-524.92
$76
$15
$0
$0
$0
$0
$21
$21
$5
$0
$21
$7
$1
$!7
$13
1
1592
2
$45
$36
$13
$'
$•:
$'.•
'ear
i;
OIL PRODUCTION
-
365
1019
$25.47
SAS P^GDLiL
u
t
1
n
365
315
$25.47
TIQN
0
1
1
i.
7u5
652
$25.47
o
1
i
365
522
$25.47
o
1
1
365
417
$25. *7
0
1
1
365
334
$25.47
0
0
1
765
267
$25.47
0
0
1
3a5
214
$25.47
,)
0
',
•'..r
Pi
$25.47
-------
Frice -sr ilCF;
$2,17 $2.17 $1.17 *2.17 $2,17
*2.!7 fZ.17
$:.r
$2.1"
Revenues ''$000);
s Revenues '$000*:
Tctai Revenues ($000;:
Royalty Fayients-Oii ($000):
Fo'/alty Fayaents-Sas '$000!:
Eeverance Ta-es-Qil <$000/:
Severance Taxes-Gas (1000):
ELF for Alaska Severance "axes-Oil:
ELF tor Alaska Severance Taxes-5as:
Net Avenues(f000):
Operating Costs:
E;psnsed Poll.Cont.Cap.Costs i$000i
Pollution Control Operating Costs:
For :'V Pell. Cont-oi:
Depreciation 4 Amortization:
Operating Earnings '$000.';
Earnings Before Interest anfl GDA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
yet Cash Flow:
Snutcff "*
Actual Oil Prod.'rear (Barrels'1:
Actual Sas Fred, "rear 'MMCFi:
Actual Sruss Revenues ($000):
Actual Net Revenues ($0001;
Actual Net Cash Flo* '$0001:
Actual Tai-es Paid ($000):
Capitalized Cost; Not Expended:
Surplus Depreciation:
$26
$3
$29
$3
$0
12
$0
0 . 00
820,76
$23
$15
$0
$0
$0
$0
$8
$8
$3
$0
$8
$3
$1
$5
$5
{
i
1019
1
$29
$23
$5
$3
$0
$0
$21
$;
$23
$3
$0
$2
$0
0.00
-1026.1'
tie
$15
$0
$0
$0
$0
$4
$4
$3
$0
$4
$1
$0
$2
$2
1
815
1
$23
$18
$2
$2
$0
$0
$P
$2
$18
$2
to
$1
$0
0.00
-1282.'"'
$15
$15
$0
$0
$0
$0
JO
$0
$2
$0
$0
$0
$0
$0
$0
1
652
1
$15
$15
$0
$0
$0
$0
$13
$1
$15
$2
$0
$1
$0
0.00
-1603.?'
$12
$15
$0
$0
$0
$0
($3i
($3)
$2
$0
'$3!
($1)
($0)
($2)
($2)
0
0
0
$0
$0
$0
$0
$0
$0
$11
$1
$12
$1
$0
$1
$0
0.00
-2005.24
{9
$15
$0
$0
$0
$0
($5)
($5)
$1
$0
1*5)
($2!
($01
($3)
($3)
0
ij
0
$0
$0
$0
$0
$0
$0
$9
$1
$9
$1
$0
$1
$0
0.00
-2506.30
$8
$15
$0
$0
$0
$0
($7)
($7)
$1
$0
($7)
($2)
i*0i
i$4)
($4)
0
0
0
$0
$0
$0
$0
$0
$0
$7
$1
$8
$1
$0
$1
$0
0.00
-3133.75
$6
$15
$0
$0
$0
$0
($91
($9)
$1
$0
($9>
($3)
1*1)
($5)
!$5i
0
0
0
$0
$0
$0
$0
$0
$0
$5
$;
$&
$1
$0
$0
$0
0.00
-3917.4;
$5
$15
$0
$0
$0
i*10i
($10)
$1
$0
($10)
i$3)
($1)
($6)
1*6)
0
0
0
$0
$0
$0
$0
$0
$0
$4
$0
$5
$1
$0
$0
iO
0.00
-4S37.04
14
$15
$0
$0
$0
($111
i*ili
$1
$0
i*ll)
'$4;
1*1'
>ti>i
'$£'
o
'1
0
$0
$0
$0
$0
$0
JO
J7
$0
$i
$0
$0
$0
$0
0.00
-0121.55
$3
US
$0
$0
$0
.*lli
•til1
$0
$0
'$lli
•*4i
$:'•
.$9'
lj:
i
i
£
$
$
| ,
fear fear rear
21 22
-ear «ear fear 'ear rear i. 1 / *... il li. 1 •
-------
Oil Revenues ($000;:
^^as Revenues (*000):
^Pkai Revenues i*000/:
Fcyalty Paysents-Qil ($000):
!oyalty Payaents-5as ($000):
Severance Ta>'es-Qil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Ta
-------
PV of Net Ca=h Flaws; $4:0
Fv of Excess Depletion: $0
tV cf Surplus Depreciation: ~ $0
FV of Ei-censed Invest Cash Flows: $220
FV of Capitalized Casts: 1107
Fv1 at Leasenold Cost: $3
FV -oil. Lent, Costs; $0
FV of Royalties - On: $57
F'V at Royalties - Gas: $6
F'V of Severance Taxes -0:1: $34
PV of Severance Taxes - 5as: $4
FV of Operating Costs: $57
FV of Incoie Taxes: $223
FV of Total Coipany Casts: $707
PV of Total Ccspany Costs - Gil: $636
PV of Total Company Costs - Sas; $71
Mortized Cospany Cost per MHBTU: $2."
AiQftired Cospany Cost per bbl: $19.17
Aiortized Conpary Cost per HCF: $l.b3
Wellhead Price on HHBTli basis - Oil $4,39
kleihead Pri:e en NHBTU basis - 5as $2,13
SV Equiv. cf Oil Prod,(bbi; 33,208
PV Equiv. of cas idftCF'-: 43
FV Euiv. of F-od. iHFBTU): 23b942
kiet Present Value of Projec $7^
Inte'"iai Fate of Return: 0.140
F-ofcatle -OR: 0.5
Arrvja!i:ed coll,Cont.Ccsts: $0
Fv :f Scciii Costs - Tntai: $499
Ascrh:ed Social Cos: MHBTU $2.11
PV :f Social Costs - Oil: - $449
ftincrtized Social Cost/bbl: $17.52
F'v ]f Social Costs - Gas: $50
Amortized Social Ccst'lC"; $1.15
-------
Project Type;
Rase Cost:
G&E Expense;
Leasehold Cost:
Peal Discount Pate:
fears Between Lease Sale
and Start of Expior,:
Percent Costs Considered IDC's:
Fercent Costs Expensed:
Drilling Hud Cost Increient:
Corporate Tax Rate:
State Corporate Tax Rate:
Corp Structure il-iajor/2-indepi:
Cost Per Exploratory Well;
Drilling Hud Cost Increient:
Discovery Efficiency:
Successful E'pl. Well;
29-Apr-87
Region 7 - single oil well
$11
58,302
$18
5.00?
0
60.00?
42.00?,
0.00?
342
5.0')?
j
EXPLORATION COSTS
$246
$0
0.71
1
Year
Year
Vear
'ear
^Erplor. Costs Per Project;
Cost of Successful Efforts:
Expensed Costs:
Expensed Cash Pious;
Capitah:ed Casn Flows:
PV of Expensed Exploration Cash
C'V of Capitalized Expl. Cash Flows:
Total Capitalized Expi. Costs;
Pv of all E'rioratcry Costs:
$347
$246
$204
$135
$143
Flows;
ws:
$0
$0
$0
$0
$0
$135
$143
$143
$347
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
DEVELOPMENT COSTS
Tota! Infrastructure Cost: $87
'ears Between Start of Exploration
a"2 Start o* Deveiopaent: 0
of Hells Drilled: 0
wells Drilled Per 'rear: 0
g Cost Fer well: $0
Year
Year
rear
'ear
tsar
Year
tear
Year
Drilling Cost Per Hell:
Drilling lud Cost Increient:
i Nusiber of 'rtslis Drilled;
Total Drilling Costs for Year;
Annual Infrastructure Cost:
Ann'jai roii LD.it Capital Costs;
$0
$0
0
$0
$87
$0
$
$
$
$
$
0 $0 $0 $0 $i
) $0 $0 $0 $t
) 0 0 0 !
) $0 $0 $0 $i
) $0 $0 $0 $i
) $0 $(• $0 $'
) $0 $0 $' i."
$0 $0
0 ir
$0 t>j : i.
i $0 $•: i
; $0 $''
-------
Tatai Annual Capital Cost: $87 tO to $0 tO tO $0 tO tO JO
Ta- Shield: $12 $0 $0 tO tO tO $0 tO $0 10
tpensen Casn FJcn: ' $24 tO $0 $0 $0 tO $0 tO $0 *0
pitah:ed Casi Flon: 150 tO tO tO $0 $0 $0 $0 $0 $0
PV of Ail Developient Costs: $37
FV af Expensed Development Costs: $24
FV c* Capitalized Developieit 'lasts: $50
FINANCIAL RATES
Percent Water Cut in G&6 to Start: 22
Oil/Gas Prod. Decline Rate/Year (2) 637.
Cost Escalator '2): 02
Royalty Rate (2): 20.007.
Federal Tax Rate i'/.): 342
State Tax Rate <2i: 52
Average Depreciation Life (years): 7
Deprec. rate (each year>: 14.292 24.492 17.4-2 12.492 8.932 8.922 8.932 4.462
State Severance Tax Rate-Oil: 7.002
(If Alaska enter 99)
State Severance Tax Rate-Sas: 7.002
(If Alaska enter 99)
PRODUCTION COSTS
Vsars Between Start of Developient
and Start o+ Production t-5): 1
Nuiber of 'ears at Peak F'rod: 1
Oil Pea* Prod. Rate'Well(fab): 37
Gas Pea» Prod. Rate/Well(MNCF/D): 0.069
Nuaber of producing Hells: 1
Nuifaer of Xeils Put in Service/Year 1
cnc? of Oil Per Parrel: t26.54
Price of 3as Per MCF: 12.40
Total Operating Costs (tOOO): $15
Fall Cent Oper Costs (tOOO): $0
Davs cf production Per /ear: 365
producing Hells in Service:
Barrels of Oil Per Day:
Days of Production Per Year:
Barrels of Oil Per Year;
Price/Barrel of Oil:
Year
OIL
t
1
PRODUt
1
37
365
13505
26.54
Year
:TION
$2
2
0
-57
365
8508
6.54
*ear
0
15
365
53t>0
t26.54
rear
4
0
9
365
3377
$26.54
'fear
5
0
6
3o5
2127
t26.54
Year
6
4
365
1340
t26.54
fear
7
2,
365
844
t26.54
fear
8
1
365
532
$26.54
fear
?
1
365
TTC
J -' J
$26.54
Vear
10
i
T^f
~ i ',
$16.5*
5AS PRODUCTION
-------
MHCF of aae Per Day;
WtCF of Gas Per Year:
of 3as:
Annual Oil Revenues ($000):
Annual bas Revenues ($000):
Total Revenues '$000):
Royalty Fayeents-Qil ($000);
Royalty Payuents-Gas ($000,':
Severance Taxes-Oil ($000):
Severance Ta*es-6as ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas:
Net Revenues '$000):
Total Operating Costs ($000):
Expensed Poll.Cent.Cap.Costs !$000>
Poll.Con.Operating Costs ($000):
Capitalized Costs ($000):
Depreciation i Asortization ($000):
Operating Earnings ;$000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes
Federal Tax:
it ate Tax;
^Earnings Before Interest After Tax:
Net Cash Fic»:
ShutcfP
Actual Ci; Prod..'Year 'Barrels/!
Actual Gas Prod./Year (NHCF):
Actual Brass Revenues ffOOOi:
Actual Net Revenues ($000):
Actual Net Cash Plow itOOO'1:
Actual Taxes Pain ($000):
Capitalized Costs Net Expended:
3'jrpius Depreciation:
Barrels Oil Per Day:
Days of f'roduct:on Per Year:
Barrels Ci! ^er vear:
Price Per Barrel:
5as ;er Day:
11CF Gas ser ''ear;
0
25
- $2.40
$358
$60
$419
$72
$12
$25
$4
ERR
-42,48
$306
$15
$0
$0
$193
$28
$291
$263
$6
$0
$257
$87
$13
$156
$191
1
13505
25
$419
$306
$191
$100
$0
$0
Year
11
0
16
$2.40
$226
$38
$264
$45
$3
$16
$3
ERR
-68.01
$193
$15
$0
$0
$0
$47
$178
$130
$4
$0
$126
$43
$6
$77
$123
1
6508
16
$264
$193
$128
$49
$0
$0
Year
$ -,
i i.
o
10
$2.40
$U2
$24
$166
$28
$5
$10
$2
ERR
-108,54
$121
$15
$0
$0
$0
$34
$106
$72
$3
$0
$7,}
$24
$3
$43
$79
,
5360
10
$166
$121
$79
$27
$0
$0
fear
13
0
6
$2.40
$90
$15
$105
$18
$3
$6
$1
ERR
-172.88
$76
$15
$0
$0
$0
$24
$61
$37
$2
$0
$36
$12
$2
$21
$47
1
3377
6
$105
$76
$47
$14
$0
$0
'ear
14
0
4
$2.40
$5o
$10
156
$11
$2
$4
$1
ERR
-275.00
$48
$15
$0
$0
$0
$17
$33
$16
$1
$0
$15
$5
$1
$9
$27
1
2127
4
$66
$48
$27
$6
$0
$0
Year
15
0
-\
$2.40
$36
$6
$42
$7
$1
$2
$0
ERR
-437.10
$30
$15
$0
$0
$0
$17
$15
($2)
$1
$0
($3)
($1!
f$0)
($2!
$16
I
1340
2
$42
$30
$16
nn
$0
$0
Year
16
0
2
$2.40
$22
$4
$26
$4
$1
$2
$0
ERR
-694.39
$19
$15
$0
$0
$0
$17
$4
($13)
$0
$0
($14)
($5)
($1)
($8)
$9
1
844
J
$26
$19
$9
($5;
$0
$0
Year
17
o
1
$2.40
$14
$2
$16
$3
$0
$1
$0
ERR
-1102.79
$12
$15
$0
$0
$0
$9
($3)
($12!
$0
$0
($12)
($4)
($1)
i $7;
$2
0
W Jfa
I
$16
$12
$0
$0
$0
$9
Year
18
0
1
$2.40
$9
$1
$10
$2
$0
$1
$0
ERP
-1751.06
$e
$15
$0
$0
$0
$0
($8)
!$8i
$0
$0
•$5!
i$3'
•iO
.$5'
•$5'
0
(f
$'.<
$0
$0
$0
$0
$0
year
i3
*-, ;,-
$;
$1
$7
$1
to
$0
$0
ERR
-2 '30. 04
£5
$15
$0
$0
i'j
$0
,,10.
'$10'
$0
$0
•$10'
•$4<
•ill
••I7-
*Ti
0
o
$0
JO
$0
10
$0
$0
rear
-•'
OIL PRODUCTION
0
365
133
$26.54
GAE ^ODL'i
0
0
y
365
84
$26. :4
7ION
0
M
ij
•^LS
53
$26.54
0
u
o
365
33
$2a.54
0
0
0
365
21
$26.54
it
ij
0
365
13
$26.54
0
0
i)
365
8
$26.54
0
0
0
365
5
$26.54
M
ij
3t5
••
$26.54
,-,
3o5
:
$2:.:*
-------
trice Per MCF:
$2,40 $2.40 $2.40 12.40 $2.40
$2,40 $2.40 $2.40 $2.40 $2.40
Jhi Revenues '$000):
^^ps Revenues ($000):
Tctal Revenues '$000):
Royalty Payients-Gil '$000;:
Royalty Payients-Sas ($000):
Severance Taxes-Oil ($000i:
Severance Taxes-Gas ($000);
ELF tor Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Sas:
Net Revenues ($000!;
Operating Costs:
Expensed Poll. Cont. Cap. Costs i$000)
Pollution Control Operating Costs:
For P'/ Poll, Control:
Depreciation i Asortization:
Operating Earnings '$000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
^iet Cash Flow:
ShutofP
Actual Oil Prod. /Year (Barrels):
Actual Sas Prod. /Year 'MCFi:
Actual Gross Revenues !$000i:
Actual Net Revenues ($000);
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000):
Capitalized Cost; Not Expended:
Surplus Depreciation:
Parrels Oil Per Dav;
Days of Production Per Year:
Barrels Oil °er Year:
Price Per Parrel:
^^MMCF Gas Per Day:
MCF Sas Per Year:
"nee Per *CF:
$4
$1
$4
$1
$0
$0
$0
0.00 0
-4413.35 -7005
$3
$15
$0
$0
$0
$0
($12) I
($12) (
$0
$0
($12! <
i$4)
($1)
($7)
l$?)
0
0
0
$0
$0
$0
$0
$0
$0
Year Year
21
OIL PRODUCTION
0
365
1
$26,54 $26
SAS PRODUCTION
o
0
$2,40 $2
$2
$0
$3
$0
$0
$0
$0
.00
.90 i
$2
$15
$0
$0
$0
$0
$13!
$13)
$0
$0
$13!
($5!
($1!
($8)
($8)
0
0
0
$0
$0
$0
$0
$0
$0
\
T5
0
365
1
.54
0
0
.40
$1
$0
$2
$0
$0
$0
$0
0.00
it*******
$1
$15
$0
$0
$0
$0
($14!
($14)
$0
$0
($14)
($5)
($1)
($9)
'$8!
0
0
o
$0
$0
$0
$0
$0
$0
'par
::
i.
365
1
$26.54
U
0
$2,40
$1
$0
$1
$0
$0
$0
$0
0.00
*****t*ti
$1
$15
$0
$0
$0
$0
($14)
($14!
$0
$0
($14)
($5!
($1)
($9)
($9!
0
0
0
$0
$0
$0
$0
$0
$0
'•ear
24
0
365
0
$26.54
''}
0
$2.40
$1
$0
$1
$0
$0
$0
$0
0.00
*********
$0
$15
$0
$0
$0
$0
($15)
($15)
$0
$0
($15)
($5)
($1!
($9)
($9)
0
0
0
$0
$0
$0
$0
$0
$0
''ear
25
0
365
0
$26.54
_i
0
$2,40
$0
$0
$0
$0
$0
$0
$0
0.00
-44478.91
$0
$15
$0
$0
$0
$0
($15)
($15)
$0
$0
($15!
($5!
($1)
($9)
($9!
0
0
0
$0
$0
$0
$0
$0
$0
/ear
26
0
365
0
$26.54
0
0
$2.40
$0
$0
$0
$0
$0
$0
$0
0.00
*********
$0
$15
$0
$0
$0
$0
($15!
($15)
$0
$0
($15)
($5)
($1)
($9)
($9)
0
0
0
$0
$0
$0
$0
$0
$0
Year
27
0
365
0
$26.54
o
0
$2,40
$0
$0
$0
$0
$0
$0
$0
0,00
*********
$0
$15
$0
$0
$0
($15!
($15!
$0
$0
($15)
($5!
($D
($91
($9!
0
0
0
$0
$0
$0
$0
$0
$0
fear
28
0
365
0
$26.54
o
0
$2.40
$0
$0
$0
$0
$0
$0
$0
0,00
*********
$0
$!5
$0
$0
$0
($15)
i$15)
$0
$0
($15)
($5)
($1)
($9''
.$
-------
'"]? i Revenues ' J("''Vi)'
las £'2vsr,'_;es ' JOOOi:
ttal Revenues ($000):
Royalty Pay«ents-Qil ($000):
Foyalty Payients-bas ($000):
Esverance Taxes-Oil ($000):
Severance Taxes-tas !$000i:
ELF tor Alaska Severance Taxes-0il:
ELF for Alaska Severance Taxes-Sas:
Net fsvsnues(*000i:
Operating Costs:
Foliation Control Operating Costs;
For PV Poll. Control:
Depreciation 4 Aiorti:atian:
Operating Earnings
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
Earnings Before Interest After Tax:
Net Cash Flo*:
hutofP
'Actual Oil Prod./Vear (Barrels):
Actual Gas Pros,/Vear '.HHCFi;
Actual Brass Revenues ''$000):
Actual Net Revenues iJOOO):
Actual Net lash Flow '$000>:
Actual Ta;
-------
FV of Net [ash Flows; $418
FV cf Excess Depletion: $0
of Surplus Depreciation: - $2
FV of E'
-------
Date:
Project Type:
Tease Cost:
S&S Expense:
Leasehold lost:
Real Discount Pate:
Years Between Lease Sale
and Start of Explor,:
Percent Costs Considered IDC's:
Percent Casts Expensed:
Drilling Mud Cost Incre*ent:
Corporate Tax Rate:
State Corporate Tax Rate:
Corp structure d-najor/2-indep):
Cost Per Exploratory Hell:
Drilling Mud Cost Increient:
Discovery Efficiency:
Successful Expl. Well:
29-Apr-87
Region 7 - single :ii nell
$11
56,302
$18
B.OOZ
0
60.00?
