Document Body - Copper - Alberta Industrial Heartland

Transcription

Comparative Cost Analysis of Alternative Sites
Oil Sands Bitumen / Heavy Oil Upgrader
Nexus of the Alberta Hub
Connecting to the Marketplace
Stantec Consulting Ltd
Project Number 117200230
Sept. 1, 2004
Confidential
ALBERTA INDUSTRIAL HEARTLAND ASSOCIATION
COMPARATIVE COST ANALYSIS
TABLE OF CONTENTS
INTRODUCTION ....................................................................................................................... 3
STUDY OBJECTIVE ................................................................................................................. 4
LOCATIONS ............................................................................................................................. 5
ALBERTA UPGRADING CAPACITY....................................................................................... 6
UPGRADING ECONOMICS ..................................................................................................... 8
TECHNOLOGY SELECTION ................................................................................................. 11
METHODOLOGY .................................................................................................................... 12
BASE PROJECT..................................................................................................................... 14
SIGNIFICANT LOCATION FACTORS ................................................................................... 16
Operational .................................................................................................. 16
Water Treatment/Import ................................................................ 16
Sulphur/Coke Byproduct Transport............................................... 18
Pipeline Transport Costs In........................................................... 18
Pipeline Transport Costs Out ........................................................ 18
O & M Labor Costs........................................................................ 19
Unplanned Shutdown Turnaround Time ....................................... 20
Insurance Premiums ..................................................................... 20
Attrition, Education and Training Cost Impacts............................. 20
Power Distribution Costs............................................................... 21
Transportation of Equipment and Materials .................................. 21
Camp Costs................................................................................... 21
Travel and LOA Costs ................................................................... 22
Capital Costs ............................................................................................... 22
Transportation Equipment and Materials ...................................... 22
Camp Costs................................................................................... 22
1
Travel and LOA Costs ................................................................... 22
Land Costs .................................................................................... 22
Concrete........................................................................................ 23
Insurance Premiums ..................................................................... 23
NON LOCATION FACTORS .................................................................................................. 24
Operational .................................................................................................. 24
Capital .......................................................................................................... 24
CONCLUSION ........................................................................................................................ 25
APPENDIX A – COST COMPARISON MODEL .................................................................... 27
APPENDIX B – DETAILED WATER ANALYSIS................................................................... 41
APPENDIX C – MAPS OF THE ALBERTA INDUSTRIAL HEARTLAND ............................. 44
2
INTRODUCTION
This study outlines on a lifecycle cost basis the differential costs associated with
the installation and operation of a heavy oil upgrader in three locations within
Alberta, to establish whether there are economic drivers in place for potential
developers to choose one location in Alberta over another.
As a result of this study it was determined that the long term operating cost
differential for the upgrading to a 35 degree API premium synthetic crude oil
would lead to an increase of $.53 US per barrel in the La Corey location and an
increase of $.80 US per barrel for the Conklin location compared to Alberta’s
Industrial Heartland in Greater Edmonton. With an annual production of
33,945,000 barrels, the potential savings in year 1 alone from locating in the
Alberta Industrial Heartland would be:
- $18 Million U.S compared to La Corey; and
- $27 Million U.S. compared to Conklin
In addition to the financial advantages for installing an upgrader in the Alberta
Industrial Heartland, other qualitative factors were identified that indicate the
Alberta Industrial Heartland is a superior location for consideration for the
installation of an upgrader. The land development, infrastructure in place and
synergies with other industrial sites already in place represent significant factors
for the Alberta Industrial Heartland being the preferred location. In addition, the
Alberta Industrial Heartland location provides an improvement for the import of
raw water needed in the operation of an upgrader both on a surface and
groundwater basis.
3
STUDY OBJECTIVE
This study compared the relative costs for the installation of a 100 KBPD
upgrader complete with co-generation power plant. It provided a comparative
capital construction and operating cost analysis complete with time
considerations (using a net present value model) at three alternative sites. This
was a high level economic study and was not intended to provide an in depth
engineering perspective. The study’s focus was on location. The study included
the evaluation of five different locations. After an initial screening was
completed, Fort McMurray was dropped from the evaluation because of a
decision to focus on immediate upgrading potential from In-Situ sites south of
Fort McMurray and north of Cold Lake. Hardisty was eliminated due to a lack of
water.
The three final locations under consideration as shown on the next page were:
Alberta’s Industrial Heartland
Conklin area south of Fort McMurray
La Corey in the Cold Lake area
The purpose of this study was to establish whether there were economic drivers
in place for potential developers for choosing one location in Alberta versus
other alternate locations. The study focuses on the current advantages that
would exist in the Alberta Industrial Heartland in Greater Edmonton as
compared to two other locations, but the methodologies used would be valid as
a tool in comparing future upgrader site alternatives for other project developers.
4
LOCATIONS
Conklin
La Corey
5
ALBERTA UPGRADING CAPACITY
The province of Alberta has in place a significant amount of proven oil
recoverable reserves with 350 Billion BBL’s currently established.
The Athabasca oil sands is the largest of Alberta’s three oil sands deposits,
containing over 1.3 trillion barrels of initial in-place volumes of crude bitumen.
According to the Alberta Utilities Board:
“A comparison of conventional oil production and bitumen production over the
past 10 years clearly show bitumen’s increasing contribution to Alberta’s oil
production. This ability to shift from conventional oil to bitumen is unique to
Alberta, allowing the province to offset the decline in conventional oil with
bitumen production.”
6
Although conventional oil production will continue to decline, the AEUB
estimates the production of bitumen will triple by 2012. The share of nonupgraded bitumen and synthetic crude oil and equivalent supply is expected to
increase from 48 percent in 2002 to 77 percent by 2012.
The current capacity for the upgrading of bitumen exists within the province and
is being processed in four different upgrading facilities. These facilities are:
•
•
•
•
Syncrude Canada Ltd, Fort McMurray, AB (Upgrading Capacity 265
KBPD)
Suncor Energy Inc., Fort McMurray, AB (Upgrading Capacity 225 KBPD)
Shell Canada Ltd, Alberta Industrial Heartland, AB (Upgrading Capacity
155 KBPD)
Husky Oil, Lloydminster, Sask, (Upgrading Capacity 77 KBPD)
Several projects are currently under evaluation or development to increase the
capacity of upgrading within the province including:
Expansion of Existing Upgrader Facilities
•
•
•
•
Syncrude Canada Ltd. expansion (100KBPD)
Suncor Energy Inc. expansion (225KBPD)
Husky Oil expansion (77KBPD)
Shell Canada Ltd expansion, Alberta Industrial Heartland, (40KBPD)
New Upgrader Projects Planned
•
•
•
•
•
•
OPTI Canada Inc. Long Lake, Fort McMurray AB (70 KBPD)
Esso Kearl Lake Project (final capacity unknown)
Canadian Natural Resources, Fort McMurray, AB (projected capacity 232
KBPD)
Petro Canada Refinery Conversion Project, Edmonton, AB (85 KBPD)
BA Energy, Alberta Industrial Heartland, (projected 150 KBPD)
Northwest Upgrader, Alberta Industrial Heartland (projected 150 KBPD)
Although these existing and planned facilities represent a significant level of
upgrading capacity, according to the Alberta Oil Sands Technology Roadmap a
further 2,000 KBPD shortfall exists in viable upgrader production by 2030. This
7
study should assist project developers in assessing the economic merits of
choosing from current available locations.
UPGRADING ECONOMICS
The first stand-alone facility built in the Alberta region, located in the
Alberta/Saskatchewan border town of Lloydminster, was the Husky Upgrader.
This facility was a joint venture of the Alberta Government, the Saskatchewan
Government, the Government of Canada and Husky Oil. This facility was
officially opened on November 20th, 1992 at a capital cost of $1.632 billion.
The basis for the development of an upgrading project is the cost of production
of a barrel of bitumen to upgrade it from an API of 8 degree to an API of 35
degree. The profitability of an upgrader is dependent upon the amount by which
revenues from the synthetic crude oil produced exceed the costs of the bitumen
plus the related upgrading costs. The following graph gives a perspective of this
differential for the last six years.
$18.00
$16.00
$14.00
$12.00
$10.00
$8.00
$6.00
$4.00
$2.00
$0.00
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Ja 97
nAp 98
r-9
Ju 8
lO 98
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nAp 99
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Ju 9
lO 99
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Ja 99
nAp 00
r-0
Ju 0
lO 00
ct
Ja 00
nAp 01
r-0
Ju 1
lO 01
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Ja 01
nAp 02
r-0
Ju 2
lO 02
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Ja 02
nAp 03
r-0
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-0
3
$US DIFFERENTIAL/BARREL
BITUMEN DIFFERENTIAL TO LIGHT CRUDE TRACKING
PERIOD
For example, with a light crude oil price of $30/bbl, then bitumen would be $6
less ($24) in October 1997 or $9 less ($21) in October 2003.
8
There are several factors impacting the cost of upgrading but in general these
can be broken into three main cost categories:
•
•
•
The capital cost for the installation of the facility
The annual operating and maintenance cost for the operation of the
facility
Capital renewal over the plant’s lifecycle
The costs of these facilities further breakdown into the following more detailed
sub-categories:
Capital Cost
Direct Field Labor and Material Costs
Excavation and Backfill
Piling
Concrete
Structural Steel
Buildings
Mechanical Equipment
Piping
Electrical
Instrumentation
Painting
Insulation
Scaffolding
Indirect Field Costs
Temporary Construction Facilities
Construction Office Support
Project Small Tools
Project Consumables
Construction Equipment Rental
Major Cranes and Safety Equipment Rental
Constructor All Risk Insurance
Field Management and Field Supervision
Contractor’s Overhead and Profit
Personnel Camp Facilities
Bussing of Trades To Site
Bussing of Trades From Camp to Work
Location
Camp Cost
Living Out Allowances (L.O.A.)
