HomeMy WebLinkAboutPhase 1 of the Southeast Alaska & Gulf of Alaska Utility Gas Distribution Project, 2-2002
Economic Assessment Executive Summary
PHASE 1 OF THE
SOUTHEAST ALASKA AND GULF OF ALASKA
UTILITY GAS DISTRIBUTION PROJECT
Prepared for
Alaska Intrastate Gas Company
February 2002
CH2MIHILL
POWER POINT PRESENTATION OF
THE ST & GULF OF PROJECT
(SEAGA )
May 12, 2003
Those invited to attend:
Mr. Jeff Stazer Federal Co-Chairman of the Denali Commission.
Mr. Paul McIntosh Project Manager, Denali Commission.
Ms. Kathleen Prentki, P.E. Denali Commission Energy Program Manager, Proj. Mer.
Ms. Rachael Petro Co-Chairman of the Denali Commission Lt. Gov. Leman’s staff.
Mr. Yuri Morgan The Alaska State Legislature’s Representative to Denali Comm.
Mr. Charies P. Fhomas, Ph.D. Sr. Energy & Environmentat Policy Analyst, U.S.
Fed: Dept. of Energy, & Energy Solutions Group, a
Business Unit of Science Applications International
Corp.
Mr. Mike Harper The Alaska Energy Authority (A_E.A.).
Mr. Jim Egan Senator Ted Stevens Staff Assistant, Anchorage office.
Ms. Patricia Heller ‘Senator Lisa Murkowski’s State Director, based in Anchorage.
Mr. Greg Kaplan Congressman Don Young’s Deputy District Director, Anchorage.
Mr. Al Ewing Denali Commission, Chief of Staff.
Executive Summary
This economic assessment examines the cost competitiveness of an Alaska Intrastate Gas
Company (AIGC) proposal to provide a utility gas system in the communities of Ketchikan,
Sitka, and Juneau, Alaska. AIGC is proposing to supply, distribute, and sell utility gas! to
these communities in a system whose components would be developed, owned, and
operated by AIGC and others. At a future date, the system might be converted to natural
gas. The success of the proposed project depends on the following factors:
e The AIGC cost of providing the service and how this cost compares to that of the readily
available alternatives: fuel oil, bottled propane, and electricity
e AIGC marketing, consumer acceptance, conversion costs, and meeting market
projections
This study focuses on the cost of providing utility gas service and the associated revenue
requirements.
Project Components
The analysis included a review of the major project elements as discussed below.
Customer Base
The system as analyzed was assumed to serve residential and small commercial customers
and all of the seafood processors that are located in the three communities. Residential and
small commercial customers primarily represent a space-heating and hot water heating
load. Asa result, their sales are the greatest in the winter and relatively low in the summer.
Seafood processors, on the other hand, represent a summer load, and therefore would even
out the year-round load by filling in the summer sales trough with relatively little additional
investment required to serve them.
Utility Gas Delivery Chain
This study analyzes the utility gas delivery chain from propane procurement through
customer billing and collection. The major elements in this delivery chain are as follows:
¢ Procure propane in Alberta and British Columbia.
e Ship the propane in railroad tanker cars to Prince Rupert, British Columbia. The tanker
cars would be owned or leased by AIGC. CN Rail would haul the railcars to and from
the propane sources to its existing facilities at Prince Rupert and load them on a barge(s)
for shipment to the communities.
1 For this utility gas system, utility gas is defined as vaporized propane that is mixed with dry air prior to delivery to customers.
ES-1
EXECUTIVE SUMMARY
e The barge would make a trip to one community, off-load full tanker cars, on-load empty
tanker cars, and return to Prince Rupert for the next round trip. At each community, a
third party, Prairielands Energy Marketing, Inc. (PEMI), would off-load the cars for use
as in-community storage (Ketchikan and Sitka) or pump the propane from the barge to
fixed storage tanks (Juneau).
¢ PEMI would construct the needed infrastructure in each community from the dock to
the “city gate,” the point at which AIGC would take delivery of utility gas. This
infrastructure would include any land-based storage and the vaporization (“send-out’”)
facilities. Within each community, there might be multiple send-out facilities at multiple
locations.
e¢ PEMI would operate the process from the docks to the city gate.
e AIGC would construct and operate an underground pipeline distribution system to
deliver utility gas to end-users.
e AIGC would contract with a local electric or water utility system for customer billing
and collection.
Community Infrastructure
Each community has different infrastructure requirements. The infrastructure used for this
analysis is as follows.
In Ketchikan, there is existing rail car infrastructure at the Saxman Seaport that can
physically accommodate the projected number of rail cars required for this new project. In
Sitka and Juneau, infrastructure would need to be developed to accommodate off-loading
and on-loading rail tanker cars and to meet storage requirements. At Sitka, Sawmill Cove
Industrial Park facilities could be upgraded to provide the needed docking, rail siding, and
rail tanker car storage. In Juneau, the area between the Little Rock Dump and the Big Rock
Dump would be developed to provide a docking facility and an area for fixed storage tanks
(no rail tanker car storage is anticipated for Juneau).