60.00?
0.00?
34Z
5.007.
2
EXPLORATION COSTS
$246
$0
0.71
Year
rear
Year
Year
xplor. Costs Per Project:
ost at Successful Efforts:
Expensed Costs:
Expensed Cash Fiows:
Casi tali zed Cash Flaws:
$347
$246
$248
$lo4
$99
$<}
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
Pv of Expensed Exploration Cash flows;
PV o+ Capitalized Expl. Cash Flows:
Total Capitalized Expl. Costs:
PV at ail Exploratory Costs:
$164
$99
$99
$347
7:.tal Infrastructure Cost:
'ears Between Start of Exploration
aid Start of Deyelopient:
Nuncer ii Hells Drilled:
Nusber Wells Drilled Per Year:
Drilli-g Cost Per Hell:
DEVELOPMENT COSTS
$87
0
0
0
$0
fear
Year
/ear
';ear
I'ear
fear
fear
'ear
Drilling C:st fer Hell:
Drilling Mud Cost Increient:
ber of Hells Drilled:
Total Driilng Costs for Year;
Annual Infrastructure Cost:
Ar.Tjal Poll Cent Capital Costs:
$0
$0
o
$0
$37
$0
$0
$0
0
$0
$0
$0
$0
$0
i'l
$0
$0
$0
$0
$0
0
$0
$0
$0
$0
$0
0
$0
$0
$0
$0
$0
0
$0
$0
$0
$0
$0
u
$0
$0
$0
$0
$0
0
$0
$0
$0
$0
$0
! i
f'j
$11
»'"
f-
f .
*'.'
-------
'otal Annual Capital Cost:
Tax Shield:
pensed Cash Flow:
rapitah:ed Cash Flew:
FV of fill Deveiopsent Costs: $87
PY of Expensed Development Costs: $34
?V cf Capitalized Deveiopaent Costs: $35
FINANCIAL RATES
$87
US
$34
$35
$0
$0
$•)
$0
$0
$0
10
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
to
$0
$0
$0
$0
$0
$0
$0
$0
$0
to
to
$0
$0
$0
$•:
$0
JO
$0
Percent Water Cut in 0&6 to Start; 21
Oil'Gas Prod. Decline Pate/rear Ci) 63?
Cost Escalator (X): OX
Royalty Rate (Z): 20.00?
Federal Tax Rate iX): 34X
State Ta;: Rate (Xi: 5?
Average Depreciation Life 'yearsi: 7
Deprec. rate iea:h year>: 14,291 24.491 17.497. 12.497. 8.93X 8.92X 8.931 4,46;
State Severance Tax Rate-Oil: 7.007.
(If Alaska enter 99)
State Severance Tax Rate-Gas: 7.0GZ
'If Alaska enter 99)
PRODUCTION COSTS
'ears Between 5tart of Develapaent
and Start of Pnduction f-51; 1
Nuaber of rears it Peak Frod: 1
0:1 Pea* Prod. Pate'Kellfbb): 37
3as F9a> P-od. Rate/Keli
-------
M*CF at Sas Per Day:
HMCF at Sas Per Vear:
fice/HCF of 3as:
Annual Oil Revenues t$000>:
Annual Sas revenues ($000):
Totai Revenues ($OC'0):
Royalty Pay»ents-Gil iJOOOi:
Royalty Payients-Gas ($000;;
Severance Taxes-Oil ($000):
Severance Taxes-Gas i$000i:
ELF for Alaska Severance Taxes-Oil
ELF for Alaska Severance Ta*es-6as
Net Revenues ($000):
Total Operating Costs '$000;:
Expensed foil.Cent.Cap.Costs '$000!
F'cil.Con.Operating Costs i$QOO):
Capitalized Costs ($000):
Depreciation 4 Aaortiiatian ;$000i:
Operating Earnings '$000):
Earnings Before Interest and OM:
Depletion Allowance:
Surplus Depletion;
Earnings Before Interest and Taxes:
rederai Tax:
state Ta:;:
Earnings Before Interest After Ta;::
Net Cash F13«:
inutaff
Actual Oil Prod./rear (parrels):
Actual Sas Prod.'"rear 'MHCFi:
Actual Sross Revenues <$000;:
Actual Net Revenues i$OQQ':
Actual Net Cash Flo* ($000):
Actual Ta;'es Paid ($0001:
Capitalized Casts Not Expended:
Surplus Depreciation:
Sa^eis Oil Per Dav;
Days of Production Per fear:
barrels Oil "er
Frice Per Barrel:
MHCF ias ;er Day:
i4**" Gas ser 'ear:
0
25
$2.40
$353
$60
$419
$72
$12
$25
$4
: ERR
: -42.48
$306
$15
i $0
$0
$133
: $19
$291
$272
$40
$0
: $2fc5
$90
$13
: $1&2
$187
1
13505
25
$419
$306
$137
$103
$0
$0
fear
11
0
16
$2.40
$22:
$38
$2s4
$45
$3
$16
$3
ERR
-68.01
$193
$15
$0
$0
$0
$33
$175
$145
$25
$0
$141
$48
$7
$36
$123
1
8506
16
$264
$193
$123
$55
$0
$0
'fear
12
'1
I'l
$2.4u
$142
$24
$166
$28
$5
$10
$2
ERR
-103.54
$121
$15
*0
$0
$0
$23
$106
$63
$16
$0
$80
$27
$4
$49
$75
t
57tO
10
$lo6
$121
$75
$31
$0
$0
year
13
0
6
$2.40
$90
$15
$105
$18
$3
$6
$1
ERR
-172.88
$76
$15
$0
$0
$0
$17
$61
$45
$10
$0
$43
$15
$2
$26
$45
1
3377
6
$105
$76
$45
$17
$0
$0
rear
14
o
4
$2.40
$56
$10
$66
$11
$2
$4
$1
ERR
-275.00
$48
$15
$0
$0
$0
$12
$33
$21
$6
$0
$20
$7
$1
$12
$25
1
2127
4
$66
$48
$25
$8
$0
$0
Year
15
0
-1
$2.40
$36
$6
$42
$7
$1
$2
$0
ERR
-437.10
$30
$15
$0
$0
$0
$12
$15
$3
$4
$0
$3
$1
$0
$2
$14
1
1340
-
$42
$30
$14
$1
$0
$0
Year
lo
y
^
$2.40
$22
$4
$26
$4
$1
$2
$0
EFR
-s94.39
$19
$15
$0
$0
$0
$12
$4
($8)
$3
$0
($8!
(fji
l$0i
($5!
$7
1
844
i.
$26
$19
$7
($3)
$0
$0
Year
17
0
i
i
$2.40
$14
$2
$lfc
$3
$0
$1
$0
ERR
-1102.75
$12
$15
$0
$0
$0
$6
.*;»
($5)
$2
$0
'$9i
s$3i
I$G)
1*6'
$1
0
572
1
$16
$12
$0
$•)
$0
$t
fear
18
[
$2.40
$9
$1
$10
$2
'to
$1
$0
ERR
-1751.00
$3
$15
JO
$0
$0
$0
($5)
f$S)
$1
$0
'$3''
'$3'
•$0'.
'$5'
•$5'
u
0
0
$0
$0
$'.'
$0
t;
$0
Year
1 3
•"'
$2.40
Is
Ji
$7
$1
$0
$0
$0
p;
-273':v"'4
$:
$15
$0
$0
$0
$0
.$10.
•$10
$1
$0
. 1 1 ,',
•+ I V '
$4,
, 1 1
•17-
1 i" '
' f
o
t '
j'"r
i '"'
i;
$;•
iO
•ear
-i1
OL PRODUCTION
0
365
133
$26.54
EAE P?C'DUC
<;.
u
f,
365
34
$26.54
T!QN
0
y
0
365
C"*
_' J
$2s,54
y
I)
0
3o5
77
J j
$26.54
0
0
o
365
21
$26.54
o
o
0
365
13
$26.54
0
0
0
765
8
$26.54
J
0
,'i
3&5
=;
$26.54
0
0
i'.
7t5
••
$26.54
-..c
^_
$2t.5-i
-------
$2.40 $2.40 II. 40
11.40
12.40 42.40 $1.40 11.40 II. 41
• i Revenues <$000):
bag Revenues '$000):
Total 5evenues '$0001:
Royalty Day*ents-0ii '1000):
Royalty Faysents-'Sas '$000;:
Se/erance Taxes-Oil ($000):
Severance Taxes-cas ($000':
EL' for Alaska Severance Taxss-uil
ELP for Alaska Severance Taxes-6as
Net Revenues '.$000i;
Operating Costs;
Expensed Poll, Cant. Cap. Costs ilOOO
Pollution Control Operating Costs:
For py Poll, Control :
Depreciation 4 Atorti:ation:
Operating Earnings '1000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes
Federal Tax:
State Tax;
Earnings Before Interest After Tax
1st Cash F!QN:
Shutoff"
Actual Oil prod.'>=ar 'Barrels':
Actual Eas Prod. /fear 'MCF/:
Actual Gross Revenues ($000;:
Actual Net Revenues ($000):
Actual Net Cash Flow !tOOO):
Actual Taxes Paid '$000;:
Capitalized Costs Sot E.ipendea:
Surplus Depreciation:
Barrel; Oil Per Day:
la;. s of Production Per /eaf;
Parrels Oil :er 'ear;
P'rice Per Barrel:
MfiCF aas Per Dav;
WJ 5as Per -ea-:
:ri:e -er «rt.
$4
$1
$4
11
$0
$0
$0
; 0,00 0
: -4413,35 -7005
$3
$15
;< $0
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to
$0
'$12! i
i$12;
$0
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: $12)
'$4'
($1)
: '17)
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0
1 1
10
$0
$0
$0
$0
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Year Year
21
OIL PRODUCTION
,;,
365
1
$26.54 $26
5AS PRODUCTION
n
'!
$2Jn $;
$2
$0
$3
$0
$0
$0
$0
.00
.90
$2
$15
$0
$0
JO
$0
$13!
$131
$0
JO
1131
!$5i
ill!
'181
'I8i
0
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"
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22
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1
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$1
$15
$0
$0
$0
$0
•114.
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$0
$0
'114)
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0
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$0
$0
$0
$0
JO
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"
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3c5
1
126.54
0
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12.40
Ji
$0
$1
$0
JO
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JO
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$0
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$0
$0
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$15
$0
$0
$0
$0
($15!
'$15)
$0
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0
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25
0
365
0
$26.54
j
0
$2.40
$0
$0
$0
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$0
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0.00
-44473.91
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'•ear
2s
0
365
0
$26.54
o
0
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10
$0
$0
$0
$0
$0
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0.00
*********
$0
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10
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$0
(115!
(115;
10
$0
($15)
($5)
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o
0
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$0
$0
$0
$0
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Year
17
u
365
'.(
$26.54
1
1
12.41
$0
$0
JO
$0
JO
$0
$0
0.00
*********
$0
$15
JO
$0
$0
.$15)
i.J15'
$0
$0
•$15l
•;$5i
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i$9''
($9'
l)
0
0
$0
$0
$0
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''ear
25
,;,
365
0
$26.54
0
$2.40
$0
$0
1C
$0
JO
$0
JO
0.00
**********
$0
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to
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($15)
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0
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10
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$0
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tea'
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$26. !4
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t,-,
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0.00
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JO
$15
$•:•
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$0
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-------
Oil Revenues '$000':
i Fe.'Srues 'tOOO*:
"ioyaity Faints-Oil flO'X''1:
Foyaltv Pay«ents-5as ($000):
Severance Ta'-e=-Jii '$000i:
Severance Taxes-Gas (tOOOi:
ELF for Alaska Severance Taxes-uil:
EL3 for Alaska Severance Taxes-Gas:
Net Revenues'tGOO;:
Operating Costs:
Pollution Control Operating Ccsts:
For PV Poll. Control:
Depreciation i Amortization:
Operating Earnings :$000):
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Ta»;
Earnings Before Interest After Ta;.:
Net Casn Fi3n;
Bhutoff
"Actual Oil Prod,-fear 'Barrels.;
Aztuai Gas Prod."ear iilHCF1:
Actual Grass Revenues t$000):
Actual Net Revenues itOOO'';
Actual Net Cas" flow '$000,':
Actual Ta\es pa:d '$000':
to
$0
to
to
to
to
to
0,00
to
$15
to
to
«$15)
($15-
to
$0
>$15>
i$5;
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'$9)
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to
to
to
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to
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0,00
444 44 4444
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to
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to
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0
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0
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to
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to
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to
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115
$0
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•$15)
to
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-------
'V of Net CiS" "Ions: $401
Fv cf Evcess Depletion: $0
M cf Surplus Depreciation: II
:v 2* E;.3SP5?d Invest Casn Flows: ll'B
CV :f C£pi:jii:«2 Lists: 1133
FV of ..aaseirld Cost: 113
Fv -oil. Cent. Costs: 10
CV of Royalties - Gil: $78
Fv cf Royaltiss - Sas: $13
FV of Severar-cs Taxes - Oii: $27
FV of S9verance Ta>es - 5as: *5
FV 3* Operating Costs; $39
CV cf I".co«e Taves: $184
FV o* Total Cospany Costs; $654
fV of Total Ccspany Costs - Oil: J595
FV of Total Cospany Costs - Gas: $100
Psorti:ed Coipany Cost per HHS7U: $3.04
&«ort;:ed Conoany Ccst per obi: $20.10
Anort::ed Cospany Cost per >1CF: 11.52
Weliheac! -rice on HHBT'J basis - Oil $1.53
Wellhead Drice on HPBTU basis - Sas $2.35
f'J Equiv. at" Jii p'od.'bDi; 2v,c05
F'V Eqiiiv. r1' Gas itWCF': 55
f'J Equu. of Prod. 'MUBTU/: 228,107
Net c'esent Value ct -rajec $53
!".?'T3l Rate o* Return: 0.156
:':oacls ;L,K; 0.5
A-ri:aii:ed :c:l .Cont.Costs: $0
:V cf iccia: Costs - V.ai: $430
^:-t::ed 5cc:ai Cost'«1BTU $2.1'j
F- :•' Social C:sts - C'll: ' $410
^oriized Social C:st'5dl; $13.36
''-' cf Scciil Costs - £as: $o'
^crt::ed Social Cost'^CF; $1.25
-------
Run E'ate:
Project Type:
Use Cost:
Sib Expense;
Leasehold Cost:
Real Discount Rate;
rears Between Lease Sale
and Start of Expior,:
Percent Costs Considered IDC's:
Percent Costs Expensed:
Drilling Mud Cost Increient:
Corporate Tax Rate:
State Corporate Tax Rate:
Corp Structure 'l-aajor/2-indep):
Cost ?er Exploratory Well:
Drilling Mud Cost
Discovery Efficiency:
3uccesr*til Expl. ulell;
2"?-Apr-B7
Region 7 - single gas Nell
$22
58.JO*
$35
6.002
0
60. OO'i
42.002
0.00!'.
342
5,002
1
EXPLORATION COSTS
$728
$0
0.71
1
Year
Year
rear
'ear
Expior. Costs Per Project:
Kost of Successful Efforts:
Expensed Costs:
Erpensec Cash Rons:
Capitalized Casn RDNS:
f'l of E"pensec! Exploration Cash RONS:
c';,' of Capitalized Expi. Cash Flows:
Total Capitalized E';pl. Costs:
PV cf ail Exploratory Costs:
$1,025
$726
$603
$398
$422
NS:
$0
$0
$0
$0
$0
$3^8
$422
$422
$1,025
$0
*0
$0
$0
$0
$0
$0
$0
$0
$0
Tcr.3i Infrastructure Cost:
tsars Between Start of Exploration
a^H Start of Developaent:
Nu'cer of Neils Drilled:
mel Is Driiieo Per Year:
c Cost Per Heii:
DEVELOPMENT COSTS
$40
0
0
0
$0
rear
tear
>ear
Year
Year
fear
'ear
Drilling Cost cer well:
Drilling Hud Cost Increient:
5RPr ^* ^p^': "i ^ ' i ; p ^ •
ctai C""iilipg C:;ts for r'ear:
Annual In»ra=tr.:t'jre Cost:
$0
$0
0
$0
$40
$0
$0
$0
\\
$0
$0
$0
$0
$0
M
$0
$0
$0
$0
$0
ij
$0
$0
$0
$
$
$
$
$
$0
$0
ij
$0
$0
$0
$0
$0
o
$0
$0
$0
$0
$0
1 (
$0
$0
$0
$0
}"
.'
$i
$0
}•''
:;
{
I ,
I
-------
Tota! Annual Capital Cost;
Ta* Shield
sensed Cash F!OH:
Ipitah:ed Cash F!CP;
F'/ of All Development Costs:
FV of E?ps"sed Developie^t Costs:
FV :f Capitalized Development C:its:
$40
$6
til
t23
10
to
to
to
140
til
$23
10
to
to
10
to
to
to
ro
to
to
to
to
to
to
to
to
to
to
to
to
iO
to
to
t :
t'l
to
to
I'.
t1.'1
to
t.',
FINANCIAL RATES
Percent Water Cut in 0?:
Royalty Rate (7,i:
Federal Tax Rate W:
State Ta:; Pate iX):
Average Depreciation Li-fe iyears):
Deprec. rate 'each year):
State Severance Tax Rate-Oil:
fit Alaska enter 99)
State Severance Tax Rate-Sas:
!H Alaska enter 99)
637.
07.
20,00?
347.
52
7
14,29?
7.007.
7,00?
24.494 17.491/. 12.492
5.92X
PRODUCTION COSTS
•'ear; Between Start of Developaent
and Start of Production i'5): 1
Nuiber of 'years at Peak Prod: 1
Oil Peat Prod. Rate/HellfbD/s 0
Gas Feat Prod. Rate/Hell(HMCF/D): 1.038
Nuucer of "reducing Kells: 1
Neither of Wells put in Service/Year 1
c'ice of Oil per Barrel; t26.54
Fries cf Sas Per HCF: *2.40
Total Operating Costs itOOOi: t21
c'cli Cont Qper Costs itOOO): $0
Days of Production Der Year: 365
Year
Year
'Bar
tear
Year
Tear
•ear
•ear
OIL PRODUCTION
Froducing wells in Service;
Parrels of Oil Per Day:
Days of Production Per fear;
Barrels of Oil Per -ear;
Price'Barrel of Gil:
1
u
3s 5
0
t26.54
v
0
365
o
0
365
0
tl6.54
0
o
365
0
t26.54
0
365
0
t26.54
0
365
0
t26.54
0
365
0
$24.54
..00
SAS PRODUCTION
-------
C' Qt 6as Per Day;
rlMCF of 3as Per Vear:
trice/MCF of 5as:
W
Annual 5as Avenues i$000):
"otal Revenues '$000;:
Fcvaitv Fi/ffeits-C'ii 'fOOO1;
Fayaity Pavients-Sas ''$000';:
Se<-erance Ts.-es-Oil '>$000;;
Cavprance Ta';es-tas '$000!:
ELr for Alaska Severance Taxes-Gil:
ELF *T Alaska 5eii'prance Ta-es-Sas.
Net Revenues ilOOO'1 ;
Totai Operating Costs '$000':
Expensed Foil, Cart. Cap. Costs '*000'
foli. Con. Operating Costs '.$000':
Capitalized Costs '$000!;
Depreciation I •iicrtiiation 'lOOOi;
C'perit:."g Eatings i$OOiO:
Earnings Before Interest and QDA:
Depletion Allcnar.ce;
Surplus Depletion:
Earnings Before Interest and Ta^es:
Federal Tax:
(state Tax:
Earnings Before Interest After Tax:
k.'et Cash Flo«:
Snutcf^
Actual Oil Cr:d, ''ear Barrels1:
Actual bas ^r3C,/Tear 'rthCF':
Actual oross ;evenues iiOOOi;
Actual Net Revenues i$OOC":
Actual Net Casn Flow 'tOOO';
Actual Ta>es 2aia $OOC : :
Capitalized tests Not Expended:
;'j"'uc I'ppr'-i ari T :
/ear
GIL
379
$2.40
10
$=09
*3,j3
$0
$1E2
$0
$64
ERF
-' 39
$.64
$21
$0
$0
$445
$64
$643
$579
$0
$0
$579
$197
$2°
$353
$4 '1
I
0
379
$'09
$664
$4|7
$226
$0
$0
1!