Winter Work Allowance
Hoarding and Heating Of Materials
Freight Allowances
Overtime Allowance
Safety Allowance
QA/QC Program
Productivity
Home Office Support
Owner Costs
Contingency
Escalation
9
Operating and Maintenance Costs
Fixed Operating Costs
Operating and Maintenance Labor and
Benefits
Contract Maintenance Labor
Turnaround Accruals
Maintenance Materials
Site Warehousing Materials and Supplies
Rental and Contract Services
Waste Disposal/Environmental
Environmental Monitoring/Reporting
Taxes/Licenses/Royalties
Variable Operating Costs
Purchased Fuel
Electrical Power (Import/Export)
Water Import Makeup
Water Treatment
Catalysts and Chemicals
Natural Gas Import
Feed Pipeline Import Costs
Product Pipeline Export Costs
Transportation of Upgrader Byproducts
(Sulphur, Coke, etc;)
Insurance
Other G and A (Travel, Safety, Legal, etc;)
Capital Renewal Costs
Capital Renewal entails replacement and/or upgrading of major capital items at
the end of their economic life, and should not be confused with regular
maintenance. In this model, capital renewal is estimated in the following manner:
•
•
•
Calculate hard construction costs (excludes soft costs such as design)
In Year 1, capital renewal allowance is 1% of hard construction costs
In subsequent years, the allowance for capital renewal costs is based on
year 1 capital renewal allowance, but inflated annually
Actual capital renewal expenditures typically fluctuate wildly from year-to-year,
but the above capital renewal provisions will allow the asset manager to draw
upon the capital renewal fund if and when required.
The cost of producing an upgraded barrel of bitumen is therefore made up of:
• The Cost of Capital
• Operating Fixed Costs
• Operating Variable Costs
• Capital Renewal Costs
10
TECHNOLOGY SELECTION
There are developer factors determining the type of upgrading process
technology to be used, which impact the overall costs of the upgrader.
Developers who are in the oil production business only will tend to select
upgrading technologies which minimize capital costs and operating costs but
produce an upgraded product that is semi sour and will require further
processing. These processes have lower liquid yields and produce higher
volumes of solid byproducts. These processes involve lower usages of
hydrogen, and as result, reduce the upgrader import demands for natural gas.
They also use less water.
Other developers will choose processing technologies which increase the use of
hydrogenation as part of the upgrading process. Developers with integrated
businesses, which also have refining capability, will tend to use these types of
processes. These processes require more hydrogen, natural gas and water.
These processes have higher liquid yields and produce lower volumes of solid
byproducts. These types of upgraders have a higher capital and operating cost
than the previous type.
The location of an upgrader will have an impact on the upgrading technology
selected. Some examples of this would be:
i.)
ii.)
The availability of hydrogen or water in a specific location will impact
process technology selections.
The ability to manage large amounts of coke solids will impact
process technology selections.
The above are just a few of the examples to be considered. The current study
did not evaluate these factors as part of this location analysis but focused only
on the non-processing related differences between the locations. A more indepth analysis would include evaluating these parameters.
Two key factors in the choosing of the technology in support of this study were
to:
• Select a process whereby proven technology was being used and in
common use.
• Ensure the technology selection did not provide preferential or
exclusive advantage to an Alberta Industrial Heartland location.
11
As part of the terms of reference, coking technology was pre-selected by the
AIHA to match that in a parallel study by Purvin and Gertz. It is recognized that
alternate technologies would be considered for specific projects.
METHODOLOGY
The methodology used in the development of this study was to take economic
profiling data from previous Alberta upgrader project studies to arrive at full life
cycle cost parameters to be used in the development of an upgrader project.
These parameters were then evaluated to establish whether location had an
impact on the associated costs. The cost differentials were then established on
a price per barrel of bitumen feed being upgraded, to establish the cost for
significant factors.
All significant factors were validated for cost impact by referencing costing to
Alberta Government regional economic cost of living parameters, in house
Stantec project costing data, and reviews with third party suppliers and
contractors. Data was peer-reviewed by third party industry developers to
further validate the final findings.
A cost differential model was built that ascertained the relative total differences
on a per barrel basis. Also undertaken was a comparative analysis of economic
performance indicators over the life of the project, for the 3 locations:
• Net Present Value (NPV),
• Internal Rate of Return (IRR)
• Profitability Index (PI)
These indicators were calculated on a simplified after tax basis. The after tax
factors were deductions for Capital Cost Allowance and interest payments.
NPV is the sum of all discounted cash inflows, minus the sum of all discounted
cash outflows. NPV is the value that the project under consideration will bring to
the organization. It is driven by the cash flows that are estimated, and the
discount rate chosen. Decision rule: Accept positive NPV projects and reject
negative NPV projects. Higher-NPV projects are preferable to lower-NPV
projects.
IRR is the discount rate that makes a project’s NPV equal zero. It is a
characteristic of the project that is driven by the cash flows that are estimated.
IRR is compared to the discount rate used; as long as the discount rate is less
12
than the IRR, the project will have a positive NPV. Decision rule: accept projects
with IRR greater than discount rate. Some organizations will apply an arbitrary
premium to the discount rate, and accept only projects with IRR greater than
this “hurdle rate”. In this project the discount rate used was 6% and the hurdle
rate adopted was 12%.
PI is the sum of all discounted cash inflows, divided by the sum of all discounted
cash outflows. It is the best measure of a project’s “return on investment”
because it compares the value received, in present value terms, to what was
risked. Decision rule: accept projects with PI greater than 1 and reject projects
with PI less than 1. Do not use PI to compare projects without considering NPV
Key Assumptions
•
•
•
Discount and Interest Rate are at 6%
Escalation on operating costs was taken at 3%
US Exchange Rate used was 1.376
Details are contained in the attached spreadsheet, Appendix A.
13
BASE PROJECT
The base project used to do the analysis was a 100,000 BPD In-situ bitumen
upgrader producing a 35-degree API premium synthetic crude oil, olefinic C3C4
mix, coke and sulphur. This includes on-site generation to match steam and
electricity requirements and pipeline requirements to serve the site.
A base case study was used to develop a preliminary block flow diagram of the
upgrader using conventionally proven commercial processes. Several current
initiatives are underway to reduce the overall operating cost of a barrel of
upgrading production, using non-conventional technologies and non-commercial
processes. These initiatives will have a significant impact towards reducing the
operating cost of a barrel of upgrade bitumen. However, these initiatives were
not considered as part of this study. Refer to the Preliminary Block Flow
Diagram on the following page.
14
AIHA Upgrader - Carbonization Only - AC
ALBERTA INDUSTRIAL HEARTLAND ASSOCIATION - UPGRADER OVERALL BLOCK FLOW DIAGRAM
CASE:
CASE:
CASE:
BY:
DATE:
REVISION:
CONBONIZATION ONLY OPTION - AIR COOLER
BITUMEN
100.0
KBPD
DILUENT
43.8
KBPD
DILBIT
143.8
KBPD
20.0
API
WATER
335
USGPM
DESATL
158.1
KBPD
TO WWTU
335
USGPM
SW
239
USGPM
4.93
DESALTED DB
143.8
KBPD
DRU
158.1
KBPD
ATM RESID
86.5
KBPD
VAC RESID
54.5
KBPD
TSW
239
USGPM
COND
RIVER WATER
738
USGPM
WTU
UW/CW
65
USGPM
NATURAL GAS
14.64
MMSCFD
WT%
VDU
95.2
KBPD
KBPD
LGO
12.9
KBPD
CVGO
31.8
OG
37.6
DCU
59.9
KBPD
GRU
NAPHTHA
1.4
KBPD
NHT FEED
11.1
KBPD
H2
7.77
LGO
10.1
KBPD
KBPD
COND
513
USGPM
SMR NG
18.07
MMSCFD
TW
235
USGPM
GOHT FEED
43.6
KBPD
H2
39.66
COGEN
70.2
MW
MMSCFD
H2 COMP
SMR
52.3
MMSCFD
STEAM
110274 LB/H
NHT
13.8
KBPD
0.9
KBPD
DHT
25.3
KBPD
0.01
KBPD
GOHT
47.9
KBPD
H2
63.33
MMSCFD
AMINE
15.05
MMSCFD
SRU
TGU
SULPHUR
532.1
TPD
GRU NAP
1.0
KBPD
OFFGAS
14.11
MMSCFD
SULPHUR
38.9
TPD
SULPHUR
571.0
TPD
FG
46.20
MMSCFD
3.15
MMSCFD
TD
22.8
KBPD
27.25
MMSCFD
H2
15.78
MMSCFD
POWER
63.79
MW
BFD
CH
HRU
TO WWTU
30.42 HRU OG
MMSCFD
FG MAKEUP
18.52
MMSCFD
PLANT STEAM
SCO
78.0
KBPD
35.0 API
0.12 WT% S
TGO
43.7
KBPD
SMR H2
47.55
MMSCFD
SMR STM
217650
LB/H
STM
COLLECT
61.24
MMSCFD
C3/C4
3.3
KBPSD
NAP
11.6
KBPD
GOHT OG
0.00
MMSCFD
SRU TW
302.99
USGPM
TW
576
USGPM
MMSCFD
MMSCFD
KBPD
SMR TW
551.1
USGPM
MMSCFD
TNAP
11.4
KBPD
DHT OG
1.70
MMSCFD
DHT FEED
23.0
KBPD
H2
15.90
NAPHTHA
9.6
HGO
11.8
NHT OG
0.56
MMSCFD
DILUENT
43.8
KBPSD
0.88
KBPSD
GRU FEED
39.88 MMSCFD
0.88 KBPD
DILUENT
42.9
KBPD
SWS
RIVER WATER
96
USGPM
NATURAL GAS
51.24
MMSCFD
SULPHUR
P CHUNG
25-Jun-04
0
FG MIX
USGPM
PLANT FG
48.94 MMSCFD
COKE
3289
TPD
The following table provides typical natural gas and water import requirements
and product exports for a 100, 000-barrel per day upgrader.