PPC^
~"*s
$2.40
$0
IS"7:
$573
$0
ins
$0
$40
h **v
-" ^
$4iE
$21
$0
$0
$0
$109
$7?"
$286
$0
$0
$268
$"8
$14
$Pi
$265
i
0
' \ V
$573
$416
$265
$112
$0
$0
Year
12
TION
::0
$2.40
I'.f
$3;1
13:1
$0
* 7"1
$0
$25
ER°
$2c3
12i
$0
$0
$0
$78
$242
$165
$0
$0
$lb5
$!6
$6
11 00
$175
i
0
1 50
$3cl
$2:3
i!76
*:4
f :•
*<:
y a - •-
•~
-c
12,40
$0
1227
$22^
$0
145
$0
lit
EFF
-;•''. 5tj
121
$0
$0
$0
$36
$145
$3c;
$0
$0
$69
$30
$4
$54
1110
1
95
$227
$lo6
$110
$75
10
$0
ear
14
uO
$2.40
10
$143
$143
$0
$29
$0
$10
EFF
_ - T~
1105
$21
$0
$0
$0
$40
$84
$44
$0
$0
$44
$15
$2
$27
$56
I
0
60
$143
$105
$6c
$17
$('•
$0
15
78
$2.40
$0
$9)
$90
$0
$15
$0
$6
^p
_"/c 1 1
106
$21
$0
$0
$0
$40
$45
$5
$0
$0
15
$2
$0
$3
$43
1
n
38
190
$60
$43
$2
$0
$0
'ear
16
24
12.40
$0
$57
$57
$0
$11
$0
$4
EF.R
-45.2"
$42
$21
$0
$0
$0
$40
$20
i$19'<
$0
$0
i$19''
(*7i
i$l>
i$12'-
$26
i
i
0
24
157
$42
128
;*9.
$0
$0
'ear
1?
15
$2,40
$0
$7a
136
$0
$7
$0
$3
[5?
_71 •*?
$26
$21
$0
$0
$0
$20
$5
•$15)
$0
$0
i$!5i
i$5i
'$!>
!$9i
it;
1
0
15
136
$2o
$11
•*6>
$0
$0
Vear
19
9
$2.40
$0
$23
$23
$0
'$5
$0
$2
E?F
-11!. 47
$is
$21
10
10
$0
$0
($5;
•$5;
$0
$0
$5'
'$2'
•$:•
•13'
'131
.;,
0
$•1
$0
$0
J.-.
10
i''.
•Jjr
1"
:
$2. 40
t ",
$14
$14
J;',
$7
$'.'
i:
^
-•:Z" J"
i i ,",
$2:
$0
$0
$0
$0
.$11
'$1
in
$1'
$1
'$4
i:
t~
i
*0
i'.
5"
I1'
z '
^
--
Parrel: Oil F=r 5av:
a .'= cf c'roductic" =er 'ear;
7^5
3o5
$2o.54 $26.54
126.54 $26.54 $2i.54 $26.54 $2s.54 $2:. 54
^C" I-as :er Day:
""2" 3as ^e' (93r;
-------
"rice *£? 1Cr;
kl Pevenues '1000';
($000;:
Royalty Payflents-Qil (*000):
fa-aity ?a',ients-5as 'JOOO1;
Ee'-'era^ce Tawes-0il (lOOO1:
Severance Taues-':as ($000;:
ELF for Ajjct-a Severance Taxes'
ELF for nlast-a Severaics Ta^es-6as:
Net Revenues 11000!:
9perat:ng Casts;
E1pense; Poll.Con:,Cap,Costs '$000
Pollution Control Operating Costs:
For *[1 co!l, Control:
Depreciation 4 Aaorti:ation;
Operating Earnings '$000;;
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest JT, Tai
0
0
o
$0
$0
$0
$0
$0
$0
Year
21
OIL p'or-ijc
o
365
u
$26.34
5AS PFCv'jC
'i
0
$2.40
$2.40
$0
$6
*6
$0
11
$0
$0
0.00
-4t4. 75
$4
$21
$0
$0
$0
$0
($17)
($17)
$0
$0
'$17)
($6)
(Hi
'$10i
.$10;
0
y
0
$0
$0
$0
$0
$0
$0
Year
22
TION
U
363
fi
$2a.54
-I:-N
o
0
$2.40
$2,40
$0
$4
$4
10
$1
$0
$0
0.00
-73B,33
$3
$21
$0
$0
$0
$0
'$1B)
'$18)
$0
$0
($18')
($6'
i*l'
•$li;
•ill-
i
r
i
$1
$(
*'
$0
I'"'
fO
Jojr
j. j
t •
_ 1 2
$2t,34
•,
0
$2,40
12.40
$0
12
$2
$0
10
$0
$0
0.00
-1172.54
$2
$2!
$0
$0
10
$0
1*19!
'$19i
$0
$0
($19)
1*7)
ill)
''112)
1*12!
0
0
0
$0
$0
$0
$0
$0
$0
• ear
24
3^5
0
126.34
u
0
$2.40
$2.40
$0
$1
tl
$0
$0
$0
$0
0.00
-1861, 7o
$1
$21
$0
$0
$0
$0
'$20;
'$20;
$0
*0
1*20''
<$7>
(tl)
($12;
($12"
o
0
o
$0
$0
$0
to
$0
$0
Vear
25
fi
3t5
$2;. 34
I
f
$2. 4i
$2.40
$0
$;
$1
$0
$0
$0
$0
0,00
-2955,76
$1
$21
$0
$0
$0
$0
'$20)
($20)
$0
$0
>$20)
($7!
i*li
'$12)
'$12i
0
0
0
$0
$0
10
10
$0
10
•'ear
26
,-i
3o5
t;
$26.54
,;,
0
$2.40
$2,
-------
5ii Revenues 'fOOOi:
as ^evspLSS if GOG'1;
dtal Revenues '$000);
fioyalt/ :'a',"!!ents-0il (fOOO):
Foyaltv Favaents-Sas '$000!:
Severance Ta?es-C'il 'iOOOi;
Severance Ta:,$!3
n
n
0
$0
$0
fG
$0
$0
$0
$0
$0
$0
$0
$0
0.00
*********
fO
$21
$0
$0
if 21)
i$21i
$0
$0
'f 21)
1*7)
til)
•$13'
.*!!)
o
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
»*»****-30f
$0
$21
$0
$0
( $21)
($21)
$0
$0
if 21'
'$7)
($1)
i'$13'
«$13i
u
0
0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
0.00
198.64 **
$0
$21
$0
$0
!$21i
($21 i
$0
$0
'f21i
($7)
i*l)
•
I'.'
$11
$•
i1.1
I'"'
*0
10
*0
$0
$'.'
$)
0 . 00
*******
$'?
$21
$0
$0
!$21<
'$21'
$0
$0
.$21'
'$7i
'fli
•W
n-
i ~
: .
t '
-------
CV :» Set las" Flaws: f5*"'
FY c* E cess Depletion: $•!
:t Eurciu: LEpreciation; $0
F!.' ;f E peases If".'=s: Casn "lows: f^C5
CV cf Capitalized Cc=ts: $445
~T ^* _°5-9nz"2 Tcrt; 135
-J --.11 ;Ic"., Ic=t=: *0
P.1 :* ^c^aitieE - uii: $0
FY ct ^cvaities - 5as; ii99
Fv :f Severance Ta'<;es - 0:1: JO
"\' c* Ee'-sr3"ce Ta'es - c3i; 170
F1.1 :f "peratipg Costs; $60
;V :f" IicoTe T3'
-------
gioT 7 - sirgis 321 well
fear= Between Lease Sals
aid Start of Explor,: 0
Percent Casts Considered IZ'C =: il.OOi
Fe-cent Costs Expensed: id00?
Znlliig ^ud Cost incresent; 0, :(•'',
Co-pcrate Ta* Pate: 34?
State Corporate Ta,1: ^ate: 3,00 i
Z:r: Sf'^cture 'i-*aj2r Z-indecJ: Z
Zest Per Exploratory Hell; £72=
Drilhig dad Cost Increaent: JO
Discovery Efficiency: 0.71
Successful Expl. »eil: 1
'ear rear ***r
0 1
E''plor, Ccsts cer frcject; $i,OZ5 tO
^ost cf iuccessful E*'*cr:=: TZ3 10
E'dar:od Za=^ :'"^; J454 JO
Zapitali:°c Zasn PI 3*15: tZ5: *0
r" ot Evpersed E"pio'at;o" Cas*1 "laws; 1454
:v of Capitalized E»pl. Ca=n "ic^s: :Z°1
-.
10
fO
10
10
*0
•^
_'
$0
10
{0
10
10
V j* ii: E ::3rstDr- Costs:
DEVELOPMENT COSTS
"eta. >*-ast'uc:j's Ccst; $40
=i'= retussn Sta't of E'ploration
i'd Starl: of Ze^elDpient: 0
'•-'09' -••ells Z'rilled Der fear: 0
'ear rear •?£•" '9ar 'ear rea1" 'ear rsar
0 i Z 5 4 : o ~
tO $0 j' 10 $0 $0 JO $0
$0 $1 I: 10 JO 10 i'i tO
:'3 Z:sts -c^ tea-; $0 $0 i i
Z:nt Capital Z:S:E; *0 10 J)
-------
:tai ^"Tjal Capita: Ccst: $40 JO J'. J'i to JO $0 $0
a;: Shield - *3 to i: 10 $0 $0 JO $i
,persed Cash Flew: $ii +0 $0 JO JO $0 $0 $0
.tallied Casn "121*; tli JO J; JO JO to $0 JO
:'',! of 611 Development Casts; $*0
F'/ of E-persed Development C:sts: Jifc
CV 3t Capitalize: Deveiopsert C:sts: Jit
'srce-.t hatsr Cut i" Q&5 to Start: 2\
?:!'5as Prod. Dechre 5ats/rear il'; a3X
'Zest Escalatcr V: 'A
red5rai Tax Rate :'',': 34V.
State Tdi; Rate '"{i; 51/.
Average Depreciaticn Lf'e 'years'; 7
Deprec. rate lea:" year); 14.IW, 24.49? 17,4:''/I iZ.4v'i 6,93?
State Severance Ta* Pats-Oil: 7,00?
'If Alaska enter '9'
State Severance Tax Rate-Gas: 7,00?
'If Alaska enter 39l
PFGDUCTION COSTS
'ears Eetween Start c* Developient
ard Start 3* ^r^d-ctio". '-5i;
VJTiQar 3* '5J'S at :5a^ Pr;:;
•3:1 ''83* C'OL, 5ats.»eli ifao':
Ga-: cea* r.-Cd. Site'Jeil (HHCF-D':
Ni.i!Q9r cf Pr:3rcing Neils:
N'jii!Der o* *eii5 fut in 5ervice''Year 1
:rice of Jii Per Bar'ei: J26.54
"'ice :t" 5is F9r 1[c; $1.40
Tctii Cps'atrg Costs 'tOOOi: $21
P:1I Cont Oper Costs $'"rOO'1: $0
lavs :; ;'c;.:t::r. :er 'ear: 3o5
Year Year '?ar ''?ar V5ar fear
i Z 7 4 5
OIL ;qODUCT10N
^""odurin"t^Gii5i^S^rvi";3j [ ^ M c
5arr?l= ;* •];; Per Day: 0 '.< " 0 0
Davs cf P^cd-xcnon r?r "ear; 363 Ia5 7:5 3^5 3s5
•ice'sa'-ei c; C':I: $2t.!* tZfc.54 t;:,54 iZs.:4 JZi.:4 tZ6,54
-------
Mf" it -,jc ;=.- »=ar.
|;=,w * i.,,-
-.i"-sl 0;i ^-rces '*000>;
iriual Eas Revenues tlO'OO):
7otai Avenues '$000;;
H'Qv'altv Davnerts-Z'ii $000';
^vait', FavfflBiti-Z-as '$000';
Ee pranrg 7a*fi5-'3il '.$0-:0';
Eevsranie Ta".es-tas l$000':
Ei." tor bljsff£ Severance Ta"es-]:i:
r,_p ;;r v^i 3 Eeverance Ta-'95-']as:
Net ^p'-piues ' $'.'00 ' :
"eta; Zesting Easts '$000:;
E;;e"sed :'ril.C;-t,'2ap.2LSts '$000'
;-,;; ,-,,„ r.npr ')" n-i ~->-<-c . *r.iVi.
iaDitihred 2csts ;$000':
L'epreciaticP 4 Ascrti:ation '$000':
Operating Earnings 'tJOO1;
Earnirgs Beware ;n,:erast and 2'L'H:
Depletion ^ilo^aicB:
SurpLs Dspletio":
Eirnings ijetc^s Ir.terESt and ^a'-'ee;
i""1— ~* ~
lta:e Tar;
Earnings Bfit'c's !-:2rB=t w-t?r Ta' ;
,e: ra,r r;,w.
Enutc*'"
^-T,.^ ."., ' Irn,i ;vo^r .^3rr3i';il
:l EaE F'::, 'ea-- '^CF.;
-'ctjji Er;55 "e''PnL55 'fOOO':
Actual Net RB'TBIUSS '$000i;
Actual ^et Casn ~lo« !$000';
'-'ii'jji "a1 ?s Pai2 J0;"'0':
Iinit;h:93 Ecsts Net Emended:
: ,,; = -,£,„, p, , a^,nr.
3"9
$Z,40
$0
$905
$2,;.5
10
*1E2
$0
ti4
E:B
-1.°,?
f"4
$21
to
JO
$44
$643
t599
tP7
$0
$595
$204
13'!
I3t5
140 =
;
3"
$509
$664
$409
$234
$0
$0
""* ^
$2.40
JO
$573
$577
$0
$115
$0
$40
E55
-"'' TS1
**! =
*21
!•:
to
$75
t397
$322
$55
$0
$722
J109
$:;
I!3!
$2"2
-
275
$5"
$415
$2"2
$126
i.'.
JO
150
$2,40
$'"'
$761
J7:.
JO
J-T2
JO
•T J. J
rep
~- 1 j.:;
J2c3
$21
10
$0
$54
1242
il 59
$35
$0
J15C
J:.4
$5
$ll!
- .£"
15-
$3sl
$2:7
ri,.;
•T^
to
to
95
J2.40
$0
r'"7
i22"
to
$45
to
$16
Er^
- l 0 . 56
ti£6
•+ i. i
to
$0
$0
$33
$145
$107
$22
$0
tlO7
$3;
$5
$t:
t!03
;
i"i
=5
$227
lias
$103
$42
JO
$0
;.0
$2,40
$0
$143
$143
JO
$29
to
110
E9-
_, 7 ••=;
$105
$21
Ji)
$0
$0
J27
$84
$56
$14
$0
$5t
$1°
$3
$34
J:2
i
IJ
,M)
$1*3
$1)5
$c2
$22
JO
$0
35
$2.40
$0
* V,"
$3,;,
10
tlE
*0
$5
ESS
-25.12
166
$2i
$0
$0
$27
$45
$1T
$9
$0
$17
t&
$i
$' f
• 7B
i
,;,
76
J;0
lot
t-35
$'
$0
$0
24
t2,40
JO
$5"
i~j~
i"
$11
r,
$4
- H *T
-45,23
$42
$21
JO
$0
JO
$2'
$20
.$7,
$5
$0
'T'
'tZ-
JO'
'$4
*z:
i
t
Z4
$57
142
$27
' *7
JO
to
r 3
fZ.4'; t;>:
$0 $
i7t $27
J7: J23
j,;, j.;
r '$!
to J'.
J3 tZ
E": E"
-"2.7" -::5.4"
J2. t::
$21 $21
JO
$0 t1;
jo *•:
ti4 $•:
$5 •-*:
,f; .$;
t7 J2
JO t .
1 i S : ;
'f 7 :2
'ft.1' -
't;1 f;
t? J7
:f
; "**• f
$Zi J
$5
if 7' £'
t :• ••
r; j
rear
'fear
•ear
•ear
•ear
JiL
2ra'-s :: :':;-::::P :e
Is'^i'.: I'll :9r 'sar;
^'"ice Fer Earr?! i
..£3
$26.54 126.54
$2i.54 $Zt.!4
7t5
'.as fer uay:
-------
tZ.iO fZ.40 tZ.40 fZ.4t) fZ.40
»: :eve--s -t-^:.,
.-«* ^r-i 1000;;
Tcta: fevsrues 'tOOO-:
^ovaitv Pa'.signts-Qii 'JOOO':
*c>,a:ty Cr.aients-Gas 'fOOO;:
Ee-'eran-:e Taxes-Gil 'fOOO :
^oi-pranrg "avge-i5pc $fi|VV| •
ELF *cr p;aii; 5eve*ance Taxes-Oil;
ELC f'or iias'-a Severance 7a-5s-3as:
••et Avenues 'f 000':
Ops'atirg Costs;
E'pensed HOI!, Zcr:, Zap, Zests tOOOi
Fiiktiop C:-trcI Z'pe'jtirg Zests:
~ir t: F:I1, 3c"t'-:d Ta"es:
Feflsral 7a-:
State 'a-;
.Earnings Bet3re Ir'-2rest Aits* Tax:
f-er. 'If,:h :li>-:
- n n >• T * f
H.ct'ji! Zi: Zr-.i, ?ea' 'Ea"?!;1:
ht"1"1^3 5a^ ^'*"cc. yp^r ^^C^i;
-,.,., . -„ ;„ -n,,-- ,|r,|'n',.
M::!ja ^°t Fev9n-es 'fOOO1:
•f> - FU-» - -• r *r ' '
HitLia ~j'95 Fai3 tOOOJ:
:a*itaii:ed Ccsts ^:t E'pe-aec:
;, r-: .c 'a-'pr. p>- -T
t-0
t5
f?
to
iZ
to
f 1
0 , 00
-Z-Z.44
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tzi
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to
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to
to
to
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to
11
to
to
-464.73
14
tz;
to
to
to
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•117'
'*n
ti
to
itii
ti 1
i * i ,"i ,
,*[,;,,
V
i
0
to
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to
to
t4
f4
to
ti
to
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t:
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to
to
to
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to
to
tlB1'
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tZa.:4
tZ.40 tZ.40 tZ.40 1Z.40
-------
i r i ""
•
'Z'll C21-S''U2S 'tOO'!1: . tO t; JO JO JO JO J1.1 JO J1! -'.
flbs Se-en'-ies -lOOO:; tO tO JO JO JO tO t" JO J'. J'~
^ctai ,:>2i9nues 'JOOO1; tO tO JO JO JO JO JJ J.r JO -'.
E.oviit,' c'3V3entE-iJi; *t+tt*+»t»»tt^»+t+t*t**»tft*t»«
Net ?even':es JOOO ; to tO JO JO JO JO JO JO JO JO
use.-ati-.g Zasts: JZi JZi JZi JZi tZl JZi tZi JZ: JZ. JZi
:ollut:cr. Zcntrci 'Zperatirg Cc-sts: JO JO JO to fO tO JO JO J'! JJ
"cr ?v Fell. Zo^-t'cl: tO JO JO JO JO tO tO JO J; *-'.