IMPORT/EXPORT QUANTITIES
100KBPD UPGRADER
IMPORT/PRODUCT
RAW WATER
NATURAL GAS
SYNTHETIC CRUDE
SULPHUR
COKE
QUANITY
671 USGPM
51.24 MMSCFD
76.3 KBPD
571 TPD
3289 TPD
The base case includes the addition of a co-generation power plant and
therefore the plant is self sufficient at providing its own power needs, and there
is no significant cost to the facility for power. However, this requires an
additional import cost for water and natural gas, which has been included in the
cost analysis.
15
SIGNIFICANT LOCATION FACTORS
An economic profile was done to fully determine the life cycle costs associated
with upgraders in the three locations. The profile included a full assessment of
differences in operating costs, capital costs and revenues for the three
locations. Refer to the attached economic spreadsheet analysis in the appendix
of this study. In summary, the significant location factors for the three locations
were as follows:
OPERATIONAL
All costs indicated in this operational section are on an annual basis.
Water Treatment/Import
An upgrader requires a significant import of raw water. For the base case
analyzed the amount of raw water import was 671 usgpm. Local legislation is
pending on the use of water with a movement in place to reduce water usage.
Because of this, two evaluations were done for the three areas - one on surface
water one on ground water. Refer to table 1.
16
TABLE 1
Surface Water and Groundwater Availability
Preliminary Assessment
Water Requirements: 671 USgpm = 559 igpm = 3657 m3/day = 0.0423 m3/s
Development Area
Alberta Industrial
Heartland
(Fort Saskatchewan)
Surface Water Source
North Saskatchewan River
(Qavg > 150 m3/s)
Supplies majority of industries
in the area
Conklin Area
(South of Ft. McMurray)
Christina Lake
Jack Fish River
Christina River (Qavg > 3 m3/s)
La Corey
(Cold Lake)
Athabasca River (Qavg > 100
m3/s). Pipeline 100-150 km
required.
Cold lake
Beaver River (Qavg > 6 m3/s)
North Saskatchewan River
(Qavg > 150 m3/s). Pipeline 70100 km required.
Groundwater Source
Beverly Channel
50 < Q <700 m3/day, locally up to
1300 m3/day
Supplies Town of Bruderheim
Groundwater quality hard, TDS:
500 - 2000 mg/L
No pre-glacial buried channels
Grand Rapids Formation (bedrock)
50 < Q < 200 m3/day
Allocation for thermal project:
200,000 m3/year = 548 m3/day
= 84 igpm
TDS: 1000 – 2000 mg/L
Buried deposits
150 < Q < 700 m3/day
TDS: 500 – 1000 mg/L, maybe as
high as 3,000 mg/L
Industrial water allocation near
1985 limits. Study currently
underway to update Beaver River
Water Management Plan
Competition for water with oil
producers
Water Summary
The water analysis could not establish a significant differential to be used in the
economic modeling; however, in the opinion of the evaluation team the potential
for significant impacts with pending legislation are seen to be a real threat to the
basis for all of the upgraders. The Alberta Industrial Heartland represents the
most favorable location for the installation of an upgrader for water import. More
detailed analysis of water is provided in Appendix B.
17
Sulphur/Coke Byproduct Transport
The annual costs for shipping sulphur and coke byproducts to Prince Rupert, on
the British Columbia coast for export, from the three locations are
Alberta Industrial Heartland
La Corey (See Note)
Conklin
$37,988K/Year ($1.12/bbl)
$50,551K/Year ($1.44/bbl)
$50,551K/Year (1.44/bbl)
Note: There is no rail at LaCorey. A cost evaluation was completed of trucking
versus rail, and rail was the lowest life cycle cost option. However, at La Corey
there would be a need to add the cost of extending rail, which is $88 Million.
The Alberta Industrial Heartland location represents the best economic location
for shipment of sulphur and coke byproducts based on a transport cost
analysis.
Pipeline Transport Costs In
The transport of heavy products in the pipeline requires the use of condensate
and/or unique upstream process techniques. Pipeline annual import costs for
an upgrader at La Corey and Conklin are anticipated to be negligible as they
are directly located adjacent to sources. The Alberta Industrial Heartland would
have an additional cost associated with the import of bitumen to cover pipeline
transportation rates, and this is anticipated to cost $.64 per barrel.
La Corey and Conklin are better locations for bitumen import costs on an
economic basis as compared to the Alberta Industrial Heartland.
The synbit pipeline option, if proven viable would reduce the pipeline costs and
improve the economics for locating an upgrader in the Alberta Industrial
Heartland, compared to the other locations.
Pipeline Transport Costs Out
Product shipments from the three locations would vary. It is anticipated that
product produced in Conklin or La Corey will be shipped to Hardisty and then to
US markets. Products produced in the Alberta Industrial Heartland and Conklin
18
would be routed via Edmonton. The product annual export costs by pipeline for
the three locations are anticipated to be as follows:
La Corey
Conklin
$1.43/bbl
$1.43/bbl
$1.74/bbl
The Alberta Industrial Heartland and La Corey locations represent the best
economic location for shipment of products based on a pipeline transport cost
analysis.
The Alberta Industrial Heartland has other advantages for lower pipeline costs
by providing improved access to the West Coast and Edmonton refineries,
which at some point in market cycles offers a better price and ultimately a better
netback to producers. The total economic value for this is difficult to assess and
was not included in this economic analysis.
O & M Labor Costs
Due to the remote locations of La Corey and Conklin in relation to the Alberta
Industrial Heartland, there are differences in wages for personnel working in the
three regions. The base annual salaries for the three locations with a staff of
Administration, Operation and Maintenance personnel of approximately three
hundred and fifty (350) is:
La Corey
Conklin
$90,000K
$96,300K
$115,200K
This equates to an annual operation cost of
La Corey
Conklin
$31,500K/Year ($.93/bbl)
$33,705K/Year ($.99/bbl)
$40,320K/Year ($1.19/bbl)
The Alberta Industrial Heartland represents the best location for O & M Labor
Costs.
19
Unplanned Shutdown Turnaround Time
Due to the remote locations of La Corey and Conklin, unplanned shutdowns of
facilities and turnarounds will take a longer time to have maintenance crews
and materials put in place for dealing with the event. It is anticipated that this
will have impact on overall unit availability and therefore the anticipated
availabilities for the upgrader operated in the three locations are as follows:
La Corey
Conklin
93% (33.9 Million Barrels Per Year)
Insurance Premiums
Due to the remote location of the La Corey and Conklin sites, insurance
premiums for loss production and equipment damage are higher in these
regions than in the Alberta Industrial Heartland region. The annual insurance
premiums are anticipated to be as follows:
La Corey
Conklin
$20,000K ($.59/bbl)
$20,800K ($.61/bbl)
$20,800K ($.61/bbl)
Attrition, Education and Training Cost Impacts
The Alberta Industrial Heartland and region provides with a more stable work
force. The local amenities and access to a larger city, as compared to the
remote locations of Conklin or La Corey, make it easier for facility operators to
retain staff. Average annual attrition rates for the three various locations are
projected as follows:
La Corey
Conklin
1%/Year
4%/Year
6%/Year
The cost of recruiting and retraining a trained operator for a facility has been
equated to three times the salary for that operator. As a result of this, annual
operating costs as a result of attrition at the three locations are as follows:
La Corey
Conklin
$945K ($.03/bbl)
$4,045K ($.09/bbl)
$7,258K ($.19/bbl)
20
The Alberta Industrial Heartland region represents the best location for retaining
and maintaining core staffing.
Power Distribution Costs
The cogeneration power plant will be tied into the local power grid. Power
distribution systems for the three locations vary as a result of the actual
available infrastructure in these three locations. Power distribution facilities in
the northern part of Alberta are currently under development, to allow import of
power south. The La Corey and Conklin Areas would therefore require an
additional capital investment of:
La Corey
Conklin
$10,880K ($.03/bbl)
$10,560K ($.03/bbl)
The Alberta Industrial Heartland represents the best location from a power
distribution consideration for an upgrader, with the entire electrical infrastructure
already in place.
Transportation of Equipment and Materials
The annual costs for transportation of equipment and materials to the three
locations varies, and annual transportation cost would be estimated as follows:
La Corey
Conklin
$700K/Year ($.03bbl)
$980K/Year ($.04 bbl)
$1,050K/Year ($.04/bbl)
Camp Costs
La Corey and Conklin, due to their remote locations, will require installation
camps to facilitate annual shutdowns. These camps will add to the maintenance
costs for the upgrader each year as follows:
La Corey
Conklin
$2,000K/Year ($.06/bbl)
$2,000K/Year ($.06/bbl)
21
Travel and LOA Costs
Travel and LOA costs in support of bringing in trades staff to support annual
shutdowns is anticipated to add to the annual maintenance cost of upgraders
located in the La Corey and Conklin locations as follows:
La Corey
Conklin
$480K/Year ($.06/bbl)
$480K/Year ($.06/bbl)
CAPITAL COSTS
The following analysis details difference in capital costs for the three regions
based upon a base cost of $1 Billion for the capital cost of a 100KBPD
upgrader.
Transportation Equipment and Materials
La Corey
Conklin
$23,000K ($.07/bbl)
$32,200K ($.10/bbl)
$34,500K ($.10/bbl)
Camp Costs
La Corey
Conklin
No Camp
$50,000K ($.14/bbl)
$50,000K ($.14/bbl)
Travel and LOA Costs
La Corey
Conklin
No LOA/Travel
$14,800K ($.04/bbl)
$14,800K ($.04/bbl)
Land Costs
A 100KBPD Upgrader will occupy 2.56 square kilometers of land. The land
costs for the three regions are as follows:
La Corey
Conklin
$6,400K ($.02/bbl)
$320K (<$.01/bbl)
$498K (<$.01/bbl)
22
Land would have to be leased in the Conklin area.
Conklin and La Corey represent the lowest cost options for land costs in
support of a 100KBPD Upgrader.
Concrete
Concrete costs for construction projects in the La Corey and Conklin regions
are higher than in the Alberta Industrial Heartland, because the Alberta
Industrial Heartland is located close to a major city with concrete production
facilities. The price of concrete for the three regions would vary as follows:
La Corey
Conklin
$40,000K ($.11/bbl)
$50,769K ($.14/bbl)
$50,769K ($.14/bbl)
The Alberta Industrial Heartland represents the lowest costs for concrete in
support of construction of an upgrader.
Insurance Premiums
Due to the remote location of the La Corey and Conklin sites, insurance
premiums in support of construction are 10% higher in these regions than in the
Alberta Industrial Heartland region. The insurance premiums are anticipated to
be as follows:
La Corey
Conklin
$10,000K ($.03/bbl)
$13,200K ($.04/bbl)
$12,100K ($.04/bbl)
23
NON LOCATION FACTORS
OPERATIONAL
The following additional operational cost factors were considered but no
significant differences in cost were attributed to these factors within the scope
of this study in the three regions:
•
•
•
•
•
•
Environmental Air Emissions Systems
Municipal Taxes
Emergency Services
Natural Gas Costs
Power Costs
Water Supply Tax
CAPITAL
The following additional capital cost factors were considered but no significant
differences in cost were attributed to these factors within the scope of the study
in the three regions:
•
•
•
•
•
•
•
Contractor Capacity
Labor Costs
Overtime
Duration of Construction
Ability To Attract a Labor Force
Productivity
Home Office Costs
24
CONCLUSION
1. The preliminary study identified some significant economic differences for
the development of a project in the Alberta Industrial Heartland as compared
to alternate locations. The cost benefits on a per barrel basis are $.53 US
per barrel in the La Corey location and of $.80 US per barrel for the Conklin
location. The most significant factors being the:
•
•
Additional costs associated with transport of finished products to
market.
Additional costs associated with operational staff costs and local
attrition factors providing a more stable work force in the Alberta
Industrial Heartland location.
2. On a long-term, life cycle basis, The Alberta Industrial Heartland location is
superior as reflected in the performance indicators below:
Economic Indicators
Simplified After Tax NPV (000) (1)
Net Present Value (NPV) ($000) (2)
Internal Rate of Return (IRR) (2) (3)
Profitability Index (PI)
Total Capital Investment ($000)
Operating Costs, Year 1 ($000)
Total Barrels In, Year 1 (000)
Total Revenue, Year 1 ($000)
Total Cost/Barrel Input, Year 1 (4) ($Can)
Total Cost/Barrel Input, Year 1 ($U.S.)
AIH
Conklin
$2,075,388 $2,013,630
$3,339,740 $2,985,306
35.6%
31.4%
1.95
1.79
$1,000,000 $1,093,828
$254,224
$274,342
339,450
335,800
$699,912
$692,386
$10.59
$11.69
$7.70
$8.50
LaCorey
$2,094,332
$3,095,849
30.6%
1.84
$1,180,769
$253,891
335,800
$692,386
$11.36
$8.26
Benchmark
> $0
> $0
>12%
>1
(1) "Simplified" after tax NPV considers 2 deduction factors - depreciation & mortgage interest; other factors,
e.g. interest during construction - not examined
(1) NPV & IRR, are before tax & exclude any asset residual value
(3) IRR must be greater than the cost of capital, which is assumed to be 6%, but a 12% industry hurdle rate
is used
(4) Total Costs = annual debt service costs + operating costs + sustaining capital costs + lost unplanned
downtime revenue
25
3. The study also concluded there were other significant advantages with the
Industrial Heartland as a result of the existing land development,
infrastructure in place and synergies with other industries in the more
integrated Alberta Industrial Heartland location.
4. The Alberta Industrial Heartland area has the following advantages as it
relates to water usage for an upgrader:
•
•
•
•
Located near the North Saskatchewan River, which has a potential to
supply the required demand with relatively lesser impacts.
Located near the Beverly Channel, which is a shallow aquifer with
reasonable yields.
Not competing with oil producers for the water.
Free from restrictions on the water allocations.
In terms of groundwater, the less expensive location to develop a source of
water would appear to be the Alberta Industrial Heartland, while the more
expensive would appear to be Conklin.
It is important to keep in mind that water conservation is currently a critical
issue. There will be more scrutiny on how surface water and groundwater
are used and restrictions on water use should be expected. Recycling of
water and the use of non-potable water (TDS > 4,000 mg/L) is expected to
be encouraged. The regulatory process for water diversion, as a
consequence, is also expected to become more detailed and complex.
5. This study provides a framework for future more detailed studies to allow the
development of criteria for establishing the economic factors in evaluating
one upgrader location versus another.
26
APPENDIX A – COST COMPARISON MODEL
27
Total Costs And Differences (000)
Total Capital
AIH
Conklin
Conklin Diff. LacCorey LaCorey Diff
$1,000,000
$1,093,828
$93,828 $1,180,769
$180,769
Total Annualized Capital
Total Operating Costs
Total Capital Renewal
Lost Revenue from Unplanned Downtime
Net Annual Costs
Total Costs & Differences/Barrel
Annualized Capital/barrel
Operating Costs/Barrel
Capital Renewal/Barrel
Lost Revenue from Unplanned Downtime
Total Cost/Barrel, Can$
Total Cost/Barrel, US$
Output
Total Annual Barrels Production
$97,135
$254,224
$8,070
$0
$359,429
AIH
$106,249
$274,342
$8,783
$7,526
$396,900
Conklin
$2.86
$7.49
$0.24
$0.00
$10.59
$7.70
AIH
33,945,000
$3.13
$8.08
$0.26
$0.22
$11.69
$8.50
Conklin
33,580,000
$9,114
$20,118
$713
$7,526
$37,471
$114,694
$253,891
$9,666
$7,526
$385,777
$17,559
-$334
$1,596
$7,526
$26,348
Conklin Diff. LaCorey
LaCorey Diff
$0.27
$3.38
$0.52
$0.59
$7.48
-$0.01
$0.02
$0.28
$0.05
$0.22
$0.22
$0.22
$1.10
$0.78
$11.36
$0.80
$0.56
$8.26
LaCorey
33,580,000
28
Revenue
Oil
Coke
Sulphur
C3 C4
Total Revenue, Year 1
Capital Costs
Capital - Factors with Variances
Unique Water Treatment System
Transportation of Equipment/Modules
Camp Costs
Land Costs
Concrete Aggregate Costs
LOA/Travel Costs
Electrical Capital Cost
Rail Extension Costs
Insurance
Sub-Total - Capital Variances
AIH
$647,500,875
$44,658,042
$7,753,038
$38,289,960
$699,911,955
AIH
$0
$23,000,000
$0
$6,400,000
$40,000,000
$0
$0
$0
$10,000,000
$79,400,000
Capital Baseline (Factors w. No Significant Difference)
Construction Labor
$370,000,000
Material, excluding Transport Portion
$397,000,000
Other incl. Soft Costs
$153,600,000
Sub-Total , Capital Baseline
$920,600,000
Total Capital Costs
$1,000,000,000
Annualized Cost to Service Debt
$97,134,683
Difference
Operating - Factors with Variances
Water Treatment
Sulphur/Coke Byproduct Stream
Pipeline Transport Costs In
Catalyst & Chemicals Transport Costs
Pipeline Transport Costs Out - Oil
Oper. Staff Labor Costs incl. Admin.
(350 People)
Insurance Premiums
Attrition Education & Training Cost
Impacts
Maintenance Costs
Transportation of Equipment/Modules
Camp Costs for Annual Shutdown
Travel & LOA Costs
Land lease Costs
Sub-Total Operating Variances
AIH
Conklin
$640,538,500
$44,177,848
$7,669,672
$37,878,240
$692,386,020
Conklin
$0
$34,500,000
$50,000,000
$498,305
$50,769,231
$14,800,000
$10,560,000
$0
$12,100,000
$173,227,536
LaCorey
$640,538,500
$44,177,848
$7,669,672
$37,878,240
$692,386,020
LaCorey
$0
$32,200,000
$50,000,000
$320,000
$50,769,231
$14,800,000
$10,880,000
$88,000,000
$13,200,000
$260,169,231
$370,000,000
$370,000,000
$397,000,000
$397,000,000
$153,600,000
$153,600,000
$920,600,000
$920,600,000
$1,093,827,536 $1,180,769,231
$106,248,591
$114,693,645
$9,113,908
$17,558,962
Conklin
LaCorey
$0
$37,998,033
$21,769,336
$68,750
$48,541,350
$0
$50,551,332
$0
$103,125
$59,064,300
$0
$50,551,332
$0
$86,625
$48,541,350
$31,500,000
$20,000,000
$40,320,000
$20,800,000
$33,705,000
$20,800,000
$945,000
$20,000,000
$0
$0
$0
$0
$180,822,469
$7,257,600
$20,000,000
$350,000
$2,000,000
$480,000
$13,695
$200,940,052
$4,044,600
$20,000,000
$280,000
$2,000,000
$480,000
$0
$180,488,907
Operating Baseline - Factors W. No Significant Difference
Natural Gas Import Costs
$73,401,982
$73,401,982
Municipal Taxes.