Zaeratrg Ear^ir^s >JOOO'': -JZi' 'tZii itZl itZi1 'tZl' 'JZii 't:ii 'JZ;' -JZi' JZ:
Earnrgs Before Interest ani GDfi: 'tZi; 'tZi1 tZl' (tZi> itZl'1 [tZ:; 'tZi- -J2i' -JZi; JZi
Depletion Allowance: tO JO tO J; JO tO f. JO JO JO
Eurpirj5 Depistio": tO JO JO JO tO JO JO fO JO JO
Eanirgs ret'2-e Interest ani Tj-es: 'JZi' 'JZi' 'tZ'i- 'tZi- ftZi- 'tZi< (tZi; JZi1 JZi1 JZ:
r2derai Ta-: 't75 't7'' 'J7' 't7- 'f' 't7i it?/ '!"• •$? J"
Etats ~'i*\ 'tl: 'ti1 'Ji; 'tli '.tl1 itli .11'' 't:, >ti Ji
EaTi1]; Se*ore Interest ^fter Ta1-: 'Ji3' 'tl3' JiZ'1 'ti~i ti3' 't!3i 'tiZ1 t:3i JlZ1 Ji-»
JO JO JO JO tO JO to JO JO
to JO J<: to to Jo to jo jo
tO JO tO JO JO JO tO tO i"
tO JO JO tO tO tO to t; J:
-------
:• **et '. ==", *.GWS;
;• •' of E cess D°pis::on:
kv :•' ;.-'5i'.s Sep'sciat:
" - ;• E ;2"25C I"-5£t C£=n Flows; I'SOO
:'.' ;t 'I5sit = ii:ej Costs: $307
:v L* ..Siie^clj lest: *35
r:»! "til. Co^t, 'ISS'r! 10
?',' cf ;,c'.- aities - 'I'll: t'i
'V :• Boyalti3s - I-as: t:^p
FV c* Es^irance Ta:'ss - C:l: $0
:v 3* Ee'-'SrJ"C5 Tas-es - tas: *7v
:ii :• Gpsratirg C:st=: fiO
:v :f Ircame Ti^es: I^Z*
PV at Total Ccepany Costs: *l,40i
?J at" Total [cispiiy Costs - :ii: *0
:v c- Tata: Cospany C:sts - Gas: I!, 601
Hso't::ed Ccspa-y Cost per .ifSTij; $1,89
rtizsd Cospany Cost per bbi: E*R
:ed Caapa.r.' Cost oer 1CF: $1,?!
Pr::e on ^^BT'J Sasis - Oil $4,58
fosilnead Pr:;s cr, ^PTL oasis - 5as $2.35
t '-ai'-s o+' ^rijec $53
at= c*' Return; 0.116
CF; O.S
$0
$1,138
5cc:;i Costs - C.i:
:ea racial 3:s!: ::;;
;:ciil Co=t= - :as: $1,13;
-------
ate;
.ease I:=t:
Si- 5 £ ?;":e;
C:st se' E"picratcr> meii:
15
ana Start ct" E."p!ar,; 0
f-er:ent CoEtE C:nsi:erec IDC's: sO.OO;
Percent rests E'.&s'sei; 41,00'',
I'liii^g Hud C:s!: I"trei!ent: O.OOX
iorzcra'.s Tax Rate: Z1".
Etite Corporate 'a' ?3te: t,T5'i
CcrQ 5'ru;iar5 ' i"i?ajor'Z"i"flej!i; 1
i'lscover/ Eftinencr;
fuccssst'iii t'ipi. »eii:
0,!5
i
Vear <2ar 'jar
10 i'.' 10
tj JO iO
*0 *0 *0
' * ^
v ,3- E1 :?'';;: E"piarat:cn las"
ows:
7ctfl :EC::al::2C E 3!. C:=ts:
1244
«e3' rti't :+ E"plcration
tarr. ;*• I? slo^jent:
r:lis3 :9- 'ear:
to
to
to
11:3
to
i -,
to
to
tj
4 .'
*• t:
1 1 tO
to I;
-*v tO
fi. iv
t'.1
*'!
f>.
to
JO
to
to
' 1
to
to
to
t:
to
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to
to
to
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t:
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t <
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r
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t
-------
JO JO ;( 10 JO J-0 ;1
t; JO JO *:• JO JO J-0 JO J
J;j 5l J? JO JO 10 JO r'j {<'.
"~sts: il!3
"ir:e^r kfate' 2ut in Git5 to Start: 2';
']:! 5as Froa, feciire 'ate/i'sar 'V1 7Z'i
Zest Escalator (X1: 0',
^oyalty Fats >'i>: 12,50''.
State 7a- Fats '2): 7V.
Average ueprsciaticri Lite 'years1: 7
Z'epre;. ry.z 'eac1! year1; 14,~Jj\ 24,4?', i",4:<'. 12,4:'',
Stats Severance "as Bat9-['ii: 5,'X'i
•*I* Alaska enter 99i
State Severance "a? Fate-Gas:
' I* Alaska enter 5vi
and Stirt 3- Ir::,:ti:- : : i
:3i --:3, :a:= *eil 'c:i; 53
:9r- :":^, -ate selliil^CF I"; 0,072
:sr :t cro^cir: Jfeiis; 1
:?' :*' *sll; :at in 3eri-:.:e/'ear 1
:. Zperati'g Zests '$000;: 117
; Io".t 'JDer Costs 'tOOO): $0
765
r'ear 'sar '±ar '?ar T55*" f8a*" '85""
.5 i" :e--::5j
'. :;' 2av:
'sar
.4
-------
hiM „ ,; ,,£,; „£, ygjf.
^ice-^CF ot Eas:
Mr~,al 2:1 -9.9".»« '.tOOO-:
-ri'.al 3ai -eve-iMge ijiVjOi:
Tcta: :e>^'jes j'0'',>;
:o.'/aity Fa/is"ts-]il 'tOOO1;
Pcvaitv Fa,i8e"ts-5as tiOOO':
Eevsrance Ta»es-7:l
i '.
$150
$2:
$207
$23
$7
$'
$1
EPR
-110.63
$171
$17
$0
$0
$0
$35
$154
tils
11
$0
$i;5
$39
$8
toE
$107
j
7220
10
$207
$171
$107
$47
$0
$0
•ear
14
755
270
$24.33
$2.70
$i:0
$;5
$149
$15
$2
$5
$1
E™
-154,05
$127
$17
$0
to
to
$27
$105
$7"
$1
$0
$79
$27
$5
$47
$T4
,
5199
7
$149
$123
$74
$::
$'-
Jr'i
rear
15
i
%=;
155
$24.33
t
$2,"0
$54
f!4
1 1 ,•, -
$12
$2
$5
$0
EPS
-214,74
$59
$17
$0
$0
$0
$27
$72
$45
$0
$0
$44
$15
$3
$25
$54
;
3'43
5
$107
$35
$54
$15
$0
$0
'ear
is
,
7e5
140
$24.53
4
i2.70
fe-
ll i'!
$7T
$5
t'i
17,
to
EhP
-735.05
$64
tl7
to
to
$0
t27
$47
$20
to
•tit
$!c
$7
$1
$12
$73
i
203:
4
$77
$t4
f1
t5
$0
$•''
fear
I7
H
^ t c
i 0 1
$2-»,55
T
$2.:o
$43
i~
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$3
$!
$2
$0
:~f
-4;4.4'1
$4:
t!7
$0
$0
$0
$14
$2?
$;5
$0
$0
$15
$5
t '
19
i27
i940
~
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$4t
$27
$5
$0
r ',
j
i j
3&5
-'
$24.3;
12. "0 $2."'l
$35 $25
$5 $4
$40 flc
$i !~
$1 $'1
$2 $:
$0 JO
E:= E;i=
-5"5,94 -8 JO, 71
$77 $24
tr $r
$0 $0
$•. $0
$j $0
$0 $0
$1; $"
$1: r
$0 iO
$0 $:
t • - t~
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t- i~
fl $
$3 ;J
T" l:
;
' -:" : ' ' ,.
,_
$4v i2:
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$;0 -'.
t~j i ~*
1 1 t
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12.'
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— - — — ... I
-
Tc!:a; '•s1 ernes 't /."'(':
-c-il'-J ca',-s-its-0il 'tOOO-:
F:./al:<, Fa^ents-'Zas ct' Ov
Ee'-'erance Ta/'es-u:! '10' •:
C-5vera-:e "a'?=-5;; '.tOi '':
EL/ *"cr Alaska 5everance TaxsE~0;l;
'•?t *e'-E'"-3E ti'OO) :
Operating C:sts;
E-pensed Fell. Cent. Cap. C:sts rtOOOr
Fcil^tiQfi Centre; Operating Casts;
ror c;- c"il, Cort'cl;
Decree' ati on * ^eort'z^ticn;
Operating Earnings itOOO1:
Earnings 5e*cre Interest ana GDfl:
Depletion Hilenanee:
"'T^lu1 i}an' p»' ir >
Eatings Be*:-- Iite«st a-d Taxes:
Federal Ta- ;
Etate Ta-:
|ar"in;s Be-"ore Interest ^rter 7a":
"et -lasr. =l:u:
E'-ut:"'
ict'-ial 111 -r<:S,.'Vsa- sar-el=):
Actual Gas Fred, iear '?"!"CFi;
^ct.al Jra!i seve"i:es ;tOOC":
Actual Net Revenues itOOO'i
Actual Met Cash Hew 'tOOO'1:
£:ti:a; Ta' es "aid tOOOr:
Capitalized Ccsts Met E: penced:
Surplus Dep'eciaticr:
Ei-reiE 0:1 :er Da^.
Cays 3r Deduction ;er rea[;
:arre'.= Oil per rear:
F'rice Per Earrei;
\
**r.: Sas "er Day:
"H_P '^,35 »-'»•• -par;
Prl:e :£r «CF;
tie
13
12!
12
to
t:
to
'.' , 00 i
_ \ 1 M 5"! _ 1 Hi^
IF
$17
JO
to
to
to
to
to
to
to
to
to
to
10
jo
1
724
i
121
t! 7
to
to
to
to
Vear Year
21
JIL PRODUCTION
IJ
7fc5
- -?
t24,98 124
5A5 P^ODur^IGN
'j
1 1
12. "M t2
tl:
12
115
12
to
t:
10
-.- -.
112
t!7
to
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ll'l
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15 1
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17
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117
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to
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'till
•14,
't!1
It;
'tfc1
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365
10
124. '5
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ti
tt
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ti7
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to
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''tl2'
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to
;t!2)
i$4'
'tl'
'17'
'$7''
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to
to
to
t'l
to
to
'ear v
25
r
7t5
1
124. 98
o
0
!2."0
14
t:
14
to
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26
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365
5
124.93
h
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12. Ml
il
10
r
to
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,-, ,-.,-,
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117
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i.115'
•tl5i
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'115)
'15'
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I191
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to
10
to
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3s5
4
124.58
Ij
if
$2.70
12 11
to t'.' :
12 t!
ii ' f i"' '*'
^0 tO i.
to to o
i(! 10 tO
" r. t* .*• ,"i i . ."• .', n
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117 IF IF
IN IM :],
to to to
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to to i :
to to o
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'11.' t;' !;•
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to to 10
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to to io
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0 • i
7o5 7i5 7:5
T
124. '8 124. =5 iC-i.:E
12.70 12."' iC."
-------
0:i fe^9"'jes 'JOOO1;
•is Revenues vJuuu'1;
eta: '''e-enues 'JOOOi:
-oyaitv fayse-its-OiI '*G»0;:
Royalty Payaerts-Gas '.10 'O1:
Severance T;^es-0il .*00 '•;
Severance Taves-5a= 'JOO":
ELF tor Alaska Severance faxes~0ii;
ELF for uiasi;a Eeverar:2 "axes-cas:
^et Fr"<'°ri-es '. J0(0 ;
'Jperat:n3 Casts:
;GlIjti:n Control Operating Casts:
Far Fv P:li, Cont'ci:
Depreciation 4 nacrtizaticn:
Operating Earnings iJOOO);
Earr:ngs Pe*ore Interest and QDA:
Depletion Allowance:
Surplus E'epietic":
Earnings Be+ore Interest and Taxes:
Federal Ta;;:
State Ta*;
Earnings Befcre Interest fitter Tar:
x
'J16;
JO
JO
*lai
'J6!
'Jl'
i*!0)
'JlOi
JO
JO
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JO
JO
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JO
JO
JO
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JO
JO
JO
JO
JO
JO
JO
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JO
JO
JO
to
JO
*0
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0 i"i{".
****************** »t*******»***t****- 15
JO
J17
JO
JO
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JO
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•Ji)
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JO
JO
ijr
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^hctD*f
Actual Oil Drod,"'ea' 'Barrels
'"-••••- '1-15 P'Dd. 'vear 'fCCFf:
']rc5= Seventies 'JOCO'1:
J(P* -ievpnjes 'JvOO):
•^et uasn ^iow iJ'.'Ou1;
nrtuai Ta.ss Faid 'J00( r:
o
JO
JO
JO
JO
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JO
JO
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I
I
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-------
at **et Casf Flows: J"2
of t: :ess Depletion: - iO
cf surplus Depreciation: JO
;'V c* £-pensecf :nvest Casn flows: *3'7
:/ of Capitalizes Casts: 17')4
FV o* .easenrld Ccst: $E
F". c- Fcvaltiss - C-as: $12
F\ a' Ssverance Ta'55 - jii: $33
Ci. of Caerating Casts: Isi
FV of T?tal Cospany Costs; 11,2+2
Fv ct Total Cc'jpa'-y Casts - Cii: $1,055
:V or Total Cajipany Casts - Sas: $157
iic'tirss Ccspany Ccst per *!hBTu: 13,25
fiaorti:sa Cospany Cost per bbl: tl'i',44
•inortned Ccmpar-/ Cast per ^CF:
Wellhead P^::e on 1HETl oasis - Oil $4,:i
hei'.nead ?n:e on ^BTU :asis - 5as $2.fc4
rod. .^e7^: 361,736
'jai :r5S9^t value of projec *S6
>:2r"ji -at? o» Return: 0.131
:':;a:lr CC*: 0.5
^""jalizsi ^?i1.Cant.Casts: ^0
'.1 :• ccial Casts - :tal:
H-cr:::s; :oc:al Cast ^^tTy tl,44
Fv :» 5cc:ii Costs - 'Jii: tcl3
H^cr^zsa C-oc:al Cas:'Dbi: $15.30
F-; a» Eac'.ai Costs - Gas: $11^
rrtizsd Ecaiai lost *fCr! *[.l5
-------
Project Type:
Region 6 - single oil
Lest:
tit E> sense:
Leasehold Cast:
Feal Discount Pate:
Years Between Lease Sale
ard Start o+ Explor,:
Percent Costs Considered IDC s:
Percent Costs Expensed:
Drilling Hud Cost Increiert;
Corporate Ta* Rate:
State Corporate Tax Rats:
Carp Structure 'l-iajcr/Z-indepi:
Ccst Per Exploratory Well:
Drilling Hud Cost Increient:
Discovery Efficiency:
Successful Expl. Well:
56. TV?
is
5.002
0
flO.C'O?
40. OCX
0,00?
341/.
6.75?
EXPLORATION COSTS
$0
0.55
1
rear
rear
•ear
rear
^Explor, Costs Per Project:
Et of Successful Efforts:
Expensed Costs:
Expensed Cash Flows:
Capitalized Cash Pious:
r\> of Expensed Exploration Casn He
F'V of Capitalized Expi. Casn Flows:
Total Capitalized E*pl, Costs;
:v of all £;.ploratory Costs:
$7o6 tO
*4:i to
J597 |M
$3^4 tO
tlcS to
WE: t3?4
sl63
tlsB
to
to
to
to
to
to
to
to
to
to
Tatal infrastructure Cost:
tears Between Start of Exploration
a"? Start of Developient:
Nm^er o» Wells Drilled:
Nufoer wells Drilled Per Year:
>il!:ng lost Per Hell:
Drilling Cost Per Weil:
Drilling Hud Cost Increient:
NtiaSer o» uleils Driiisd;
Total Drilling Costs for Year;
Annual Infrastructure Cost:
Annual •'oil Cant Capital Costs:
DEVELOPMENT COSTS
$103
0
o
0
to
Year fear
0
to
to
o
to
ti03
JO
Year
1
to
to
to
to
tj
t'ear
to
to
t'"'
to
*l.l
Year
to
to
0
to
to
to
•ear
4
to
to
0
*•'
to
to
Vear 'ear '9;1" "5£r
5 4 ' :
to to to i i
tO tO tO J :
o 'j •:
$o t" t: .' ;
to $•'' to ; -:
$; jo $• • :
-------
T:tal Annual Capital Cost;
_[ax Shield:
Ipensed [ash Flow:
Lapitahied Lash Flow;
FV of Ail Dsvelapaent Costs:
FV of E;-penssd Deveiopient Costs:
PV 2* Capita!i:ed Development tests:
$103
$21
$41
$41
to
$0
$0
$0
JO
to
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
10
$0
$0
$0
$0
JO
to
$0
*j
$0
10
iO
$0
$0
i.:
${
1'!
t("
$103
$4!
$41
FINANCIAL RATES
Percent Water Cut in G&G to Start:
Oil/Gas p-od, Decline sate/r'ear (X)
Cost Escalator '''.':
Foyalty Hate i?):
Federal Tax Rate >V:
State Tax Rate '.A!:
Average Depreciation Life (years):
Deprec, rate (each year):
State Severance Tax Rate-Oil:
'It Alaska enter W
State Severance Tax Rate-Gas:
(H Aiasira enter l
12.50?
141
n
14,297.
5,007.
24. 491/. 17.49;i 12.
8.93J
H.92X S.93S 4.4sl
PRODUCTION COSTS
VearE Between Start ot Developnent
and Etart cf Productian t-'5): 1
Dumber of \ears at Feat; Prod: 1
0:1 c'eat Fred. Fate/Well (bb'S 53
Sas Feat- °rnd, Pate/Keli (HHCF'D): 0.072
Ncsber ot Producing dells: 1
NLubsr :f wells Fut in Service/Year 1
:'rice ot Oil Per Barrel: $24,98
Price ot Sas Per HCF: $2.70
Total Operating Costs !$000): $17
•foil Cont Oper Costs ($000): $0
Da',s ct p'o:u:t:on Per Year: 365
Froducirg Hells in Service:
Barrels of Oil Per Day:
lays of Production Per ''ear:
Barrels o+ ];I F?r rear:
kPr:ce/Barrei cf Oil:
Year Year 'ear "sar *ear fear
12345
fear rear
'ear 'ear
OIL PRODUCTION
1
53
365
19345
$24.98
0
33
365
13*28
$24.98
n
27
365
10028
$24, ?S
0
20
365
7220
$24. =8
u
14
365
51'9
$24.98
10
365
3743
$24.98
1
i
365
2o95
$24.93
5 4
3a5 3i5
1=40 13=-
124.55 $J4.'9
~
7r?
i ' " ' L
tl-t.1;
SAS FPOD'JCTICN
-------
at Gas Per Day:
J1HCF of Gas per 'rear:
K:e/HCF of Sas:
Oii Avenues '$000):
Annuai Gas Revenues i*000>:
Tota: Fivenaes 'lOOCu;
Royalty Paysents-Gii 'fOOOi:
Fayaity Paysents-Sas $000i:
Depreciation i Afflorti ration ($000):
Operating Earnings '$000):
Earnings Before Interest and DBA:
Depletion Allowance;
Surplus Depletion;
Earnings Before Interest and Taxes:
federal Tax:
ritate Ta<:
Earnings Before Interest After Ta":
Net Casd clan:
ShutcfP
Actual Qii Prod. /rear (Barrels/;
Mctuai Sas Prod..tear '.HHCFh
Actual 3ross "evenues \$000>:
Actual Net Revenues 1*000* :
Actual Net Cash Flow itOOO1:
Actual Ta;es Paid ($000):
o
26
12.70
$461
171
$554
$60
$9
$:4
$2
ERR
•40,67
$459
$<7
JO
$0
$210
1:0
$442
$412
$64
$0
1410
$139
I2B
$243
$2-5
1
19345
26
$554
$459
$275
$167
t_!
1 9
$2.70
$348
$51
1399
$43
$6
$17
I!
ERR
-56. S7
$330
$17
$0
$0
$0
$51
1313
$262
$46
$0
$260
$89
$18
$154
$207
1
1392S
I5
$399
$330
1207
$10o
0
14
$2.T0
$251
$37
$267
$31
$5
$1:
$1
EFR
-79,33
$278
$17
$0
$0
$0
*37
$221
$184
$33
$0
1153
$62
$12
$108
$146
i
10028
14
$267
$238
$14s
$'5
0
10
$2.70
$150
$2o
$207
$23
$3
$9
$1
ER«
-110.63
$171
$17
$0
$0
$0
$26
$154
$128
$24
$0
$127
$43
$9
$75
$102
1
7220
10
$207
$171
$102
$52
0
7
$2.70
$130
$19
$149
$lo
$2
$6
$1
ERR
-154.05
$123
$17
$0
$0
$0
$19
$10i
$88
$17
$0
$87
$30
$6
$52
$71
1
5199
7
$149
$123
$71
$35
f't
c
$2.70
$94
114
$107
$12
12
$5
$0
ERR
-214.34
$89
$17
$0
$0
$0
$1?