$0
$0
Water Supply License Tax
$0
$0
Sub-Total Operating Baseline
$73,401,982
$73,401,982
Total Operating
$254,224,451 $274,342,034
$73,401,982
$0
$0
$73,401,982
$253,890,889
Capital Renewal
Unique Water Treatment System
Camp Costs
Construction Labor
Material, excluding Transport Portion
AIH
$0
$0
$40,000,000
$0
$0
$370,000,000
$397,000,000
Conklin
LaCorey
$0
$0
$50,000,000
$50,000,000
$50,769,231
$50,769,231
$10,560,000
$10,880,000
$0
$88,000,000
$370,000,000 $370,000,000
$397,000,000 $397,000,000
29
NPV Key Assumptions
Comment
Factor - Same for All Locations
Value
Discount Rate & Interest Rate
6%
Period of Analysis, years
15 Specified in terms of Reference
% of Capital That is Financed
100%
Sustaining Capital as % of Construction
1.0% Specified in Terms of Reference
Sustaining Capital Starts in Year 2
Capital Cost Allowance Rate
30.0% Some capital is depreciated at lower rates,
On CCA Schedules, there are no deletions, only additions
http://www.albertaCorporate Tax Rate for After Tax Analysis
34.6% canada.com/economy/taxes.cfm
This is a simplified after tax analysis, e.g. tax treatment of soft costs, interest during construction are ignored
Share of Capital Costs Spent in Year 1
10%
40%
50%
Inflation Rate Used for Construction Costs
6% Inflation added over construction period
Inflation Rate Used for Operating Costs
3% not inflated from now until operational date
Inflation Rate used for Capital Renewal
Inflation Rate Used for Revenue
26-May-04
U.S. Conversion Rate
0.72680
Residual Value is ignored
Impact of GST is ignored
Feed/Day, Barrels, Bitumen
100,000
Maximum Days of Production Annually
365
Nominal Annual Feed, Barrels
36,500,000
Availability
93%
Estim. Annual Base Feed (barrels)
33,945,000
Estim. Annual Output (barrels)/day
76,300
Estim. Revenue/Barrel
$25.00
AIH
Conklin
LaCorey
Factor - Vary by Location
Capacity Availability
93%
92%
92%
Annual Staff Turnover
1.0%
6.0%
4.0%
30
Economic Indicators
Total Cost/Barrel Input, Year 1 ($U.S.)
AIH
Conklin
$2,075,388
$3,339,740
35.6%
1.95
$1,000,000
$254,224
339,450
$699,912
$10.59
$7.70
$2,013,630
$2,985,306
31.4%
1.79
$1,093,828
$274,342
335,800
$692,386
$11.69
$8.50
LaCorey
$2,094,332
$3,095,849
30.6%
1.84
$1,180,769
$253,891
335,800
$692,386
$11.36
$8.26
Benchmark
> $0
> $0
>12%
>1
(1) "Simplified" after tax NPV considers 2 deduction factors - depreciation & mortgage interest; other factors,
(1) NPV & IRR, are before tax & exclude any asset residual value
(3) IRR must be greater than the cost of capital, which is assumed to be 6%, but a 12% industry hurdle rate is
(4) Total Costs = annual debt service costs + operating costs + sustaining capital costs + lost unplanned
AIH Compared to
Differential Indicators
Total Cost/Barrel Input, Year 1 ($US)
Conklin
$61,758
$354,434
4%
0.17
($93,828)
($20,118)
3,650
$7,526
($1.10)
($0.80)
LaCorey
($18,943)
$243,891
5%
0.11
($180,769)
$334
3,650
$7,526
($0.78)
($0.56)
31
Potential Significant Factors
Long Term Operating
Source Total Annual
Operating Costs
Sulphur/Coke Byproduct
Stream Transport
Comments
$10/tonne more for La
Corey/Conklin Options 571 tpd
Sulphur & 3289 tpd Coke. $2900
& $3900 per 98 Tonne car loads
Pipeline Transport Costs In Condensate recycling pipeline
costs 43.76KBPD @ $0.25/bbl for
full condensate return and import
of 143.76@ $0.37/bbl trip. .
Catalyst & Chemicals
$52.50/t La Corey $62.50/t
Transport Costs
Conklin - 550 Tonnes/Year
Pipeline Transport Costs Out - $2.74/barrel from Edmonton AND
C3 C4
La Cory to Hardisty, $3.54/barrel
from Conklin, 3,760 barrels/day
Pipeline Transport Costs Out - Product to be transported to US
Oil
via Hardisty
Oper. Staff Labor Costs incl. Includes evaluation of costs
Admin. (350 People)
associated with facilities located
adjacent & competition for similar
labor force.
Insurance Premiums
Attrition Education & Training Retraining Staff Costs against
Cost Impacts
operating budget are taken at
three times base salary X no. of
employees needing retraining.
Maintenance Costs
2 % of Capital (base) - Increments
are below
Transportation of
5% of $14 Million in Materials
Equipment/Modules
Costs with La Corey 40% Higher
& Conklin 50% Higher- from
Contractors & Mullen Trucking
Camp Costs for Annual
25,000 CMD @ $80/CMD
Shutdown
Travel & LOA Costs
4% of Labor @ $12 Million
Land lease Costs
Conklin only, via Provincial Govt.
Sub-Total Operating
Variances
Conklin
One Time Capital
Delta Costs
LaCorey
Conklin
LaCorey
AIHA - Base
AIHA Locational Variances %
Base
from Base
Annual
Order of Conklin LaCorey Conklin LaCorey
Operating Magnitude
%
%
Cost Cost Per
Cost
Cost Per
Per
Barrel
Barrel
Barrel
$37,998,033
$1.12
34%
34%
$0.37
$0.37
1
$50,551,332
$50,551,332
2
$0
$0
$21,769,336
$0.64
12
$103,125
$86,625
$68,750
$0.00
13
$4,469,632
$3,459,546
$3,497,150
$0.10
0%
2
$59,064,300
$48,541,350
$48,541,350
$1.43
3
$40,320,000
$33,705,000
$31,500,000
4
3
$20,800,000
$7,257,600
$20,800,000
$4,044,600
$20,000,000
5
6
6
7
$12,553,299
$12,553,299
-$0.64
-$21,769,336
-$21,769,336
$0.00
$0.00
$34,375
$17,875
28%
$0.03
$0.00
$972,483
-$37,604
22%
0%
$0.31
$0.00
$10,522,950
$0
$0.93
28%
7%
$0.26
$0.06
$8,820,000
$2,205,000
$20,000,000
$945,000
$0.59
$0.03
4%
6%
4%
4%
$0.02
$0.19
$0.02
$0.09
$800,000
$6,312,600
$800,000
$3,099,600
$20,000,000
$20,000,000
$0.59
$0.00
$0.00
$0
$0
$350,000
$280,000
$0
$0.00
50%
40%
$0.01
$0.01
$350,000
$280,000
$2,000,000
$2,000,000
$0
$0.00
100%
100%
$0.06
$0.06
$2,000,000
$2,000,000
$480,000
$480,000
$13,695
$0
$205,409,684 $183,948,453
$0
$0
$184,319,619
$0.00
100%
100%
$0.01
$0.00
$0.62
$0.01
$0.00
-$0.01
$480,000
$13,695
$21,090,066
$480,000
$0
-$371,166
32
-100%
LaCorey - Annual
$
-$0.64
$5.43
-100%
Conklin Annual $
Capital Renewal - 1% of Hard Construction Costs
Total Annual
1% of Hard Construction
Costs
Capital Cost
Base Capital Cost $1 Billion
Capital Cost
Comments
Transportation of
Equipment/Modules
Camp Costs
Land Costs
LOA/Travel Costs
Insurance
5% of 460 Million Capital Material
Costs Applies to La Corey Conklin
Sites Only. 50% Higher
Conklin/40% La Corey than
Edmonton Project.
$50 Million based on 580,750
CMD Applies to La Corey &
Conklin Sites Only
$10,000/Acre vs. $500/Acre in La
Corey. In Conklin, land only
available by lease, so this is the
1st year incremental lease cost.
See Op. costs for subsequent
years
Price of concrete is $165/cu.
Metres in Conklin /La Corey
vrs.$130 AIH on $40 Million of
Aggregate Costs in AIH
4% of Labor @ $370 Million for La
Corey & Conklin
$10,560,000 Conklin and
$10,880,000 La Corey , tie into
grid system in AIH is easy
La Corey requires major
extension. Fifty five miles @ $1.6
Million/Mile.
Insurance is 1% of Capital Cost
as a premium with 10% Higher
Premiums for La Corey/Conklin.
Based on Reed Stenhouse Data.
Sub-Total Capital
Conklin
LaCorey
$8,783,292
$9,666,492
Total
Capital-1time
Conklin
Annual Capital Renewal
Delta Costs
Conklin
LaCorey
NA
NA
One Time Capital Delta
Costs
LaCorey
Conklin
5 $34,500,000 $32,200,000 $11,500,000
6 $50,000,000 $50,000,000 $50,000,000
AIHA AIHA Locational Variances % from Base
Base
Base
Annual
Order of Conklin LaCorey Conklin LaCorey Conklin Capital
Magnitude
%
%
Cost Per Cost Per Annual $
Renewal
Cost Per
Barrel
Barrel
Cost
Barrel
$8,070,000
$0.24
9%
20%
$0.02
$0.05
$713,292
AIHA Base
AIHA Base
LaCorey - Annual $
$1,596,492
Locational Variances % from
Base
AIHA - Base
LaCorey
Capital 1Order of Conklin LaCorey Conklin LaCorey Conklin LaCorey Time Cost Magnitude
%
%
Cost Per Cost Per Annual $ for Annual $ For
Cost Per
Barrel
Barrel
Debt
Debt Service
Barrel
Service
$9,200,000 $23,000,000
$0.07
$0.03
$0.03 $1,117,049
$893,639
$2,234,098
$0
$0.00
$0.14
$0.14
$4,856,734
$4,856,734
$0
$320,000 -$5,901,695
-$6,080,000 $6,400,000
$0.02
-$0.02
-$0.02
-$573,259
-$590,579
$621,662
9 $50,769,231 $50,769,231 $10,769,231
$10,769,231 $40,000,000
$0.11
$0.03
$0.03
$1,046,066
$1,046,066
$3,885,387
6 $14,800,000 $14,800,000 $14,800,000
$14,800,000
$0
$0.00
$0.04
$0.04
$1,437,593
$1,437,593
$0
10 $10,560,000 $10,880,000 $10,560,000
$10,880,000
$0
$0.00
$0.03
$0.03
$1,025,742
$1,056,825
$0
11
$88,000,000
$0
$0.00
$0.00
$0.25
$0
$8,547,852
$0
$3,200,000 $10,000,000
$0.03
$0.01
$0.01
$203,983
$310,831
$971,347
$173,227,536 $260,169,231 $93,827,536 $180,769,231 $79,400,000
$0.23
$0.27
$0.52
$9,113,908
$17,558,962
8
$498,305
$0 $88,000,000
$0
4 $12,100,000 $13,200,000
$2,100,000
33
$50,000,000
Annualized
Capital
Revenue Impacts:
Revenue
Oil Revenue Loss from
Additional Unplanned
Shutdown Response Time
C3 C4 Revenue Loss from
Coke Revenue Loss from
Sulphur Revenue Loss from
Base Revenue of $901 Million
Comments
Total Annual Revenue
Annual Revenue Delta
AIHA - Base
AIHA Locational Variances % from Base
Base
Conklin
LaCorey
Conklin
LaCorey Ann. Revenue Revenue/ Conklin LaCorey % Conklin LaCorey Conklin LaCorey Barrel
%
Cost Per Cost Per Annual $
Annual $
Barrel
Barrel
1%
1%
$0.21
$0.21 $6,962,375 $6,962,375
$640,538,500 $640,538,500 -$6,962,375 -$6,962,375 $647,500,875 $19.08
based on $25/bbl & Total availability at
93% AIH & 92% for the La Corey &
Conklin Sites, of which 1% is unplanned
at AIH & 2% at other sites
based on $30/bbl & Total
14 $37,878,240 $37,878,240
-$411,720
-$411,720
$38,289,960
availability at 93% AIH & 92% for
the La Corey & Conklin Sites, of
which 1% is unplanned at AIH &
2% at other sites
$44,658,042
based on 3,289 Tonnes/day @$40/Tonne $44,177,848 $44,177,848
-$480,194
-$480,194
& Total availability at 93% AIH & 92% for
the La Corey & Conklin Sites, of which
1% is unplanned at AIH & 2% at other
sites
$7,753,038
based on 571 Tonnes/day @ $40/Tonne
$7,669,672 $7,669,672
-$83,366
-$83,366
& Total availability at 93% AIH & 92% for
the La Corey & Conklin Sites, of which
1% is unplanned at AIH & 2% at other
sites
Sub-Total, Revenue Impact
$730,264,260 $730,264,260 -$7,937,655 -$7,937,655 $738,201,915
$1.13
1%
1%
$0.01
$0.01
$411,720
$411,720
$1.32
1%
1%
$0.01
$0.01
$480,194
$480,194
$0.23
1%
1%
$0.00
$0.00
$83,366
$83,366
Cross Check
$0.23
$0.23
$1.14
$0.23 $7,937,655 $7,937,655
$0.23
$0.79 $38,854,921 $26,721,944
$21.75
Total Capital, Operating, Capital Renewal Costs & Revenue
Impact
Cross-Check
U.S. Conversion Factor
Impact on U.S. Cost/Barrel
34
$1.14
$0.79
0.728173 0.728173
$0.83
$0.57
Cash Flow Analysis for Alberta Industrial Heartland Location (000)
Construction Period
NPV
Yr. 1
Yr. 2
Yr. 3
Revenue from Upgraded Oil
Revenue from Sulphur Sales
Revenue from Coke Sales
Revenue from C3 C4 Sales
Gross Revenue
Operating Costs
Year 1
$647,501
$44,178
$7,670
$38,290
Year 2
$666,926
$45,503
$7,900
$39,439
Year 3
$686,934
$46,868
$8,137
$40,622
Year 4
$707,542
$48,274
$8,381
$41,840
Year 5
$728,768
$49,723
$8,632
$43,096
Year 6
$750,631
$51,214
$8,891
$44,389
Year 7
$773,150
$52,751
$9,158
$45,720
Year 8
$796,344
$54,333
$9,433
$47,092
Year 9
$820,235
$55,963
$9,716
$48,505
Year 10
$844,842
$57,642
$10,007
$49,960
Year 11
$870,187
$59,371
$10,307
$51,459
Year 12
$896,293
$61,152
$10,617
$53,002
Year 13
$923,181
$62,987
$10,935
$54,592
Year 14
$950,877
$64,877
$11,263
$56,230
Year 15
$979,403
$66,823
$11,601
$57,917
$6,843,322
($2,489,663)
$0
$0
$0
$0
$0
$0
$692,386
($254,224)
$720,329
($261,851)
$741,939
($269,707)
$764,197
($277,798)
$787,123
($286,132)
Operating Cash Flow
$4,353,659
$0
$0
$0
$438,162
$458,478
$472,232
$486,399
$500,991
$516,021
Initial Capital investment
Less: Capital Renewal
($943,396) ($100,000) ($424,000)
($70,523)
$0
$0
($561,800)
$0
$0
($8,070)
($8,312)
($8,561)
($8,818)
($9,083)
($9,355)
($9,636)
($9,925)
($10,223)
($10,530)
($10,845)
($11,171)
($11,506)
($11,851)
($1,013,919) ($100,000) ($424,000)
($561,800)
$0
($8,070)
($8,312)
($8,561)
($8,818)
($9,083)
($9,355)
($9,636)
($9,925)
($10,223)
($10,530)
($10,845)
($11,171)
($11,506)
($11,851)
Project Cash Flow
$3,339,740 ($100,000) ($424,000)
($561,800)
$438,162
$450,408
$463,920
$477,837
$492,173
$506,938
$522,146
$537,810
$553,945
$570,563
$587,680
$605,310
$623,470
$642,174
$661,439
Net Present Value (NPV)
($000) (1) (2)
Internal Rate of Return (IRR)
(1) (2)
$3,339,740
Investing Cash Flow
36%
2.0 1.9532357
84
(1) NPV & IRR are before tax & exclude any asset residual value
(2) IRR must be greater than the cost of capital, which is assumed to be 6% & the industry hurdle rate which is assumed to be 12%
(3) Total costs = annual debt service costs + operating costs + sustaining capital costs + lost revenue from unplanned shutdowns
PV of Cash Inflows
PV of Cash Outflows
$6,843,322
$3,503,582
35
$810,736 $835,059 $860,110 $885,914 $912,491 $939,866 $968,062 $997,104 $1,027,017 $1,057,827
($294,716) ($303,557) ($312,664) ($322,044) ($331,705) ($341,656) ($351,906) ($362,463) ($373,337) ($384,537)
$531,501
$547,446
$563,870
$580,786
$598,209
$616,156
$634,640
$653,680
$673,290
Cash Flow Analysis for Conklin Location (000)
Construction Period
NPV
Yr. 1
Yr. 2
Yr. 3
Year 1
Revenue from Upgraded Oil
Revenue from Sulphur Sales
Revenue from Coke Sales
Revenue from C3 C4 Sales
Gross Revenue
Operating Costs
Year 2
Year 3
Year 4
Year 5
Year 6
Year 7
Year 8
Year 9
Year 10
Year 11
Year 12
Year 13
Year 14
Year 15
$640,539
$44,178
$7,670
$37,878,240
$659,755
$45,503
$7,900
$39,014,587
$679,547
$46,868
$8,137
$40,185,025
$699,934
$48,274
$8,381
$41,390,576
$720,932
$49,723
$8,632
$42,632,293
$742,560
$51,214
$8,891
$43,911,262
$764,836
$52,751
$9,158
$45,228,599
$787,782
$54,333
$9,433
$46,585,457
$811,415
$55,963
$9,716
$47,983,021
$835,757
$57,642
$10,007
$49,422,512
$860,830
$59,371
$10,307
$50,905,187
$886,655
$61,152
$10,617
$52,432,343
$913,255
$62,987
$10,935
$54,005,313
$940,652
$64,877
$11,263
$55,625,472
$968,872
$66,823
$11,601
$57,294,237
$6,780,653
($2,686,678)
$0
$0
$0
$0
$0
$0
$692,386
($274,342)
$713,158
($282,572)
$734,552
($291,049)
$756,589
($299,781)
$779,287
($308,774)
$802,665
($318,038)
$826,745
($327,579)
$851,547
($337,406)
$877,094
($347,528)
$903,407
($357,954)
$930,509
($368,693)
$958,424
($379,754)
$987,177
($391,146)
$1,016,792
($402,881)
$1,047,296
($414,967)
$4,093,975
$0
$0
$0
$418,044
$430,585
$443,503
$456,808
$470,512
$484,628
$499,166
$514,141
$529,566
$545,453
$561,816
$578,671
$596,031
$613,912
$632,329
Initial Capital Investment
($1,031,913)
($76,756)
($109,383)
$0
($463,783)
$0
($614,512)
$0
$0
($8,783)
($9,047)
($9,318)
($9,598)
($9,886)
($10,182)
($10,488)
($10,802)
($11,126)
($11,460)
($11,804)
($12,158)
($12,523)
($12,899)