$72
$53
$12
$0
$53
$18
$4
$31
i50
i
i
3743
5
$107
$89
$50
$21
0
4
J2.70
$bl
$10
i?7
$8
$1
$3
$0
EFF
-298.08
$64
$17
$0
$0
$0
$19
$47
$28
$9
$0
$28
$9
$2
$17
$3a
1
2s 95
4
$77
$64
$3o
$11
0
T
$2.70
$48
$7
$56
$6
$i
$2
$0
Ef~ h
-414.40
$4t
$17
$0
$0
$0
$9
$29
$20
$s
$0
$19
$7
$1
$12
$21
;
1940
.'
$56
$4i
$21
$8
0
-,
$2.7V
$35
$5
$40
$4
$1
$2
$0
ESS
-575.94
$73
$17
$0
$0
$0
$0
$lfl
$16
$5
$0
$1:
$:
$:
$9
$10
1357
i.
$40
$33
$10
r
A
f ",",
$25
$4
$29
i3
$0
$1
$0
££9
-500.30
i;j
* i 7
•* t
$0
$0
$0
$0
$7
$"
$7
$0
i"'
t ~
r."f
$"
t:
1 .'".•:
±
$29
i24
i^
r "*"
Cap:r.5hred Cent? Not Expended;
:ur;i'j= 2'=p'e:iat:on:
$0 $0 $0 $0 $0
$0 $0 $0 $0 $0
$0 $0 $0 JO
$0 $0 iO iv
Year Year -ear »ear 'rear rear -ear 'ear fear
11 12 13 14 15 16 17 15
OIL ADDUCTION
rei= uii Fer jay;
Days a* Prc3acti:r ;er 'ear;
Parrels Gi! "9r "ear;
Frice Per carrel;
365
724
$24.98
5A5 PR'JD'JITIO1"
3s5
521
$24.98
375
$24,9g
365
270
$24.98
1
365
195
$24.98
0
365
140
$24.96
.•53
101
$24.95
73
$24.95
$24,95
as ^er Dav;
Sas Per 'ea':
-------
$2.70 $2.70 t2,70 $2.70 $2.70
Pevenues '$000):
3i.s Revenues ;*000):
Tetal Revenues ifOOO'1:
Fovaltv :'a/!sents-0i: ($000';
Royalty Payments-Gas '$000;:
Severance Ta?es-]il 'tOOO>:
Severance Taxes-5as '$000i;
£l~ for Alaska Severance Tai'es-Gii:
ELF for Alaska Severance Taxes-Gas:
Net RevenuesilOOOi!
C'peratirg Costs:
Expensed Poll.Cent.Cap.Costs '$000)
Foliation L3rtr?i Operating Costs:
ror fv Poll. Contr:!:
Depreciation *< Amortization:
Operating Earnings :$000'f;
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depletion;
Earnings Before Interest and Taxes:
Federal 'ax:
State Tar.;
Earnings Before Interest fitter Tax:
Net Cash Finn;
Sr.utcff
Actual Cii P'od.-'rear 'Barrels);
Actual Gas Prod, "'ear 'HMCFi:
Actual dress Reverses '$000i;
Actual Net Pevenues '$000):
Actual Net Casn Hon '$000';
Actual Ta1 es Paid {$000i:
'7ap:t?h:ad Cost; Not Emended:
Surplus Depreciation:
Barrels Oil Per Day:
Says or Production per rear:
Barrels Cii For '!gar;
Price Fer Barrel;
"L" 3as :sr
$18
$3
$21
$2
to
$1
to
: 0.00 '!
: -1111.92 -1544
$17
$17
) $0
$0
$0
$0
$0
$0
$2
$0
: $0
$0
$0
: $0
$0
£
724
1
$21
$17
$0
$0
$0
$0
Year Year
21
OIL PRODUCTION
0
765
27
$24.95 $24
SA5 PRODUCT I 'jkJ
0
j
$2. 70 $2
$17
$2
$15
42
10
i!
$0
.00
$12
$17
$0
$0
$0
$0
1*5)
($5)
$2
$0
i*5)
<*2)
i$0i
($3)
;$3i
o
M
o
*0
$0
$0
to
$0
$0
22
i",
365
20
.'8
0
'}
. 7 )
$5
$1
$11
$1
to
$0
to
0.00
-2145.54
i?
?r
to
$0
$0
$0
($8)
'.$8)
tl
to
1*6)
<$3;
i$l'
'$5'
•*5)
0
o
o
$0
$0
to
$0
$0
$0
r?ar
::
! \
•',.-
M
*24.*S
1 1
0
$2.7o
$7
ti
$8
$1
$0
$0
$0
0,00
-2980. 72
tc
$17
to
$0
$0
$0
($11)
($11)
$1
$0
1*11'
i$4!
($1!
($6)
(*t>)
0
0
o
$0
$0
$0
$0
$0
$0
rear
24
,;,
3:5
10
$24.9P
M
(,
$2."0
$5
$1
t&
tl
to
$0
$0
0.00
-4140.27
$5
$r
to
$0
$0
$0
($12''
i*12i
$1
$0
|.*12)
($4)
($1)
($7)
($7)
0
o
0
$0
$0
$0
$0
$0
$0
rear
-i;
o
365
7
$24, "6
0
o
$2.70
$4
$1
$4
$0
$0
$0
$0
0 = 00
-5750. 7~
$7
$17
$0
$0
$0
$0
i*14)
($14!
$0
$0
i*l<)
i*5i
'$11
i $8!
i*8)
0
0
o
$0
$0
$0
$0
$0
$0
•'ear
26
0
365
r
$24.^8
r<
$2,7
$3
to
$3
to
to
to
$0
o.co
-7=57,57
$2
$17
to
$0
$0
$0
($15!
($15;
to
$0
i$15)
($5'
($!')
i*9;
•$?>
0
0
o
$0
$0
to
*0
it la
'$5
. I '
't;l
ti"
!'.•
t;
i>\
-rO
t!
* i'i
pa-
::
~- ~
A
* 4.*^ , ^ ""
- * -
-------
^ii Setfip-^as 'tOCO; :
HE ••evenues '1000';
Tcta: Fs/iPLies 'tCOO):
So/alty Brents-Oil 'tOOO;:
Fzvalt;.' ci/T!ert3-3as ifOOO;:
Ee;:*< uOOO'1:
Actua Taies ca:2 •$•::•:•/:
$1
$0
t:
to
to
$'•'
to
0.00
7-25.1o **
11
$17
to
to
ttlo)
'tlu!
$0
to
itlfi1'
($61
;$!.'
.$10)
'tiO'<
0
o
0
>n
vs
to
to
$0
I:
to
ti
to
$0
to
to
['} . .'|H
****»»»**
to
$17
to
to
'tl7;
•ti7'
to
to
($17'
($t)
it!)
i$10i
•$10'
)
tr.
*U
to
to
to
$0
to
to
to
to
to
to
0.00
»**+*+**«
to
$17
to
to
'$17'
(tr-
to
to
;ti71
•t6i
'$P
'tlOi
1 $10'
l".
0
1?
tt'r
?V
$0
$0
to
iO
to
to
to
to
to
to
1 j . '.' 0
****^ttt*
to
$17
to
to
,t:7,
I$l7i
to
to
•$17)
'.t:.!
i$l!
$10;
l$10'r
o
v
*n
?y
to
to
to
to
$0
£•"•
to
to
to
to
).00
*******
to
$17
to
$0
,$17!
i$!7)
$0
to
.$17;
l$6)
;$1)
'$10;
',$10!
0
o
0
in
*y
to
to
$0
to
to
to
to
1C
$0
to
0 . 00
-153629.11
to
$17
$0
to
'$17)
($17)
$0
to
t$I7)
'$6!
•'$!)
'.$10)
'HO!
{ i
0
u
tfl
f\l
to
$0
to
to
to
to
to
to
$0
to
0.00
***•»****+**
to
117
to
to
i$17'
i$17;
$0
$0
!$17)
($6)
i$l)
ft 10;
(I10»
0
0
(1
*,',
* U
to
to
to
to
to
to
to
to
to
to
0.00
*********
to
$17
$0
to
($17!
i.$17i
to
tO
'ti7i
i$fci
'$!)
'$10)
'$10,
0
0
0
$;.
..'
to
$0
to
to
to
to
to
$0
to
to
0.0'j
*********
to
tl7
10
t'-
!$17;
;$D
to
$0
•$17;
($6;
it'i
.$10
'$10'
j. •
J ' '
t..
JO
to
!.
; ]
r ."
fO
to
to
to
'_; , ij i;
*******
tf
tl'
$0
$c
itl7'
"tl7
to
to
!*!7
iti<
't:
•$..
1 il .
- -
r ",
t:
5.;
-------
PV at Net Cast-; Flows; 1743
cf Excess Deoletion: . $0
cf Sunlus Depreciation: $0
-vest Casr, Flows: $*35
P'v :f Capitalized Casts: $210
:v of .sasehoid Cost: *2
Fv =::i. Cert. Costs: $0
PY cf Royalties - Qii: $S3
'V of ^ovalties - sas: 112
P1/ cf Severance Taxes - C-il: 133
:^i of Severance Taxes - 6as: 13
F'V of Operating Casts; *6i
''•! af Incase Ta?es: $396
PV cf Total Coipany Costs: $1,240
PV of Total Ccupany Costs - Oil; $1,OE3
PV cf Total Coipany Costs - Gas: *157
Aic^tized Coipany Cost per MBTU: $3.25
Aiortized Coipany Cost per bbi: $20,39
Mortized Caspar/ Cost per HCF: $2.17
Wellhead Price on HHBTU basis - Oil $4.31
rtellnead Pn:e on M1BTU Oasis - Sas $2.64
Eqi;iv. of Qil Prod.'.hb): 53,115
Equiv. o* Gas H^CF..; 72
Equiv. cf Frod. 'dHBTU): 381,738
F'resent value of Projec $90
rnji Rate of Return: 0.135
'jR: 0,5
al i:ed Pall. Cant. Costs: $0
F'J cf Social Costs - Total:
Hitcrtired Social Cosc/Hf
-------
Run Date:
reject Type:
Tease Cost:
646 Expense:
Leasenold Cost:
Peal Discount Fate:
fears Between Lease Sals
and Start :f Explor.:
fercent Costs Considered IDC's:
Percent Costs Expensed:
Drilling Hud Cost Increaent:
Corporate Tax Rate:
State Corporate Tax Sate:
Corp Structure 'l-iajor/2-indepi:
Cost Per Exploratory Hell;
Driihng !1ud Cost Increasent:
Discovery Efficiency:
Successful Expl. Hell:
29-Apr-37
Region ? - single oil i*e!l
$2
58.302
$4
8.00'i
0
60.00*
42.00?
O.OOZ
347.
6.00'i
i
EXPLORATION CCSTS
$4<>2
$0
0.72
'ear
Year
rear
rear
rspior. Costs Per Project:
ost cf Successful Efforts:
E1 pensed Costs:
Expensed Cash Cl3«s:
Capitahzsc Casi Fl3Ks:
Fv 3t E-persed Exploration Cash Flows:
PV o* Cap:tah:ed Expl, Cash Flows:
Total Capitalized E"pl. Costs:
:v ot all £> pi oratory Costs:
0 1
$683 $0
!4'2 $0
$'99 |i1
*Ii>3 $0
$285 $0
ws: $2s3
$285
$285
$683
T
$0
$0
$0
$0
$0
-
$0
$0
$0
$0
$0
Total ht'rastructure Cost:
'•sar= Between Start of Exploration
a-d Start of Developaent:
N:jTaer of Hens Drilled:
Wuicer Wells Drilled Per /ear:
E"1.11 ing Cost Per lieil:
DEVELOPMENT COSTS
$109
0
o
0
$0
Year
'ear
•ear
"ear
fear
Year
Year
fear
2'ilhng Cost Per well:
.Drilling lud Cost Increient;
ber of itells Drilled:
Total Drilling Costs for 'ear;
Anruai Infrastructure Cost:
"T'uil co;l 'Ion*. Capi:ai C:sts:
$0
$0
fr
JO
$10=
$0
$0
$0
o
$0
$0
$0
ti-
ll
JO
$0
JO
$0
$0
r'l
$0
JO
$0
$0
$0
o
$0
$0
JO
$0
$0
0
JO
tj
$0
$0
$0
M
$'•'
$0
$'?
$0 $"
$'! i"
0 •':
$0 $•'•
tO $'.'
$0 $0
•t .'
t "
i
f-
r ,
-------
Tctal lirr.ual Capital Cost:
lax Shield:
penssd Cash Flew:
TapitahzsJ Cash Flow:
PV at All Development Costs:
FV of Expensed Development Costs:
FV of Capitahred Development tests;
J109
116
$30
J63
J
J
t
f
JO
; JO
to
JO
to
JO
to
to
t:
to
JO
to
JO
to
to
to
JO
JO
to
JO
to
to
to
to
f f"i r
JO *
JO >
JO i\
$109
J30
FINANCIAL
Percent Water Cut in Q&6 to Start:
Oil/Sas Prod. Decline Fate/ rear ''/.)
Cost Escalator i?i:
Royalty Rats (2):
rsd5rai T3i: Fate (''.".
State Ta'; Pate '?):
Ave'age Depreciation Life i/earsi:
Deprec. rate (each year1:
State Severance Tax Rate-Oil:
'If Alasta enter 3?i
State Severance Tax Rate-fias:
(If Alaska enter 99>
16.00X
34Z
67.
7
14.Z9Z 24.W 17.-19'/, i2.4v"i
4.002
4.00Z
8.922 8.932
4.462
PRODUCTION COSTS
fears tetxeen Start of Developaent
and Start of Production i 5': 1
Nusber of Years at Peak Prod: 1
Oil pean Prcd, Rate'fell'fab): 32
Gas Peal> ?rod. Pate-xell tHflCF/D): 0.069
Ntisber of Froducing sells: 1
M'-soer of «ielis Put in Service/fear 1
rrics cf Oil p?r Barrel: t25.49
--ice cf Sas Per KCF; t3.0l
Total C'perat:ng Costs ilOOO): $18
foil Cont Ocer Costs itOOO): tO
Days ci pr:di::t:on Per Year: 365
Year Year 'rear -sar rear Year
I I T 4 5
vear
•ear
OIL PRODUCTION
f-ciu:ing Weils in Service:
Bar,-?!; of Oil Per Day:
Jays :f P'cc'jcticf Fe^ vear:
rar-ei; of Dil ce' ''ear;
365
llotiO
rice(tarrei :t uil;
345
t!5.49
165
5046
3o5
5543
t25.49
13
365
4601
J25.4?
10
3oo
38 13
J25.49
JI5.45
-------
MHCF of sas Per Day:
JM'CF of Gas Per Year:
s, MCF if 3as:
Annual uil Revenues '$000):
Annual 5as Revenues i$000i:
Total Revenues ($000':
Royalty Fay*en.ts-Gii '$000.':
Royalty faysients-'jas '$000);
evsrance Taxes-Oil i$000i:
everance Taxes-Sas i$000;:
Lr for Alaska Severance Taxes-Oil:
ELF ;or Alaska Severance Taxes-Sas:
Net Revenues i$000,!;
T:tal Cperatirg Costs flOOO*:
Expensed roil,Cent.Cap.Costs '$000.'
Foil.Con.Operating Crsts ($000;:
Capitalized Costs i$000);
Depreciation 4 Amortization ',$000!:
Operating Earnings $0001;
Earnings Before Interest and QUA:
Depletion Allowance:
Surplus Depletion:
Ea-nmgs Before Interest and Taxes:
Federal Tax:
Pttate Tax:
Earnings refore interest After Tji:
Set Casn rla»:
Actual Oil 'rcd./'f'sar 'Barrels';
Actual 3as Prod,,'fear 'fHCFi:
Actual 6ros5 Revenue; i$000i:
Actual ™et Revenues '$000':
A:t:jai **st Cas^ Flow i.$000';
Actual T3'es Paid '$000':
Capitalized Costs '•at Expended:
carrel; uii per Dav:
ays of F'oduction Per i-ear:
ar'els 0:1 :*r 'ear:
'ice cer Barrel:
M[" Gas pe" Day:
CF Gas Ps' ''ear
l)
25
$3,01 $
$298
$76
$374
$45
$12
$12
$3
: ER"
: -42,48 -5
$299
$16
$0
$0
$349
: $50
$281
$231
$1
$0
: $231
$75
$14
: $133
*18=
!
llaSO
25
$374
$299
$189
$92
$0
$0
Year Year
il
OIL PRODUCTION
C
365
1312
$25.49 $2
GAS ft-'ijDuu .0^
0
21
3.01
$247
Jo3
$310
$40
$10
$10
$3
ERR
1.3?
$24S
$18
$0
$0
$0
$35
$230
$145
$1
$0
$144
$49
$9
$87
$173
1
Y694
21
$310
$246
$173
$53
$0
$0
-
4
3i5
1504
5.49
0
17
$3.01
$205
$52
$257
$33
$8
$8
$2
ERR
-62,11
$2ii
$16
ro
$0
$0
$61
$158
$127
$0
$0
$127
$43
$3
$76
$137
[
304a
17
$257
$20 o
I137
*5:
*C
t ',
•ea-
•:
'
C65
1248
$25,45
y
14
$3.01
$170
$43
$214
$27
$7
$7
$2
ERR
-75.04
H71
$16
$0
$0
$0
$44
$153
$110
$0
$0
$109
$37
$7
$66
$10"?
i
6678
14
$214
$171
$109
$44
$0
10
•ear
14
-
3s5
1036
$25.45
fj
1C
$3.01
$141
$33
$!77
$23
$6
$6
$1
ERR
-90.61
$142
$18
$0
$0
$0
$31
$124
$93
$0
$0
$93
$31
$6
$56
$87
,
5543
* L
$17?
$142
$87
$37
$0
$0
tear
15
-
365
S&O
$25.43
.j
10
$3.0:
$i!7
$30
$;47
$19
$5
$5
$•
ERR
-105.38
$115
$18
$0
$0
$0
$31
$100
*69
$0
$0
$69
$23
$4
$41
i72
1
4601
10
$147
$118
$72
$27
$0
$0
'ear
lo
2
365
7!4
$25.49
0
8
$3.01
$97
$25
$122
$li
$4
$4
$1
ERP
-13:, 59
$55
$13
$0
$0
$0
$31
$60
$49
$0
$0
149
$17
$3
$29
$oO
\
3819
3
$122
$93
$60
$19
$0
;<:<
tear
;7
-
3t5
593
$25,45
0
7
$3.01
$E:
•f j^ i
$10:
$13
$3
*3
$1
ZZ-Z
-159.22
$8i
$18
$0
10
$0
$16
$c3
$43
$0
$0
$46
$la
$3
$29
$44
i
31o9
7
$101
$81
$44
*!'
$•:
10
'ear
15
'.
365
452
$25.49
;
$3.:1
i,;/
$17
$E4
$il
$3
$3
$1
ERF
-152.0-
^
$1E
$0
$0
$0
$0
$50
1 50
$0
$0
J4^
$ l"1
;C
$:•'
t ^ i
2t31
:
1 14
$5"
f '''i
-'-''
$0
•"
•ear
;:
-tr
-.'E
iC:.i5
-------
)l Revenues '$000 ;
Bas ^svefjES '$000 :
Totai Eeverues f$0 »."';;
Soyait/ PavJeits-Oil 'iOOO'1:
F:yalt', ca>?!er:s-6as 1*0:0):
Es-sranc; Ta"es-C'ii i$000 :
Severance Taxes-Gas ($000):
ELF for Alaska Severance Taxes-Oil:
ELF for Alaska Severance Taxes-Gas:
Net !evenuesi$000):
Operating Costs;
Expensed Poil.Cort.Cap,Costs '*000i
Pollution Control Operating Costs;
ror ?'/ Foil. Centre!:
Depreciation 4 Anortization:
Operating Earnings ($0005;
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Ta";
tarnings Before Interest After Tax:
'et Cash Flow:
Snutoff"
Actual Oil Prod,/''ear (Barkis!
Actual sas Prc:,/vear '.^CF):
Actual or3S5 Revenues i$000):
actual Net Peveruas r.$000i;
Actjal Net Cash Flo* i*000>:
Actual :a.ies Paid ',$000':
Capitalized Cost; Not Expended:
Surplus Depreciation:
5arrel= Oil per Day:
Days :*' Preductier Per 'ear:
Barrels Oil "er 'ear:
Price Per Parrel:
$T 01 $
T _ 1 *. 1 •?