Investing Cash Flow
($1,108,669)
($109,383)
($463,783)
($614,512)
$0
($8,783)
($9,047)
($9,318)
($9,598)
($9,886)
($10,182)
($10,488)
($10,802)
($11,126)
($11,460)
($11,804)
($12,158)
($12,523)
($12,899)
$2,985,306
($109,383)
($463,783)
($614,512)
$418,044
$421,802
$434,456
$447,490
$460,914
$474,742
$488,984
$503,654
$518,763
$534,326
$550,356
$566,867
$583,873
$601,389
$619,430
Operating Cash Flow
Project Cash Flow
Net Present Value (NPV) ($000) (1) (2)
$2,985,306
31%
1.79
(1) NPV & IRR are before tax & exclude any asset residual value
(2) IRR must be greater than the cost of capital, which is assumed to be 6% & the industry hurdle rate which is assumed to be 12%
(3) Total costs = annual debt service costs + operating costs + sustaining capital costs + lost revenue from unplanned shutdowns
PV of Cash Inflows
PV of Cash Outflows
$6,780,653
$3,795,347
36
37
AIH Simplified After Tax Cash Flow Analysis
Construction Period
NPV
Gross Operating Income
Less: Operating Costs
Net Operating Income
Less: Depreciation
Less: Interest Expense - Mortgage
Net/Taxable Income
Less Income Taxes
Add Back Depreciation
Cash Flow Before Debt Service
Less: Debt Service - Principal
Cash Flow After Debt Service
Simplified After Tax NPV
Depreciation Schedule
Net Book Value - Beginning of Year
Additions in Year
Depreciation Rate for Additions (50%)
Depreciation Rate for Balance
Depreciation in Year
Mortgage Schedule
Period
Annual Payment
Principal
Interest
$0
$0
Year 1
$692,386
$254,224
$438,162
$121,050
$60,000
$257,112
$89,012
$0
$121,050
$289,150
$42,963
$0 $246,187
Year 2
$713,158
$282,572
$430,585
$207,102
$57,422
$166,061
$57,490
$8,783
$207,102
$306,890
$45,541
$261,349
Year 3
$734,552
$291,049
$443,503
$145,011
$54,690
$243,802
$84,404
$9,047
$145,011
$295,362
$48,273
$247,089
Year 4
$756,589
$299,781
$456,808
$101,549
$51,793
$303,466
$105,060
$9,318
$101,549
$290,636
$51,169
$239,467
Year 5
$779,287
$308,774
$470,512
$71,126
$48,723
$350,663
$121,400
$9,598
$71,126
$290,792
$54,239
$236,552
Year 6
$802,665
$318,038
$484,628
$49,831
$45,469
$389,327
$134,785
$9,886
$49,831
$294,488
$57,494
$236,994
Year 7
$826,745
$327,579
$499,166
$34,926
$42,019
$422,221
$146,173
$10,182
$34,926
$300,792
$60,944
$239,849
Year 8
$851,547
$337,406
$514,141
$24,494
$38,363
$451,284
$156,235
$10,488
$24,494
$309,056
$64,600
$244,456
Year 9
$877,094
$347,528
$529,566
$17,193
$34,487
$477,886
$165,444
$10,802
$17,193
$318,833
$68,476
$250,356
Year 10
$903,407
$357,954
$545,453
$12,084
$30,378
$502,991
$174,135
$11,126
$12,084
$329,813
$72,585
$257,228
Year 11
$930,509
$368,693
$561,816
$8,509
$26,023
$527,284
$182,546
$11,460
$8,509
$341,787
$76,940
$264,847
Year 12
$958,424
$379,754
$578,671
$6,008
$21,407
$551,256
$190,845
$11,804
$6,008
$354,615
$81,556
$273,059
0 $685,950 $478,848 $333,836 $232,288 $161,162 $111,330
$807,000
$8,783
$9,047
$9,318
$9,598
$9,886 $10,182
15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00%
30.00% 30.00% 30.00% 30.00% 30.00% 30.00% 30.00%
$121,050 $207,102 $145,011 $101,549 $71,126 $49,831 $34,926
$76,404
$10,488
15.00%
30.00%
$24,494
$51,910
$10,802
15.00%
30.00%
$17,193
$34,716
$11,126
15.00%
30.00%
$12,084
$22,632
$11,460
15.00%
30.00%
$8,509
$14,124
$11,804
15.00%
30.00%
$6,008
Year 13
Year 14
Year 15
$987,177 $1,016,792 $1,047,296
$391,146 $402,881 $414,967
$596,031 $613,912 $632,329
$4,259
$3,036
$2,181
$16,513
$11,326
$5,828
$575,259 $599,550 $624,320
$199,155 $207,564 $216,139
$12,158
$12,523
$12,899
$4,259
$3,036
$2,181
$368,205 $382,498 $397,463
$86,450
$91,636
$97,135
$281,755 $290,862 $300,328
$2,075,388
Year 1
$8,116
$12,158
15.00%
30.00%
$4,259
$3,857
$12,523
15.00%
30.00%
$3,036
$822
$12,899
15.00%
30.00%
$2,181
Year 2
Year 3
Year 4
Year 5
Year 6
Year 7
Year 8
Year 9
Year 10 Year 11 Year 12 Year 13 Year 14
Year 15
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
$102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963 $102,963
$42,963 $45,541 $48,273 $51,169 $54,239 $57,494 $60,944 $64,600 $68,476 $72,585 $76,940 $81,556 $86,450
$91,636
$97,135
$60,000 $57,422 $54,690 $51,793 $48,723 $45,469 $42,019 $38,363 $34,487 $30,378 $26,023 $21,407 $16,513
$11,326
$5,828
38
Conklin Simplified After Tax Cash Flow Analysis
Construction Period
NPV
Less: Depreciation
Net/Taxable Income
Less Income Taxes
Additions in Year
Mortgage Schedule
Period
Annual Payment
Principal
Interest
Year 1
$0 $0
Year 2
Year 3
Year 4
Year 5
Year 6
Year 7
Year 8
Year 9
Year 10
Year 11
Year 12
Year 13
$713,158
$282,572
$430,585
$225,291
$62,810
$142,484
$49,328
$8,783
$225,291
$309,664
$49,813
$259,851
$734,552
$291,049
$443,503
$157,744
$59,821
$225,938
$78,220
$9,047
$157,744
$296,415
$52,802
$243,613
$756,589
$299,781
$456,808
$110,461
$56,653
$289,694
$100,292
$9,318
$110,461
$290,545
$55,970
$234,574
$779,287
$308,774
$470,512
$77,365
$53,295
$339,853
$117,657
$9,598
$77,365
$289,963
$59,329
$230,634
$802,665
$318,038
$484,628
$54,199
$49,735
$380,694
$131,796
$9,886
$54,199
$293,211
$62,888
$230,322
$826,745
$327,579
$499,166
$37,983
$45,962
$415,221
$143,750
$10,182
$37,983
$299,273
$66,662
$232,611
$851,547
$337,406
$514,141
$26,634
$41,962
$445,545
$154,248
$10,488
$26,634
$307,444
$70,661
$236,782
$877,094
$347,528
$529,566
$18,691
$37,722
$473,152
$163,805
$10,802
$18,691
$317,236
$74,901
$242,335
$903,407
$357,954
$545,453
$13,132
$33,228
$499,092
$172,786
$11,126
$13,132
$328,312
$79,395
$248,917
$930,509
$368,693
$561,816
$9,243
$28,465
$524,109
$181,446
$11,460
$9,243
$340,445
$84,159
$256,286
$958,424
$379,754
$578,671
$6,522
$23,415
$548,734
$189,972
$11,804
$6,522
$353,480
$89,208
$264,271
$987,177 $1,016,792 $1,047,296
$391,146
$402,881
$414,967
$596,031
$613,912
$632,329
$4,618
$3,287
$2,358
$18,063
$12,389
$6,375
$573,350
$598,235
$623,597
$198,494
$207,109
$215,889
$12,158
$12,523
$12,899
$4,618
$3,287
$2,358
$367,316
$381,891
$397,166
$94,561
$100,235
$106,249
$272,755
$281,656
$290,918
0 $746,580 $521,288 $363,545 $253,084 $175,719 $121,520
$878,329
$8,783
$9,047
$9,318
$9,598
$9,886 $10,182
15.00%
15.00%
15.00%
15.00%
15.00%
15.00%
15.00%
30.00%
30.00%
30.00%
30.00%
30.00%
30.00%
30.00%
$131,749 $225,291 $157,744 $110,461 $77,365 $54,199 $37,983
$83,537
$10,488
15.00%
30.00%
$26,634
$56,903
$10,802
15.00%
30.00%
$18,691
$38,212
$11,126
15.00%
30.00%
$13,132
$25,079
$11,460
15.00%
30.00%
$9,243
$15,836
$11,804
15.00%
30.00%
$6,522
$692,386
$274,342
$418,044
$131,749
$65,630
$220,665
$76,394
$0
$131,749
$276,020
$46,994
$0 $229,026
Year 14
Year 15
$2,013,630
Year 1
$9,315
$12,158
15.00%
30.00%
$4,618
$4,697
$12,523
15.00%
30.00%
$3,287
$1,409
$12,899
15.00%
30.00%
$2,358
Year 2
Year 3
Year 4
Year 5
Year 6
Year 7
Year 8
Year 9
Year 10 Year 11 Year 12 Year 13 Year 14
Year 15
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
$112,624 $112,624 $112,624 $112,624 $112,624 $112,624 $112,624 $112,624 $112,624 $112,624 $112,624 $112,624 $112,624
$112,624
$112,624
$46,994 $49,813 $52,802 $55,970 $59,329 $62,888 $66,662 $70,661 $74,901 $79,395 $84,159 $89,208 $94,561
$100,235
$106,249
$65,630 $62,810 $59,821 $56,653 $53,295 $49,735 $45,962 $41,962 $37,722 $33,228 $28,465 $23,415 $18,063
$12,389
$6,375
39
LaCorey Simplified After Tax Cash Flow Analysis
Construction Period
NPV
Less: Depreciation
Net/Taxable Income
Less Income Taxes
Additions in Year
Mortgage Schedule
Period
Annual Payment
Principal
Interest
Year 1
Year 2
Year 3
Year 4
Year 5
Year 6
Year 7
Year 8
Year 9
Year 10
Year 11
Year 12
Year 13
$713,158
$261,508
$451,650
$247,946
$67,802
$135,902
$47,049
$9,666
$247,946
$327,132
$53,773
$273,359
$734,552
$269,353
$465,199
$173,562
$64,576