$12
$53
?7
$2
$2
$0
0,00
-279.21 -33
$46
$13
$0
$0
$0
$0
$2"
$29
$0
$0
$28
$10
$2
$17
$17
?
1912
4
$58
$46
$17
$11
$0
$0
Year Year
21
OIL PRODUCTION
1
365
281
3.0!
$38
ili
*4E
$i
$2
$2
$0
0.00
^ ?} I
$38
$18
$0
$0
$0
$0
$21
$2!
$0
$0
$2!
$7
$1
$12
$12
i
1504
3
$48
$36
$12
$8
$0
$0
Tl
365
233
$3,0!
tT"
$5
$*'.'
$5
$1
$1
$0
0.00
-405.76
$32
$13
$0
$0
$0
$0
$14
$14
$0
$0
$14
$5
$1
$8
$9
1243
J
$40
$32
$9
$6
$0
$0
Vear
'
1
3s5
iv4
$3.0!
$26
*?
$33
$4
$1
$1
$0
0.00
-489.07
$27
$18
$0
$0
$0
$0
$9
$9
$0
$0
$9
$3
$1
$5
$5
1
1036
2
$33
$27
$5
$3
$0
$0
•ear
24
0
Tit
. Wkj
161
i3.01
$22
$6
$28
$4
$1
$1
$0
0.00
-589,44
$22
$13
$0
$0
$0
$0
$4
$4
$0
$0
$4
$1
$0
$3
$3
1
360
2
$28
$22
$3
$2
$0
$0
Year
25
o
3o5
133
r. "i<
$15
$5
$23
$3
$1
$1
$0
0.00
-710.38
$18
$18
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
1
714
t
$23
$18
$0
$0
$0
$0
'rear
25
i)
365
111
$Vif
$15
$4
$19
12
$1
$1
$0
0,00
-85s. 08
$:5
$13
$0
$0
$0
$0
'$3;
($3;
$0
$0
i$3)
($1;
($0)
'$2''
<$2'<
o
y
0
$0
$0
$0
$0
$0
$0
Year
-7
._ 1
0
365
"2
I",''1!
$13
$3
$ls
$2
$1
$;
$0
:.00
-1031.a3
$13
$13
$0
$0
$0
!$5i
•$5''
$0
$0
'$5!
1*2'
i*0i
i*3,
'$31
0
0
0
$0
$0
$0
$0
$0
$0
rear
26
,j
365
7t>
{" ;••!
$!0
$3
$13
$2
$0
$0
$0
0. 00
-1243.13 -
$10
*ie
$0
$0
$0
<$7'
1*7)
$0
$0
<$/>
'$3'
! JO '
>$4>
•*4'i
r
0
o
$0
$0
$0
$0
$0
$0
fear
jC
M
3t5
L J
r "" ", |
{-
j;
$!!
$!
$'?
$0
JO
; , i_' !_'
.^' .''.
$"
$15
$0
$0
$0
.$5.
!$9i
$0
$0
• $9l
'$3'
!$:•
$C'
•;
M
i
f
s
$
JO
JO
ear
-•
~_ r
~~
$25.49 $25.4" $25,49 $25.4-
*...•»-
MfC" 5as 5er Day:
!*MCF Cas Per rear:
•••Me :sr *CF;
SAS
$3.01 $3.0! 13.01 $3,01
0 0
0 0
$3.01 $3.C1
-------
ji!
Total Revenues 'JOOO):
Royalty Pa'/Tents-Qii '.JOO1
Royalty Payniepts-Gas 'JO
severance Ta-e;-0:! 'JOO
Severance Taxes-6a£ iJOO
ELf tcr Alaska Severance
ELF nr Aias^.a Severance
Net Revenues 'JOOO):
Operating Cast;;
raliutian LGntrcl Operat
For FV ?c!l. Control:
Sepfeciation J fl»orti:atun:
Operating Earnings 'JOOO);
Earnings Before Inte
E'epietion Allowance:
Surplus Depletion;
Earnings Before Inte
Federal la*:
State Tax;
Earnings Before Inte
Net Cash Fie**;
's-iutcff"
Actual Oil prod.'/ear 'Barrels1;
Actual cas Prcd."'ear irtMCFi:
Actual aross Revenues iJOOOi:
Actual *jet Revenues iJOOO;:
Actual Net Cash Flos ''JOOOi;
Actual Ta''es Paid '.JOOOi:
J7
*2
*9
iC'i): Jl
• it! : JO
i : JO
• : JO
1 Taxes-Gil: 0,00
? Taxes-Sas: -1804.97
*7
Jld
ing Casts; JO
JO
i cm ;
i: '*1D
and GDA: 'JIT
JO
to
and Ta'/es: (til!
t6'
1*6)
0
ar ' e i s ' : 0
HCFi: 0
000): JO
C ; : JO
00 i: JO
: JO
Jo
J2
J"
J!
JO
t:<
JO
\\ , !.f 'j
-21<4.87
Jt
Ji?
JO
JO
•,Ji2i
'J12'
JO
JO
!'Ji2!
($4)
!Jit
($71
it')
0
0
o
JO
JO
JO
JO
J5
Jl
Ji
Ji
JO
JO
JO
0,00
-;-20.!3
J5
J<3
JO
JO
iJ13)
•*13)
JO
JO
*'J13i
i*4-
•tl'l
J8;
US''
0
0
0
JO
JO
JO
JO
J4
Ji
J5
Ji
JO
JO
JO
G.OO
-3157.46
J4
J18
JO
JO
,*H.
'*14)
JO
JO
J14)
!J5)
i*l i
iJ8i
(J3i
0
0
0
JO
JO
JO
JO
J3
Jl
*4
Ji
JO
JO
JO
0.00
-3:04.38
J3
Ji3
10
JO
(J14)
'*14)
JO
JO
iJ14!
t*5)
'*!)
I.J9!
(J9)
0
0
o
JO
JO
JO
JO
$3
Ji
J4
JO
$0
JO
JO
0.00
-4533,75
J3
J18
JO
JO
(J15i
(*15)
JO
JO
'J15!
(J5i
(JD
(J5)
1*9)
0
o
u
JO
JO
JO
JO
J2
Jl
J3
to
to
JO
JO
0,00
-5522.35
J2
J13
JO
JO
(*15)
(J15;
JO
JO
i'J15i
i'J5;
1*1-
i*9'.
iJ'!
.;,
0
0
JO
JO
JO
JO
J2
JO
j;
to
JO
JO
JO
i'.OO
-tc54.24
J2
J18
JO
JO
•*16)
(Jiii
JO
JO
iJiti
iJ5!
' $ i 1
(tst
.*?•
j
j
j
j
J2
JO
J2
J'?
*0
fO
.JO
'.-' . V1.'
-5017. 3o -•;.=
J2
*!9
JO
JO
(Jio'
'*16;
JO
JO
i*16)
'J5J
• *;,'
iJiO'
•JIO-
.;,
'j
)
JM
JO
JO
JO
{ f
t'.
* ~
JO
JO
ft1
JO
'.' i V V
;=.68
ti
tie
$j
JO
'Jit!
•Jlsi
JO
$0
•t!6
•Jo i
•Ji
tli1
1 j i ; '
: p.
I .
*•;
:T
-------
of Het Casn Flows: $721
of Excess Depletion: - $0
of Surplus Depreciation: $0
Py of Expensed Invest Cash Flows:
*y :f Capitalized Costs: I74I5
FV of Lsasehcld Cost: *4
Fv "oil. Cor:. Costs: *0
Fv of Royalties - Oil: $94
FV of Royalties - 5as: $24
FV of Severance Ta>:es - Oil: $23
rV of Severance Taxes - Bas; 16
PV of Operating Costs: $79
F'V ot Incone Taxes; $300
FV o« Total Cospany Costs: I!,171
FV of Total Cotpany Costs - Oil: $?34
PV of Total Cospany Costs - Sas: *238
flaortized Coipany Cost per ^BTu: $3,16
Aaortizsd Conpany Cost ;er bbl: $20.29
Mortized Coapany Cost per MCF: $2.40
l»elihead P"ice on HHBTU basis - Oil $4.39
neiliead P'lce on MHBTU basis - Gas $2.95
:V Equiv, of Oil ?rad.'fab;: 46,028
FV Equiv. of 6as fNMCF): 9?
FV Equiv. of Frod. '; 36S,29t
Met Fresent Value of Projec $^6
!n:ernal Rate of Return: 0.115
CrQDasie SCR: 0.5
Anpualized Fell.Cart.Costs: $0
F!.' at 5cc:a! Costs - Total: $B7T
•VfC'tized Social Cast'MhBTU $2.37
?V "i Social Costs - Oil: $5^6
Aiortirsd Social ost/bdi: $15.11
F'.' cf .Social Costs - 6as: $!77
kHif;rti;ed Social Cost/ICF: $1.78
-------
Pur Date:
rc;ect Type:
Lease Cost:
643 Expense:
Leasehold Cost:
Peal Discount Pate:
Years Between Lease Sale
and Start of Expior,:
Percent Casts Considered IDC's;
Percent Costs Expensed:
Drilling Mud Cost Increment:
Corporate Tax Pate:
State Corporate "ax Rate:
Ccrp Structure (!-«ajcr'Z-indep):
Cost Per Exploratory Well:
Drilling Hud Cost Increient:
Discovery Efficiency;
Successful E.xpl. i»ell:
2?-Apr-37
Region 9 - single oil wei
12
58.302
t4
60,00'i
60.007.
o.oox
347.
6.001
EXPLORATION COSTS
t492
$0
ft 7?
fear
1
Year
0 1
Evpiof, Costs Per Project:
tost cf Successful Efforts:
E;cen,sed Costs:
Expensed Cash Flows;
Capitalized Casn cia«s:
$683
W2
t4E7
1321
ti97
to to
to $0
to to
to to
to to
to
to
to
to
to
F\/ ;f Expensed E-pIoration Cash Flows;
cv :f Capitah:sd Expl. Cash Flows:
*:tal Cap;tali:ed E^pl. Costs;
P'l o* ail Exploratory Costs;
132!
1197
t!97
$:8T
T:tal !n»ra5tructure Cost;
'ear: SetKeei Sta't of Exploration
arc Start of Developaent:
^us:er of Kei!= I'riliedj
f-:«cer «ell5 Dnilea Per Year;
DEVELOPMENT COSTS
$109
0
0
0
to
"'ear
rear
Drilling Cost :er (Jell:
uicoer ; mes ried:
'ctal Drilling Costs for ''53r;
^pnjjl Irf rastr.:tiire lest:
•irri'jal Foil lent Capital Ccsts:
to
to
to
to
to
to
to
tear fear
4
rear ''sar
5 i
$0
to
t'l
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
t'">
5
-------
Tctai Annual Capita: Cost:
S\ Shield:
pensed Cash flow:
Capitalized Cash "law:
FV of All Development Costs:
PV of Expensed Development Crsts:
PV o* Capitalized Deveiopite": Costs:
$109
$22
$43
$44
$0
to
$0
$0
1109
143
$44
to
$0
$0
$0
$0
to
$0
to
$0
to
to
JO
to
to
to
to
to
to
$0
JO
to
to
$0
$0
$0
$0
$0
FINANCIAL FATES
Percent Water Cat in Q&G to Start:
Dil/Sas Prod. Decline 'ate/Year il'i
Cost Escalator ('/.I:
Royalty Rate (II i
Federal Ta« Rate iX):
State Tax Rate fX):
Average Depreciation Lite iyears':
Deprec, rate !eac^ year):
State Severance Tax Rats-Oii:
'If Alaska enter 5")
State Severance Ta1; Rate-Gas:
'If Alaska enter '9j
837.
OX
00?
34?.
6?
7
14.29X
4.00X
4.00X
24.49r,
' 40''
I T ; /.
PRODUCTION COSTS
•ears Between Start of Develcpnent
ard Start of '^auction i 5':
'"usoer of »ears at Pea1- Prod;
Oil Fea^ "--od. Rate'd'ell 'bo1:
3as Pea1 Prod, Rate'^eli :MHCF'D):
N'Laber of Pr:ducirg Sells:
Nupcer ct tjelis cut in Service/fear
:'ic; c* Gii ;er Barrel;
Fries :f 3as Per *CF:
Total Cperating tests 'tOOOc
ccl! Ccnt Qper Costs itOOO):
Dav= cf F'od'jcticr Per ''ear:
i
TT
•JL
0.069
i
i
i
t25.49
t3.01
tlB
to
365
Year
Year
tear
'rear
-------
KPCF of Gas per Day:
iilCF of Sas :er f'ear:
ice/HCF :f 5as:
Annual 0:1 Fevenues '$000):
Annual Sas Revenues ($000':
Total ^evenues '$COO;:
Royalty Payments-Oil i$000);
Royalty Fayser.ts-Sas f$000'':
Severance Taxes-Oil '.$000):
Severance Taxes-Sas ($000!:
Zi* for Alasca Severance Ti"es-0ii
ELF for Alaska Severance Ta?e=-Sas
Net Revenues '$000';
Total Cperating Costs ($000i:
Expensed Roil.Cent.Cap.Costs '$000
Poll.Con.Operating Costs '$000):
Capitahred Costs ifOOO):
Deoreciatirn * Amortization i$000i
Operating Earnings '$000):
Earnings Before Interest and ODA:
Depletion Allowance:
Surplus Depletion;
Earnings Before Interest and Ta
-------
Price Fsr HCF;
$3.01 $3.01 13.01
$3.01 $3.)i $7.0;
Wf'i Revenues '$000..;
5as Revenues 'fOOO'!;
Tctai Fe'-e^ues '$000':
^cyalt/ :a.""e".ts-C'i; 'i<''00':
Fcyalty F a^erts-tas '$(00r;
;gv3ran:e Ta"es-0ii '$000'' :
5everar:e Ta;:es-3as '$000i:
ELF for Alaska Severance Ta-es-Oil;
E^F icr Alaska Severance Taxes-Sas: -2'
Net Revenues '$000):
Operating Costs:
Expensed Poll, Cent. Cap, Costs '$000!
Poiiutici Control Operating Costs:
ror :'v Poll. ;c"tral:
Ciepreciaticn 4 Amortization;
Ope-ating Earnings '$000);
Earnings Before Interest ana QDA:
Depletion Allowance:
Surplus Depletion:
Earnings Befc'e Interest and Ta'-es:
rederal Ta:::
State Ta'<:
•arnings Setore Jr-te-est Afte" T£v:
'st Cash Flow;
SHatoff-
Actual C1:! Crod.''i'ear ''Barrels;:
^C L Ua* 'jdz ^rCfltSdT > i M Lr ' I
Actual 5'oss "evenaes i$000i;
Actual Net Revenues ($000i;
Actual Net Casn Flow i$000i;
Actual Ta'.es "aid ($000i;
Capitalized tests 'Jet E"p2,n2=d:
Tear
$46
$12
$58
*7
$2
$2
* '.'
O.iO
'9,21
$46
$18
10
$0
$0
$0
$29
$29
$6
$0
$26
$10
$2
$17
$17
i
1312
4
$58
$46
$17
$11
$0
$0
21
135
no
$45
It
$2
$2
$0
0,00
-336.6!
$38
$18
$0
$0
$0
$0
$21
$21
$5
$0
$21
$7
$1
$12
$12
i
1504
"^
$43
$36
112
15
$0
$0
Year
J J
$72
$S
$40
$:
$1
± 1
$-:
0,00
-*05,7a
$32
$13
$0
$0
$0
$0
$14
$14
$4
$0
$14
$5
$1
$3
$5
1
i
1248
1
140
$32
$;
$0
$0
$0
•ea-
i_ -
$26
$7
$33
$4
$1
$1
$0
0,00
-489.07
$27
$18
$0
$0
$0
$0
$9
$9
$4
$0
$9
$3
$1
$5
$5
1
1036
J
$33
$27
$5
$3
$0
$0
•ear
24
$22
$u
$28
$4
$1
$1
$0
0,00
-589,44
$22
$13
$0
$0
$0
$0
$4
$4
$3
$0
$4
$1
$0
$3
$3
l
860
2
$28
$22
$3
$2
$0
$0
fear
4-W
$15
$5
$23
$3
$1
$1
$0
0.00
-710.76
$18
$13
$0
$0
$0
$0
$0
$0
$2
$0
$0
$0
$0
$0
$0
1
714
-\
$23
$13
$0
$0
$0
$0
fear
26
*i3
$4
$19
$:
$1
$1
$0
0.00
-856.03
115
$13
$0
$0
$0
$0
($3)
'$3*
$2
$0
',$3'
<$1!
i$0)
i$2)
>$2)
0
0
0
$0
$0
$0
$0
$0
$0
27
*13
$3
$16
*2
$1
t!
$0
0 , 0 0
-1031. &3
$17
$13
10
$0
$0
($5)
;$5l
$2
10
'$51
i$2/
1*0)
($3i
($3)
o
! 1
0
$0
$0
$0
$0
$0
$0
''ear
25
$10
$3
$13
$2
$0
*0
$0
0,00 :
-1243.13 -145-
$10
$13
$0
$0
$0
'$7''
!$7'
$1
$0
i*7'
!$3'>
,$.;,-,
•|4.
,J4;
.-,
o
$•'•
$0
$0
$0
J,
$r.
•fear 'E£r
2:
f-
i 4.
*'
$1
$0
$0
$0
.' 1 . '.
:.:;5
1 9
$18
$0
$0
$0
<$9i
i$9:
$1
JO
.J3,
($3
1 $1 '
It' '
*:•
£'_
$0
10
$•
t ',
t,".
OIL PRODUCTION
rarre
Days
Barre
P-ice
,M.;r
»nr;
Is Oil Per Dav;
of Production Per 'ear;
Is Oil :er fear;
Per &arre; :
'255 D5r C'a'/;
5aE :er 'gar:
1
3t>5 3o5
281 233
$25.43 $25.49
U '.•'
i i
i 0
3i: 365
P4 161
$2C,45 $2^,4'
'.' u
'' i'
0
765
ITT
$25.49
'_)
o
'} '.! y
7a5 365 7t5 7::
111 92 76 63
$25.49 $25.4- $25.45 125.4?
y '.i y
$3,0! $3.0! $7,01 $7,0; $7,01 $3.01 $3.01 $3,'.'!
-------
Oil Revenues itOC'O):
ms Revenues i*000):
ictai Revenues '$000;:
Foyaltv Fay-ients-Qil ($000):
Fcyalty Fayaents-Gas '$000':
Ee'-'erance :a-es-ui '.$'-' .".<,':
Severance Taxe;-5as '1000;:
ELF for Alaska Severance Taxes-Oil:
ELF fcr Alaska Severance Taxes-5as:
Net Re'-enues ($000):
Operating Cost;:
Foiiuticn Control Operating Costs:
rcr PV Poll. Control:
Depreciation & Aicrti:aticn:
Operating Earnings '$000);
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depletion:
Earnings Before Interest ard Taxes:
federal Tax:
State Tax;
Earnings Before Interest fitter "a?.:
Net CasP clo»:
Cutoff
Actual Cii Frad,/Year (Barrels1:
Actual 3as Proa, rear <,*HIT'':
Actual Sross Revenues i*000i:
Actual N'et Revenue; i$000i:
Actual *Jet lisn Flrtt itOOO'1:
Actual Taxes Paid itOOOi:
$7
$2
$9
$1
$0
to
to
0,00
-i 804, 97
$7
$18
$0
to
($11)
($11''
$1
to
!$!!;
'$4)
itl;
'to)
'.to;
0
o
[I
$0
$0
to
to
$6
$2
r
$1
$0
JO
$0
0,00
-2174.87
$s
$15
$0
$0
.$12)
'$12''
$1
$0
'$12i
($4'
'$D
!$7)
'.$7)
0
j
•'<
$0
$0
$0
10
$5
$1
Ji
$1
$0
$0
ti,
0,00
-2620.53
*5
$13
$0
$0
'$13
;$i3;
$1
$0
!$13
'$4
Hi'
'$5,
1*8
,•;
i'
Ji
ji
$i
$0
$4
$!
$!
$1
10
$0
$0
0,00
-3157.4s
$4
tie
$0
$0
(114)
'tl4i
$1
$0
'$14)
i$5!
•$11
;$8!
1*8)
A
0
0
$0
$0
$0
$0
$3
$1
$4
a
to
$0
$0
0.00
-3504,38
$3
$18
$0
$0
•$14;
($14!
*0
$0
i*14)
($5;
i$l;
i$9>
i*9)
0
0
0
$0
to
to
to
$3
$1
$4
$0
$0
JO
$0
0.00
-4583.79
*:
$18
$0
$0
($15)
($15)
$0
$0
<$15i
(*5i
'*!)
i*9i
'*9i
A
0
0
$0
$0
$0
$0
*2
$1
$3
$0
$0
$0
to
0,00
-5522,35 -se
*2
$18
$0
to
($15)
!$15i
$0
to
($15)
t$5;
i*l)
,$9'
•*9)
0
0
0
to
$0
to
$0
$2
$0
$2
$0
$0
$0
$0
0.00
54.24
$2
*15
$0
$0
.$16!
'tis.
$0
JO
r,Iib)
($5i
!$ii
($9i
i$9.
Ti
0
o
$0
$0
$0
J'"i
3 4_
Jl)
J2
*'
$i
5'.
*'
'.' i.1'
-E'il7.36
$:
$18
JO
$0
'$ia'
'.$:6;
$0
to
i*16)
i $5;
(*!'
'$10'
'$10'
.;.
'.
$0
JO
$0
JO
$i
to
J2
to
$0
$0
JO
0.00
-^^.sd
J!
tic
t •,
JO
.Jib)
'.fib1
JO
JO
i$b'
'It'
•.$:''
-tn.
J-:'
;'.
•:<
$;•
-V
-------
v cf E-:ess Deplet:c": " $-0
f 5crol'J5 lej'scianon: JO
Fv c' Expenses' Ir.est Cas", Flows: ?364
:,' of Cap-:t2l::e:i Costs; 1241
Py ct >fo'.'alt:e£ - 0:i : 194
PV c; ^'G/aitis5 - 5as; 12*
py :f Severance Taxes - 0:1: *I3
:>; Qi ;gvarjnc° T3> 35 - 5a5! *6
C'V at Operating C:sts: $?5
:'V :i- hrone T3'
-------
Run Date:
"reject Type:
.ease Ccst:
-------
Total Annual Capital CDS::
Ta« Shield:
nsed Casl Flon:
apitalized lash Fl:«:
FV c* AH Development Costs:
fV of E:'pensed Development Costs:
PV of Capitalized Development Costs:
IS:
123
$48
to
to
$0
to
$,'•
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
10
to
to
10
to
to
to
tl.'
$'"
to
to
t83
$23
t48
rINANC!Al 5'ATES
Percent Kater Cut in C&6 to Start:
Oil/Sas Prod, Decline Rate/Year d
Cost Escalator '7J:
Royalty c.ate (V:
Fsderal Ta« Rate ('{!:
State Tax Fate d):
Average Depreciation Life (years):
Deprec. rate (each year):
State Severance Tax Rate-Oil:
(If AlasKa enter 9?)
State Severance Tax Fate-Gas:
'If Alaska enter "91
707.
OS
18,752
347.
"?
7
14.292
O.HX
0.14".
24.4s": 17.497. 12.492 8.932
S.922 8.932
4.4H
PRODUCTION COSTS
'ears Between Start of Developsent
and Start of Froduction (.5): 1
Nusber of rears at ''eak Frod: I
Oil Pea* Prod. Pate'Hell (bbi: 35
Gas Feat p-od, Rate/Hell i'MHCF/D): 0
fc'j!Bber of Producing klells: 1
Nuisber of Hells Put in Service/Year 1
'rice of Oil Per Barrel: $22.14
Price of Gas Per rtCF: $3.36
Total Operating Costs ($0001: $13
Foil Cant Oper Costs ($000): $0
Da*= cf ^reduction Per fear: 365
Year
Year
Vear
rear
Year
Year
Year rear
o
OIL PRODUCTION
F'roaucng Hells in Service.:
Barrels c+" Oil Per Day:
Davi cf pr-:d'jct:cfi Der Year:
Barrels of ]il :er Year:
Price/Barrel of Oil:
12775
365
8943
17
&2&0
0
12
65
62
0
a
365
3067
6
365
2147
4
365
1503
3
365
1052
$22.14 $22.14 $22.14 $22.14 $22.14 $22.14 $22.14 $22.14 t22 ;4
5A5 P
-------
»HCF of Sas Per Day;
,1hCF of Gas Per ?ear:
:e'HCF of Sas;
13.36 $3.36
$3.36 $3.36 $3.3t
Annual Oil revenues ($000):
Annual Sas 'everues ilOOO':
Tc
$1
$0
i$2i
i$l)
!$0l
($1;
$0
1
1052
0
$23
$19
$c
!$!'
*0
$0
Year
15
0
365
70
$22.14
$16
JO
$16
$3
$0
$0
$0
EF5
0,00
$13
$13
$0
$0
$0
$0
.$0.
l$0»
$1
$0
•$!•
• $0 '
• J-.
'$:
i'.l
JU
Ij
$13
$13
$0
• to,
•M
$,:
'ear
1'
..
3*5
1 1
$22.14
$11
$0
$11
$2
$0
$0
10
E?K
'.' i ' '.'
P
$13
M
fj
$0
$0
-,$<•
i$4;
$;
t;
• ?:
, ?-
t '
j -
'--
«;
J i
$i'
10
JO
{,;
-'-
•ear
--
-^ r
, r
r " ~ i ,1
-------
rlcs per
$3.36 $3.3t
*3.3t> $3.36
13,36 $3.36 $3.36 $3.3o
|1 Revenues ($000;;
~"bas Revenues '$000^:
Totai Revenues '$000):
Royalty :'a,aents-0i! i*000):
Fsyalty Pavsents-Sas '$000':
Severance Taxes-0il '$000):
Severance Taxes-Gas '*GOO):
ELF for Alaska Severance Taxes-Oil:
ELF fcr Alaska Severance Taxes-Gas:
Met Revenues($000):
Operating Costs:
Expensed Poll,Cont.Cap,Costs i*000)
Pollution Control Operating Costs:
For PV coll. Control:
Depreciation i Amortization:
Operating Earnings !*000):
Earnings Before Interest anc GDA:
Depletion Allowaice:
Surplus Depletion;
Earnings Before Interest and Taxes:
Federal Tax:
State Tax:
arnings Before Interest After Tax:
;et Cash
Shutoff
Actual Oil Prod,/Year (Barrels):
Actual Sas Prod./Year '-MICFi:
Actual Brass Reverues [$000):
Actual Net Revenues ($000):
Actual Yet Cash Flow i$000):
Actual Taxes Paid '.$0001:
Capitahred Costs Net
Surplus Depreciation:
Upended:
$8
JO
$3
$1
$0
$0
$0
0,00
0,00
$6
$13
JO
$0
$0
$0
1*7)
($7)
$0
$0
)
i$7<
•*:•
o
0
$0
$0
$0
$0
$'.'
$0
Year
1°
• n
i':
$0
$0
$0
10
$0
0 . 00
0.00
$0
$13
$0
$')
$0
i*13i
i$13i
$0
$0
i$13!
L$4)
•*li
'$9'
'*='
r.
$
r
$
i
i
j'.1
'83'
-'-
Barrels Oil Per Day:
Day; of F'cCuction 3er rear:
Barrels Oil 'er 'ear:
Pr::e fer Farrei:
0 0 0 0 0
365 3c5 3t5 3a5 365
10 7532
$22.14 $22.14 $22,14 $22.14 $22.14
y
365
0
365
1
$22.14 $22.14 $22.14 $22.14 $22..•»
5AS PRODUCTION
CF 5as Der Day:
CF Gas Per ''ear:
i;s Per 1CF:
0 0 '? 0 0
0 0 '} 0 0
$3.3o $3.3D $3.36 $3.36 $3.36
-------
es itOOOi;
'tOOO; :
Poverties itOOO):
Royalty Pay«ents-uil (tOOOi:
Fayalty :avser:s-Sas '$000;:
Seve^aice Ta'ies-Oil 'tOOOi:
Severance Ta^es-oas (1000):
ELF tor Alaska Severance Taxes-Oil:
ELF for Alaska aeveranre Taxes-Sas:
Net Avenues (1000):
Operating Costs:
Foliation Control Operating Costs:
For PV Poll, Control:
Depreciation i niorti ration:
Operating Earnings ($000):
Earnings Before Interest and QOH:
Depletion Allowance:
Surplus Depletion;
Earnirgs Severe Interest and Taxes:
Federal Ta*:
State 'as;
Earnings Before Interest After Tax:
Net Cash "leu:
hutoff1
Actual Oil ?rofl,.'fear
Actual 5as Prod. vear
(Barrels1:
!1fCFi:
Actual GrcES Peve-uss ftOOO':
Actual Net Reveres iiOOO1:
Actual Net Casn How (fOOO):
Actual T£"8S Paid 'I0001 :
to
tfi
tO
$0
to
to
to
0,00
0,00
$0
$13
to
to
t*7>
M
0
0
i()
to
to
to
to
10
to
to
to
to
to
0.00
0.00
to
t!3
to
to
(tl3)
'til!
to
to
>tl3)
'*51
!tl!
lt8i
't71
0
0
M
to
to
to
to
to
to
to
to
to
to
to
0,00
0.00
to
ti:
to
to
itl3/
to
to
'tl3i
(15)
'ID
(tBi
i$8i
0
' i
A
to
to
to
to
to
to
to
to
to
to
to
0.00
0.00
to
113
to
to
'113;
it!3)
to
to
($13;
(t5)
(in
(t9)
;te/
0
o
o
to
to
to
to
to
to
to
to
to
to
to
0.00
0.00
to
tl3
to
to
it!3)
(113)
to
to
tt!3)
• *5i
ill)
(18)
(18)
0
0
0
to
to
to
to
JO
JO
to
to
to
to
to
0,00
0,00
to
t!3
to
to
(113)
( 1 1 3 1
to
to
il!3)
(15;
(Hi
1*8)
US)
fi
0
'!
*0
to
to
to
to
to
to
to
to
to
to
0.00
0.00
to
tl3
to
to
it!3i
(til!
to
to
tl
K
t!
t'
K
0.00
0,00
to
113
to
to
't;3;
(113;
to
to
(113;
•*5)
(tl)
(18;
•tl3)
to
to
(t!3i
it5)
ill;
• it;
'$=
'
£ •
I'J
t'"i
iO
-------
FY at Net Cash PICKS: $352
_fv cf Excess Depletion: ' $0
jf Surplus Depreciation: $0
of E: persed Invest Cash Fiotts: $79
FV :-f Capitalized Costs: $1*1
PV 3' Leasehold Cost: $53
CV =3ll. Cent. Costs: $0
F'V of Realties - Oil: $68
PV of Royalties - Sas; $0
PV :f Severance Taxes -Oil: $1
PV of Severance Taxes - Sas; $0
PV of Operating Casts: $42
PV of Incoie Taxes: $156
PV at Total Ccapany Costs: $53?
FV of Total Ccspany Costs - Oil: $540
PV of Total Coflpany Costs - 5as: $0
Piortized Coepany Cost per MHBTU: $2.82
Asortized Coapany Cost ;er bbl: $16,38
Aiortued Cospany Cast per *CF; ERR
Wellhead Price on WB7U basis - Oil $3.32
Wellhead Price on HMBTU basis - Bas $3.29
PV Equiv. of Gil "rod.inbi; 3;,
-------
un ata;
Project T7pe:
ease Lost:
346 Expense:
Leasehold Cast:
Sea: Discount Rate:
Years Between, Lease Sale
and Start of Expior.:
ferret Costs Considered ISC s:
Percent Costs Expensed:
Prilling Hua Cost Incresent;
Corporate Tax Rate:
State Corporate Tax Rate:
Corp Structure (l-iajor/2-indepi:
Cost Per Exploratory Well:
Drilling Mud Cost Incre«ent:
Discovery Efficiency:
Successful E
-------
T2tai Annual Capital Ccst;
Tav Shier::
$33
$17
$33
I"
$0
$:•
10
$0
$o
*0
$0
$0
1C
fO
$0
SO
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
JO
},',
$1.'
$0
P'J of Ali 2-eieIcpser.t Costs:
P1,1 2* E"pepsea Develcpnert C;sts;
c'v c* Capitalized Deveiopinert C:sts:
$33
$33
Percent i^ater Cut in Gifa to Start; 2?.
2:i/Sas Prod. Decline ^ate/rear (V 70X
Ccst Escalator '': 341-,
State 'a:< Rate <'/.'>: 9?
Average Depreciation Life (years): 7
Deprec. rate (each year): 14,29?
'State Severance Tax Rate-Oil: 0,14?
il+ Alaska enter v9i
State Severance Tax Rate-Gas: G.l*X
'.If Alaska enter 99)
24,497.
. 49'4 12.497,
e.93'/. 4.467.
PRODUCTION [OS'S
years Between Start 3* Developient
anfi Start o» "nducticr i :<;
Nusner of ''ears at ceak froc:
3:1 ^231 Prod. Sate'Keliidfii:
Sas Pea* :T3d. Rate/leil iMMCF/Di:
Number of producing Keils:
*-uaber of tieiis Put in Service/fear
:rice of Qi! Per Barrel:
c'ic? of Sas Per MCP:
Total Operating Costs ($000):
Fci! Cont Oper Costs ($000):
Davs :f P'ocucticn Per rear:
0
1
1
$22.14
$13
fO
365
Year Year
1
*ear -sar Year Year
3 4 5
rear fear
7
Tear
OIL PRODUCTION
P"duc;ng Keiis n Serv;;g;
BarrelH of Oil rs- Day:
Days at Production Per rear:
rarreis of Oil Per rear:
c'ice/Barre! of Gii:
1
0
25
u
12
3o5
365 3a5 355 3a5
12775 3943 b2sO 4331 30b"
$22.14 122.14 $22,14 $22.14 $22,14
6432
365 3i5 3a5 3t5
2147 1503 1052 "o
$22.14 $22.14 $22.14 $22.14
-------
Wlr of oas Far Say:
fVCF. of cas Per year;
fcr:r°'«iT 3f 5as:
W
Arnuai Chi Revenues '$000'':
^niuai 3as Revenues sJOOOj;
T;tal Fpi-siues 'JOOO'1:
Fa/alty Cay*ents-Qil '$000 :
C3yalt- Payjiefts-eas ($000):
Severance Taues-0ii '$000;:
5everance "a"es-i:as ilOOO):
EuF for Alaska Seve^ce 7a*es-0il:
EL.F- *2r Alaska 5everan.ce Ta,ves-5as;
Tatal Operating Tests ($000);
E;:cens5d Foil, Cont. tap. Costs '$000,'
Foil. Con. Operating Ccsts ($000':
Capitalized Costs i$000.':
Depreciation i Aiortization '$000! :
Cipera:ing Earnings '$000);
Earnings Before Interest and ODA:
Depleticn Ailci*ancs:
Surplus Depletion:
Earnings Before Interest and 'a^es:
.csceral Tax:
frtate lay;
E2rni"ics 5efcre Iitersst A*'te' Ta1^:
Sst ^sn :i™;
~! n -j f r * f ~
Actual 0;i Drad,/'ear (Barrels):
Actual Gas Pr;d.''ear *HCF':
Actual Gross Revenues dOOO):
Actual Net Revenues ;$OOC":
Actual ^et Casr Flow '$000;;
Actual *a"8S Faia '$000' :
Capitalized Easts Not Expended:
E'-pius E'ep-eciatirp:
Year
OIL
£r'ei: C'll Fer Dav;
ays :; Deduction per 'ear;
o^rpic 0;^ ^of ^sar;
"•'ice Per 9ar'el ; $
~H^
0
0
$3. 3s
J283
$0
t~ w^
J-- -
$53
$(
JO
JO
ERR
M '••(•)
$229
$13
$0
$0
$97
$14
$2h
$202
$28
$0
$166
$t3
$r
$106
$135
i
12775
0
$233
$229
$135
$61
$0
$0
11
"SDDJC
<
7o5
3ai
22.14
-'•'JL'UC.
o
( <
$3.7;
$1-8
$0
$153
$37
$0
$0
JO
ERR
0.00
llcl
$17
$0
$:•
$0
$24
$147
$123
$20
JO
$112
$38
$11
$64
J98
1
5943
0
$195
$161
$95
$49
$0
JO
rear
1
T!ON
365
-<;T
$22.14
;;CN
•j
$7.73
$179
$0
$17?
J2s
$0
JO
f '"'
EF9
0 , 00
it t •
f!3
$0
$0
$0
$17
$59
$62
$H
? '.'
$74
f25
$7
**2
Is1
,
s2tO
Jl:c
$112
$t7
$72
f.
J
"ea-
13
«',
~ L S
I77
$22.14
0
J3.7S
f"
$0
$97
$15
$0
$0
$0
ERR
r, ,-,,•,
$79
$13
$0
JO
JO
$12
$65
$53
$10
$0
$48
$!s
$4
$27
$45
1
4332
o
$97
$79
$45
121
$0
$0
•ear
14
;}
3s5
124
122.14
'i
.,•
13.3s
$ta
$0
$td
113
$0
$0
10
EFR
0 . 00
$55
$13
$0
$0
to
$9
$42
$33
$7
$0
$29
$10
$7
$17
$29
1
1
30o7
0
$68
$55
$29
$13
$0
JO
-ear rE
15
u
765
57
$22.14
0
j!
$3. 3s
$48
JO
$45
$9
$0
JO
$0
E^R
1 ! ' ' 1 !
$79
$13
$0
$0
$0
$?
125
$16
$5
$0
$14
$5
$1
$5
$19
1
2147
0
$48
$39
$19
$5
$0
JO
ar
It
0
365
61
$22.14
V
$3. 3s
$37
$0
J37
$4
$0
JO
JO
ERR
,-, .-(-,
$2"
$13
$0
$0
$0
$9
$14
$5
$3
$0
$3
$1
$0
$2
$12
1503
o
$33
$27
$12
$1
jj
*•:
Vear
i?
ij
3o5
42
$22.14
j.
0
$3.36 13. 3i
123 $ls
$0 JO
$23 fls
j4 i:
JO $0
$0 . !!.'
$0 f1';
EFF E5R
|'l :'!('. •'• .',1,
$19 j;:
$13 J13
$0 $0
$0 $0
$0 JO
$4 $0
$S 'I')'
1 1 ( i 0 ;
$2 $2
$0 JO
i$0' 'Jl1
dO' •$'."
\ $'"' i -'"' '
'JO' '$1
$6
1 '
1052 "s
0 0
$23 ila
f i v 5 " "*
$t JO
no. $v
JO JO
$0 JO
'ear
-------
*"'?" i "c ^ar **Lf" :
mil Pe-'eruss 'tOOO1:
'as :5';enues 4000';
~:r,ii Feveiues tjOO;:
Scyaltv •'avue^ts-jil iOOO';
f^vaiN Fawr.s-Sis 'tOOO1:
Eeveraice Ts'-es-J:i 'tOOi";
Severance "ares-Gas ! 4-000):
EL" for Alaska 5eve-ai:e Ta?es-0ii
E_F fcr Alasi-'s Severance Ta:-es-5as
Net Hgvgniies'tC'OO):
7'Dera::ng Casts:
E1 peised "cil.[Qii.7ap = L3sts 'tOOO
Fclj^ticn Lontrol Operating tests;
PCT :v Foil. Concrcl :
E'3^rec:at::n 4 Agorti:at:on:
-C?r£tirg Earnings itOOO);
Earnnjs Before lnter=st anc GDA:
Depletion V;i;,Jd"e:
Surplus Depletion:
Earnings Before Interest and 'axes
Federal Ta*:
State la-:
.Ea^ir.gs Se^ore Interest After Tas
rvet Cain "low:
Shutoff"
Actual Oil P"d. "ear 'Barr2ls;;
Actual Ga= FrQc,"ear (?!hCF):
-ct'jal Sross Avenue? i*000i:
A:tuai Net Rever.es 'tOOOi;
V' !?'• ypr r3:n f'cw itPOiVi-
4::'jai Ta' es Pi:: 't(00; :
C3?:tali:2d ::st; Net E :e"tieo:
E-'0i,E D2?re::a:!:r:
t'.7a i
*8
to
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ti
to
to
to
; 0.00
: 0,00
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to
to
to
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: i*7'
i*2'
;*!'
: '*4!