$227,062
$78,609
$9,956
$173,562
$312,058
$56,999
$255,059
$756,589
$277,433
$479,155
$121,493
$61,156
$296,506
$102,650
$10,255
$121,493
$305,094
$60,419
$244,675
$779,287
$285,756
$493,530
$85,045
$57,531
$350,954
$121,500
$10,563
$85,045
$303,936
$64,044
$239,892
$802,665
$294,329
$508,336
$59,532
$53,688
$395,116
$136,789
$10,880
$59,532
$306,979
$67,887
$239,092
$826,745
$303,159
$523,586
$41,672
$49,615
$432,299
$149,662
$11,206
$41,672
$313,103
$71,960
$241,143
$851,547
$312,254
$539,294
$29,171
$45,297
$464,826
$160,923
$11,542
$29,171
$321,531
$76,278
$245,253
$877,094
$321,621
$555,473
$20,419
$40,721
$494,332
$171,138
$11,889
$20,419
$331,725
$80,854
$250,871
$903,407
$331,270
$572,137
$14,294
$35,870
$521,974
$180,707
$12,245
$14,294
$343,315
$85,706
$257,609
$930,509
$341,208
$589,301
$10,005
$30,727
$548,568
$189,914
$12,613
$10,005
$356,047
$90,848
$265,199
$958,424
$351,444
$606,980
$7,004
$25,276
$574,700
$198,961
$12,991
$7,004
$369,752
$96,299
$273,453
$987,177 $1,016,792 $1,047,296
$361,988
$372,847
$384,033
$625,189
$643,945
$663,263
$4,903
$3,432
$2,402
$19,498
$13,374
$6,882
$600,788
$627,139
$653,979
$207,993
$217,116
$226,408
$13,381
$13,782
$14,196
$4,903
$3,432
$2,402
$384,317
$399,673
$415,778
$102,077
$108,202
$114,694
$282,240
$291,472
$301,085
0 $821,652 $573,706 $400,144 $278,651 $193,606 $134,074
$966,649
$9,666
$9,666
$9,666
$9,666
$9,666
$9,666
15.00%
15.00%
15.00%
15.00%
15.00%
15.00%
15.00%
30.00%
30.00%
30.00%
30.00%
30.00%
30.00%
30.00%
$144,997 $247,946 $173,562 $121,493 $85,045 $59,532 $41,672
$92,402
$9,666
15.00%
30.00%
$29,171
$63,231
$9,666
15.00%
30.00%
$20,419
$42,812
$9,666
15.00%
30.00%
$14,294
$28,518
$9,666
15.00%
30.00%
$10,005
$18,513
$9,666
15.00%
30.00%
$7,004
$692,386
$253,891
$438,495
$144,997
$70,846
$222,652
$77,082
$0
$144,997
$290,567
$50,729
$0 $0 $0 $239,838
Year 14
Year 15
$2,094,332
Year 1
Year 2
Year 3
Year 4
Year 5
Year 6
Year 7
Year 8
Year 9
Year 10
Year 11
Year 12
$11,509
$9,666
15.00%
30.00%
$4,903
Year 13
1
2
3
4
5
6
7
8
9
10
11
12
13
$121,575 $121,575 $121,575 $121,575 $121,575 $121,575 $121,575 $121,575 $121,575 $121,575 $121,575 $121,575 $121,575
$50,729 $53,773 $56,999 $60,419 $64,044 $67,887 $71,960 $76,278 $80,854 $85,706 $90,848 $96,299 $102,077
$70,846 $67,802 $64,576 $61,156 $57,531 $53,688 $49,615 $45,297 $40,721 $35,870 $30,727 $25,276 $19,498
40
$6,606
$9,666
15.00%
30.00%
$3,432
Year 14
14
$121,575
$108,202
$13,374
$3,174
$9,666
15.00%
30.00%
$2,402
Year 15
15
$121,575
$114,694
$6,882
APPENDIX B – DETAILED WATER ANALYSIS
APPENDIX B – DETAILED WATER ANALYSIS
Surface Water
All three sites appear to have access to a source of surface water capable of
providing the required volumes. The North Saskatchewan River has average
flow rates generally higher than 150 m3/s, suggesting no difficulty in providing
the required diversion volumes. Surface water allocations from the North
Saskatchewan River between ranges 21 and 26 W4M (inclusive) indicated a
combined license usage of approximately 7.2 m3/s (consumptive plus losses).
At Christina River and Beaver River, the average flow rates are generally higher
than 3 and 6 m3/s respectively, indicating also the potential to provide the
required volumes. However, the effects of the diversion on these two rivers
would be relatively more significant. There is one licensed diversion of water
from the Christina River, for a total usage of 40.55 m3/day (consumptive plus
losses). For Beaver River, the licensed diversions are approximately 895
m3/day.
It is important to note that the industrial water allocation within the Beaver River
Basin is near the 1985 limits. A study is currently underway to update the
Beaver River Water Management Plan.
An alternative source of water for the Conklin area would be the Athabasca
River. However, a 100 –150 km pipeline would be required to transport the
water.
For the La Corey area, the North Saskatchewan River could also be an
alternative source of water, but a pipeline 70 – 100 km long would be required.
From a regulatory perspective, all three sites would have to undergo the same
types of studies, which would include: water supply availability, a fish habitat
assessment, and a compensation plan for loss of fish habitat. The costs
associated with these studies and the regulatory proceedings would be similar.
Differences in cost may arise in the compensation plan, depending on the
specific sensitivities of each site.
The Alberta Industrial Heartland area provides an advantage based on the
proximity to the North Saskatchewan River and the potentially higher availability
of surface water for diversion. If water from the Beaver River and Christina
41
River could be used, the cost differences between the three sites would be
likely related to building the ancillary facilities at different places.
Ground Water
Groundwater may be available at all three sites. The highest yields would be
from buried sand and gravel deposits. A number of water wells would be
required to meet the water requirements.
Both the Alberta Industrial Heartland and La Corey areas could potentially
obtain water from buried deposits. In the Alberta Industrial Heartland area,
yields of the Beverly Channel generally range from 50 to 700 m3/day, with some
areas yielding up to 1,300 m3/day. The distribution and thickness of the gravel
deposits, however, are irregular and may not be present at preferred locations.
Water well depths would range from 30 to 50 m. Groundwater quality is typically
hard, with total dissolved solids (TDS) in the range of 500 to 2,000 mg/L.
In the Cold Lake area, the buried deposits of the Empress formation could
provide yields of 150 to 700 m3/day. Depth to these deposits would be in the
order of 150 m. Shallower sand deposits are also present, but may have lower
yields. The groundwater quality is also hard, with TDS generally in the ranger of
500 to 1000 mg/L, but could be as high as 3,000 mg/L.
In the Conklin area, no pre-glacial deposits have been identified and
groundwater would have to come from bedrock deposits. Water well depths
would be in the order of 200 m. Expected yield of sandstone aquifers would be
in the range of 50 to 200 m3/day. There is one allocation for a pilot thermal
project in the area to supply approximately 550 m3/day (84 igpm) from the
Grand Rapids Formation (bedrock). Groundwater quality would be expected to
have TDS in the range of 1,000 to 2,000 mg/L.
The Alberta Industrial Heartland and La Corey areas have the advantage of
being near buried channels, which would be expected to have higher yields.
Nevertheless, bedrock in the area of Conklin could also provide significant
yields of groundwater as demonstrated by the allocation for a pilot thermal
project. To meet the required demand of 3,657 m3/day, a number of water
wells would be required, probably 8 to 10 in Fort Saskatchewan and La Corey,
and 20 to 30 in Conklin, assuming that good, productive fields are identified.
42
Locating a good production well is not as straightforward as locating a river
intake because the aquifer (i.e., buried channel) may not be present at the
preferred location, or is not thick enough. In a general sense, because of the
probable well depths and groundwater yields, it would appear that it would be
less expensive to site/install production wells in the Fort Saskatchewan area,
followed by the La Corey area, and then by the Conklin area.
43
APPENDIX C – MAPS OF THE ALBERTA INDUSTRIAL HEARTLAND
44

Document Body - Copper - Alberta Industrial Heartland

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