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to
JO
to
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*0
Year Year
21
OIL FFODUCTI'jN
' *' . , ~
15
$0
tc
ti
to
40
tO
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0.00
t:
ti:
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ti
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":J'^::ic" :er "ear;
vis*,"": ~ic z.p»- r.:,,,
MM.-C- ,;3C :pr vp,r;
-------
es '$000;:
es !*000':
TZt3i F2'/e"USE !$0!"0/!
ts-Gii ($000):
as '$000':
i>'es-u:l i$000c:
Severance Taxes-Sas !$000i:
ELF far Alaska Severance Taxes-Oil:
ELF tor Alaska Severance T=:-es-Eas:
Met Revenues i $000':
upe-at:-; .asts:
folldticn Lontrcl [Derating Costs:
Per PV Pali. Central:
Depreciation i diort::aticn;
D:3riti"5 Earnings i*000>:
Earnirgs refo'e Inter3St ans ODA:
Depleticn iilic<*ar;ce:
Surplus Depietisn:
Earnirgs Se*crs Interest and Taxes;
'efieral Tax:
State Ta-;
E3rnir,5 Be-'oro intgres: ^tter Ta: :
Net Ci=f ric»:
$0
$0
$}
$0
$0
$
$
0.0
0,00
$0
$13
$0
$0
•$13;
'$13!
$0
$0
i*!3.'
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til'
<$?'
'$7'
$0
$0
$0
$0
$0
$0
$0
0.00
'"' i"' '"'
$0
$13
$0
$0
-*!3.
'$13;
$'!
$0
i*13)
i$5i
;$:'•
'$61
'.$"•
•0
JO
$0
$0
$'"'
$0
$0
0. 00
0,00
$0
$13
$0
$0
'$13'
$13;
$0
$0
,$13-'
'$5i
i$l!
.$B'
'$5;
$0
*0
$0
$0
$0
$0
$0
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$0
$13
$0
$0
•$13)
i$13'
$0
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'$!•
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$0
$0
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$0
$0
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$0
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$'.'
$0
1*13!
',$13'.
$0
$0
'$13'
i*5!
'$!'
($6-
i*S)
$0
$0
$0
$0
$0
$0
$0
0 . 00
0.00
$0
$13
$0
$0
•$13)
'$13)
$0
$0
, x 1 •",
• ^ i . (
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'$U
i$Pi
'$81
$0
$0
$0
$0
$0
$0
$0
0.00
0,00
$0
H3
10
$0
•$!3.'
($13'
$0
$0
,$13:
'.$5;
'$!'
•$5'
i$s:
$0 J fO
$0 $0 s:
$0 $0 • JO
*0 *. ••.
$0 $0 i;
$0 fO $•'.
$0 $0 $0
0, '.'V '.'< 'A' ' ' . !"''
0,00 0,0( '.',0?
$0 $0 !•:
$13 $:3 ^13
$0 i; £•
$0 fv •:
•$::i .Ji3. $r
($13 ',$13' -f;3
$0 f-? iv
$•: $: -.-:
$13' -$!3' J13
•45' -i3' ^.
Mi .?!• $;
•*E' '*E' '-*
•IE' 'f: :-
&c:-al ]as F-cd., -ear 'l""CF':
Actual S'3;s Peve"Les '$000':
'-'Ctua. Net ^ eri.es ;$C"!0 :
•Actual Net 3asn ^io^ 'JOOO1;
"::ual "a es ?ai: '^000' ;
0
ij
$0
$0
JO
$0
'.'
'J
$0
-rO
t'.
$0
I
$
J
1
.'
i 0
$0
$0
$0
$0
o
o
$0
$?,
$0
$0
•
0
$0
$0
$0
$0
t
$0
$'•
JO
$0
r
1
i
$
r
i.
t:'l
$(
-------
of ('et Casn Flews: *33S
'.' 2* Excess Depletion: ' *0
:f 5L!rc:i!;s Desreciatitm: *0
cv a* E pensec Invest Casn Flows: $108
Fv :f Capitalized Casts: IP7
Fv o» ..easencla C:st; $53
Fv "oil. Cert, Costs: JO
:V of Royalties - Oil: $68
FV cf Royalties - 3as: 10
F"/ c» 5everance Taxes -Oil: $1
^ of Severance Taxes - 5as; $0
PV of Operating Costs: $42
*'V of Incase Ta^es: $170
P'J at Tctal Caipany Costs; 1539
?
-------
Date:
prc;e:t Ty?s.
_sase 'lest:
54t E'. per1 ss;
leaser-aid >I:st:
=eai Discount c'ate:
•ears Between Lease Sale
a"d ?tart 3t" E^pior, :
Percent 3:st= Considered IDC's:
r" -'
in 11 - 3i".gie ::!
Jlil
IZ.sOl
J;51
Driiiip; lua 'lost Iicreient:
2orp?rate Tax Pace:
State Corporate Ta- Sate:
i:rr S:-u::urg ':-3iajon2-indepi:
Cost Fer E*;piorat:ry «ieii;
['riiiing Mud 'lost Increaent:
Discrvery E-'hciency:
Eu:ces=+'ui Ejpl. aiell:
o.oox
;n
v.40i
i
EXPLORATION COSTS
^3,2.?7
10
rear
fear vgsr tear
ess+jl tjtorts;
E\per=ed Casts;
E;-p5"sea Cas" "I :ins:
$511
$802
f«o5
at" Capr.ah:ea Espi, [ash C!QNS:
tai "af:tal::2fl E"3l, Ccits:
:; all E piD'ats-y Costs:
$l,42o
f1,860
t:,794
•9ars Jet*eer Eta^t c-f E"ploration
2~j ::jr: ;-' jeveiopaent:
'•.".er ]f wells Drilled:
Yj*"-*- Jjp7'^ Hri'-Qfl hpr yP5pl
DEVELOPMENT COSTS
$45,998
4
rear ''ear -ear rear year rear
s759 10
Drilling Cost ;er neli:
•'riih"q "lud lest Ircreient:
i'-jiwe"' ot ^el.s tTiiled;
JO $0
10
$0
$0
$•:
u
$0
JO
$0
$0
JO
$0
$'•'
JO
J<''
JO
$0
£'•
JO
Jl.1
-------
"eta: flnnuai Capital Cost:
.Ta" tfiei::
"pensed Cash rlo»*:
"Ca;.it=li:ei Casr Fl:n:
P'.: af All Development Costs;
FU 3* E'jpsnsec Deveiopaent Costs:
fV of Capitalized Deveiopser: Costs;
$15,373 $15,377 $::,:
-$2,190 $Z,: = ) $2,1
$4,250 $4,Z50 $4,:
$26,353
$0
$0
$0
$0
$0
$0
$0
$0
$0 $•
$U $i
$0 n
$'.! I'
rIkJ«NClHL SATES
Percent Hater Cut in 0^5 to Start: 2?.
0:i"3as Proa. Decline Rate/Year (!/,/ $H
lost Escalator '"iS: Oi
Rcvaity Kate ('/.): U.30X
'ederai Tax Rate ('/,): 34'i
State Tax Rate '.D: 3'i
Average Depreciation Life iyears,1: "
Deprec. rate teac!1 year'1: 14.2*1
State Severance Ta': Rate-On: 9900.00?
ilf Alaska enter 99i
State Severance Tax Rate-Sas: 5900.00'i
'It Alaska enter 99)
24.4v'/.
12.49? 6.93?
.92? 5.93; 4.4t?
PRODUCTION CC5T5
''ears Between Start o-f Developnsnt
and Start of Production t 5;;
N'juaer of ?ea's at PeaK Frofi:
Oil Psa* Prod. Rate 'Hell !bb!:
at Producing Kells:
of lieils Put in Service/Year
:'ic9 o-f Oil Per Barrel:
'rice of Gas Per HCF:
Total Operating Costs '.$000):
;:ii Cont Oper Costs '$000):
Days ct p'ciuctian Per Year:
4
1
3700
0.686
1
1
$16.98
$0.74
$691
$0
3fe5
Year
"ear
10
fear
"ear
'ear
14
•ear
'ear
Ok PRODUCTION
Froducir,g Wells in Services 1 0
Parcels c-f Gil Per Day: 3700 3219
Days of Deduction Per Year: 365 3o5
Barrels of Oil Per 'ear: 1350500 1174935
i:e''Bar'"ei of Oil; $lo.i'3 $16,^8
^
<}
2476
7i5
B6c;708
$16.^3
0
2120
365
"3693
$16.98
1844 1604
765 365
o73117 585612 505483
$16.98 Hi.93 $13.56
1214
-------
MCF of 6as Per Day:
tfflCF nf Gas Per rear:
j'rice/l*CF o-f Sas:
flnnual Qii Revenues (1000):
Annual Sas Revenues '$000!:
Total Revenues ($000;:
Royalty Payaients-Qii i*000;:
Royalty Paysents-Gas if000;:
Severance "a^es-Dil i$000i:
Severance Taxes-Gas ($000':
ELF for a!asN Severance Taxes-Oil:
ELF for Alaska Severance Taxes-6as:
Net Revenues i.$000);
Total Operating Costs '$OOC'<:
Expensed Poll.Cant.Cap.Costs '$000'
Pell.Csn.Operating Costs <$000!;
Capitalized Costs ($000):
Depreciation \ Asortization ($000);
up er a 11n g Earnings (1000!:
Earnings Before Interest and QDA:
Depletion Allowance:
Surplus Depieti:n:
Earnings Before Interest and Ta*es:
Federal Ta*;
Earnrgs Before irteres*. After Tax:
Actual Oil Prod.. 'Year (Barrels/:
Actual sas Prod. /''ear 'PNCFi:
Actual Gross pevenues '$000):
Actual Net Revenues UOOO'i
Actual Net Casi Pi ON '$000 :
Actual ~ai.es Faid <$0u;;
Capitalized Costs Not Expended:
Days of Produrtioi1 ?e' 'ear:
Barrels Cil >°r '2ar:
price Per Earrei:
Ma'Ir Sas Per Day:
i1Cr 5as FEr rear;
1
- 250
$0.74
$22,931
$1S5
$23,117
$3,279
$26
$2,309
$0
: 1.00
: -3.37
$17,032
$691
• $0
$0
$23,539
: $4,078
$16,311
$12,233
$24
$0
: $12,209
$4,151
$1,14S
: $6,910
$11,012
i
1350500
250
$23,117
$17,002
$11,012
$5,299
$0
$0
Year V
20
J!L PRODUCT
5!g
3e5
3354*56
$io.98
SA5 PRODUCT
0
62
i
218
$0.74
$19,950
$161
$20,112
12,353
$23
$2,444
$0
1.00
-4,03
$14,792
$691
$0
$0
$0
$0,939
$14,101
$7,112
$21
$0
$7,091
$2,411
$667
$4,013
$11,023
1
i
1174935
216
$20,112
$14,792
$11,023
$3,077
$0
$0
ear
21
:ON
600
365
291551
$16.93
I Oil
r.
:*
1
190
$0.74
$17,357
$140
$17,497
$2,452
' $20
$2,126
$0
i . 00
-4.73
$12,5*9
$691
$0
$0
$0
$4, '92
$12,178
$7,136
$18
$(•
$7,168
$2,437
$o74
$4,057
$9,067
1
10221*3
190
$17,4^7
$l2,B:a
$9,0fr7
$3,111
$•"'
$'.'
vsa-
~-l
e9o
Tt3
253'37
$16,96
i"
'<
165
$0.74
$15,100
$122
$15,222
$2,15"
$17
$1,850
$0
1.00
-5.64
$ll,15fc
$e91
$0
$0
$0
$3,5e5
$10,505
$6,940
lie
$0
$6,925
$2,354
$65i
$3,91'
$7,500
;
569308
165
$15,222
$11,196
$7,500
13,005
$0
i''.1
-ear
'3
605
365
220*25
$16.98
.;,
41
o
143
$0.74
$13,137
$106
$13,244
$1,679
$15
$1,609
$0
1.00
-t.;3
$9,740
$691
$0
$0
$0
$2,549
$9,043
16,501
114
$0
$6,487
$2,206
$6 10
$3,672
$6,234
i
773e96
143
$13,244
$9,740
$6,234
$2,515
$0
iO
'ear
24
52-
365
1-2205
$lo.98
,;,
3i
0
125
$0.74
$11,430
$92
$11,522
$1,634
$13
$1,400
$0
1.00
-7.77
$3,474
$691
$0
$0
$0
$2,546
$7,783
$5,238
$12
$0
$5,226
$1,777
$491
$2,958
$5,515
;
673117
125
$11,522
$8,474
15,515
$2,268
$0
$0
-fear
25
458
365
167218
$16.98
o
•",
(i
109
$0.74
$9,944
$80
$10,024
11,422
$11
$1,218
$0
1.00
-9.05
$7,373
$691
$0
$0
$0
$2,549
$6,682
$4,133
$10
$0
$4,123
$1,402
$388
$2,333
$4,592
i
585612
109
$10,024
$7,373
$4,692
$1,789
$0
$0
Vear
2i
395
3o5
145480
$16.95
0
27
y
54
$0.74
$8,651
$70
$6,721
$1,237
$10
$731
$0
0.69
-10.59
$6,743
$691
so
$0
$0
$1,273
$6,052
$4,77?
$9
$0
$4,770
$1,622
$446
$2,700
$3,98,:
i
509483
34
$8,721
$6,743
$3,982
$:,o7o
$0
$0
'rear
27
347
3e5
12o5;7
116.53
„
23
'j
32
$0.74
$7,526
$6i
$7,537
$1,076
$9
$5?7
$0
O.s5
-17, "2
$5,905
$691
$0
$0
$0
$0
$5,215
$5,215
$8
$0
$5,207
$1,"70
$46Q
$2, -47
$2, =5:
1
443250
32
$7,537
$V05
$2, =55
$2,2*0
$0
$0
"ear
:e
-•r-
1*5
;iOi;-i
$i*,=S
,,
;•..
•'.
"!
I'J.74
$o,543
$53
$0,6Ml
$936
$8
$4E1
10
'.' . a ':
- }4, 72
$5,1-6
$691
$0
$0
$0
$0
$4,485
$4,485
$7
$0
$4,47
-------
Fries ;er MCF;
$0.74
10. ""4 $0,74 10.74 *0.74
$0.74 ?0.74
Keveiues '$0';0;;
e'eve^ues i$000'':
Taul feverues '$000;:
Ro-'jlty C2''9ients-0i! '$000!;
i2''er=nce Ta;'es-C'il s*000):
Eeverar-ze Tases-?as '$000!:
EtF for Alaska severance Ta^es-Oil
ELF for Alaska Severance Taxes-Sas
Net Revenues($000):
Operating Costs:
Expensed Poll.Cort.Cap.Costs ilOOO
Pollution Control Operating Costs:
For FV Poll. Control:
Depreciation ?! Amortization:
Operating Earnings i$000):
Earnings Before Interest and ODA:
Depletion Allowance;
Surplus Depletion;
Earnings Before Interest and Taxes
Federal Tax:
State Tax:
ir?5S Before Interest fitter Ta¥
Net Casn Flow:
$5,697 $4,95s $4,312 $3,751 $3,2s4
$46 $40 f3: $30 $26
$5,743 *4,93t $4,347 $3,752 $3,2"0
$2,339 $2,470 $2,145 tl,570 i:,::'
$23 $20 $17 $!5 • $13
$2,862 $2,490 $2,166 $1,385 $l,i4,.
Actual Oil Prod./"'ear 'Barrels,1:
Actual Eas Prod,/vear :
Days o» Production Per Year:
Barrels Oil Per Year:
price Per Barrel:
HC? ':as Der Day:
^'~F 5as Per 'ear;
'i:e Per !
-------
ji: revenues <*'.".'<.',' :
^everuei t*000):
Tctal Revenues 'iOOOi:
3itv Paysents-Qil i$000':
Severance Ta-es-C'il $JOO';
Esverjrrp Taxes-6nE '1000':
E.F -""ar Alasla Seve'a.nce Taxes-Oil:
EL? fcr Alaska Severance Tayes-6as:
Net Avenues i $000 i:
Operating Casts:
Pollution Control Operating Costs:
For PV Roil. Centre!:
yepreciatici i rtscrtiration:
Operating Earnings '$000;;
Earnings Bet"? Interest and ]Dft:
Depieticn Allowance:
£urplus Depletion:
Earnings Before Interest and Taxes:
Federal Tax:
State Ta»:
Earnings Before Interest After Ta":
Net Cash Flow:
Actual Oil prji,-Vear
Actual Eas Prod.'Vear iWHCFi
Actual cross Revenues '$000i
Actual Net Revenues !$000j:
Actual Net Cash rlGw !$000c
Ac:uai Taxes ^a:c $000!;
$1,415
$11
11,42'
t2i'2
*2
10
$0
0.00
-69.86
$1,223
$69!
$0
$0
$532
$532
$1
$0
$530
$180
$50
$300
$302
i
B3345
15
$1,427
$1,223
$302
$230
$1,231
$10
$1,241
$Ft
il
$0
$0
'.'.00
-80.45
$1,064
$69!
$0
$0
$373
$373
$:
$0
$37!
$126
$35
$210
$212
1
i
72510
13
$1,241
$1,064
$212
$161
$1,07!
$=
$1,080
1153
-M
$0
$0
0.00
-92,62
$925
$o9l
$0
$0
$235
$235
$1
$0
$233
$79
$22
$132
$133
1
63084
12
$1,060
$«25
$133
$101
$^32
1 "
|935
$133
ii
$0
$0
0.00
-106. si
^805
$691
$0
$0
$!14
$114
$1
$0
$113
$38
$1!
$64
$65
1
54883
10
*«39
$805
$65
$49
$311
$7
$8F
$116
$1
$0
$0
0.00
-122,6*
$700
$691
$0
$0
$10
$10
$1
$0
$9
$3
$1
$5
$6
1
47748
9
$817
$700
$6
$4
*705
$5
I'll
$101
$1
$0
$0
0.00
-141.17
$609
$691
$0
$0
'$82!
($82!
$1
$1
'$82!
($28!
!$6)
'$47!
($46!
0
0
0
$0
$0
$0
$0
$614
*5
$£19
$88
$1
$0
$0
0.00
-Io2,4x
$530
$691
$0
$0
i*lel)
($161)
$1
$1
'$161)
•'$55!
•$15i
'$91*
($91)
o
0
o
$0
$0
$'?
$0
$534
$4
$538
$76
$1
$0
$0
0.00
-156.34
$4el
$e"l
$0
$0
($230!
(*230i
$1
$1
i $230)
<$75(
'$22i
i$!30i
i$130i
0
h
0
$0
$0
$0
$0
$4fc4
f4
$4s8
$60
$1
$0
$0
0. 00
-214,^1.'
$401
$0*1
JO
$0
l $290.'
'$290,'
$0
$0
$290)
'$v9!
l$27i
i$l64''
<$b4)
I;
0
* ,
*
t •
$'
jiji
r
f4i.^
J:E
•I,",
$0
$0
; ( 'j _
-^47,li
$34'
$';1
$0
10
1 $r^ /
($342)
$0
$0
i$342i
;$il6'
'$32:
;$I26'
$225'
.'.
iO
: :
I M
^
-------
?v :* 'j°t las' "lows:
Fv :f E'-:S:5 Decieticn:
kv :*' Eurpius Depreciation;
r* £'js"=er ir'est 'las" Fiona: 18,753
:• Casitaiiisd Casts: 117,024
10
1:3,5*5
:v c* :cyalties - tas; Ilia
CV cf 5everarc9 'axes - C'ii: 111,333
Ev 3t 5?vsrar':? T3"es - sas: tr:
Lv c* Operating Casts: *7,375
:V :t Inc^e Ta*ss: ill. 4*3
F1' :f "otai Cosipany Costs; I7i,589
:"-J of Total Cc^y- Cast; - 0:1: $7i,408
FV :*' Tctal Cotpary last; - Gas: »481
^acrtired Cospany Ccst ser 1MBTU: 13.75
'i«Qrt::sa Coipany Cost per bbl: 122,30
:Tcrt::ed Coipany Cost p?r ?fLF: JO. 31
Heilfiead Price on 1«BTU Sasis - Oil $2.?3
siellseafl Price OP MftBTd Sasis - Gas 10, 72
:'.- Equiy. of Si: -'sd.'isi: 3,202,628
value of projec
0,084
0.5
$0
F. cf Scc:jl Costs - Tztal: *37,OS3
"-r".::ei Eociai Cast HftBTo tl.5!
cv ;-' S;:iai Costs - Oil: I3o,755
$Tcrt;:ed Serial Losfcol: $11.4?
c'.! :f E:cia: Costs - 5as: *Z37
'-'irc'tizsj Social Ccst'^CF;
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