In each community there is a need for fuel storage, which would be provided either by rail
tanker car storage or permanent land-based storage tanks.
There would be two send-out facilities in Ketchikan, one in Sitka, and three in Juneau.
Propane would be trucked from the docking area to each send-out facility, where the
propane would be vaporized and mixed with air to create utility gas.
Project Schedule
A preliminary project development schedule indicates that gas utility service could begin in
July 2004 in Ketchikan, April 2005 in Sitka, and April 2006 in Juneau. This phased schedule
provides time for dock facility development in Sitka and Juneau.
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EXECUTIVE SUMMARY
Cost of Service and Revenue Requirements
Projected Sales
The number of residential utility gas customers was estimated by obtaining data on the
number of occupied households in each community. Adjustments were then made for the
number that would be located within the AIGC service area and the number that would
take utility gas service over time. It was assumed that AIGC would, in year 7, serve 60
percent of the occupied households in the identified service areas of all three communities.
Greater market penetration is favorable to the project.
Annual sales to residential and small commercial customers were estimated by applying the
above customer estimates to per-customer sales data obtained from Pacific Northern Gas
Company, which serves the Prince Rupert area. Annual seafood processor sales estimates
were obtained from AIGC.
The data on annual sales were used to determine the transportation logistics for supplying
the required fuel quantities. Peak-hour demands were estimated by PEMI to determine
send-out facility capacity requirements. Heavy-demand-period usage was estimated for
establishing in-community storage requirements.
Project Capital Costs
The estimated infrastructure costs in each community are listed in Table ES-1.
TABLE ES-1
Estimated Capital Costs for Infrastructure in Ketchikan, Sitka, and Juneau
Dock Through Local Distribution
Community Send-Out Facilities System Total
Ketchikan $3,479,535 $16,600,777 $20,080,312
Sitka $ 4,168,313 $9,268,769 $13,437,082
Juneau $13,992,260 $23,229,988 $37,222,248
Total $21,640,108 $49,099,534 $70,739,642
Note: Costs in 2001 dollars.
Estimated capital costs for the Dock through Send-Out Facilities in the table were developed
by PEMI. PEMI’s cost estimates include the following contingencies and markups:
¢ Contingencies 10%
e Engineering/Legal/ Administration 2%
e Construction Management 1%
e Permitting 2%
The utility gas local distribution system layouts were assumed to be similar to previous
layouts done by others for a natural gas distribution system. Although the previous layouts
were not available for this analysis, the construction quantities were available for this
analysis and were used in developing the cost estimates for the local distribution system
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EXECUTIVE SUMMARY
(Table ES-1). The unit costs for construction were developed by CH2M HILL and were used
to estimate the distribution system cost. Appropriate contingencies and markups were
added for engineering, project management, legal considerations, permitting, and
construction supervision. The following contingencies and markups were included in the
cost estimates for the local distribution system:
¢ Contingencies 25%
e Engineering/Legal/ Administration 10%
¢ Construction Management 3%
e Permitting 2%
The higher contingencies included in the local distribution system reflect a higher level of
uncertainty in the construction quantities and system design at this stage of the project.
Additional capital costs would be as follows:
e AIGC Startup $7,180,000
e Fuel Inventory (as of year 7) $1,130,000
e Purchase of Railcars $2,460,000
The AIGC startup costs would fund the marketing program of $3 million, provide working
capital of $3.1 million, and provide $1 million for project management.
Project Operating Costs
The annual costs to operate and maintain the in-community utility gas systems and AIGC’s
operations were estimated at approximately $920,000 in the first year of operation in
Ketchikan and $7,100,000 in year 7 when there is service in all three communities. These
costs were developed based on assumed staffing levels and individual expense items
developed in discussions with AIGC and PEMI.
Capital Structure
For this analysis, it was assumed that AIGC would have the following debt equity structure
and cost of money:
e Debt 80 percent at 5.5 percent interest rate for 30 years
e Equity 20 percent at 8 percent
This structure results in a rate of return on rate base of 6.0 percent. Discussions with one
party indicated that, for a project of this nature, the investor would be willing to invest for
an 8 percent return on equity.
The analysis was done in 2001 dollars. The above interest rates, for a project of this nature
and risk, are close to real (without consideration for inflation) interest rates. If a 2 percent
inflation rate were taken into account, the nominal (with inflation included) interest rate and
return to equity would most likely be closer to 8.0 percent and 10 percent, respectively.
ES-4
EXECUTIVE SUMMARY
Revenue Requirement Based Commodity Price
Approach
The required utility gas commodity price was computed based on the projected revenue
requirements, fuel and fuel transportation costs, operation and maintenance costs,
depreciation, taxes, and return to rate base.
The calculated commodity price is the average price over the first 7 years of operation that
would, in conjunction with a monthly service charge to each customer, allow AIGC to earna
6 percent rate of return on rate base over the 7 years. This provides for a minimum of 5
years of service in a community, at which point it was assumed that AIGC has achieved 60
percent penetration of the residential and small commercial customer base. Because service
to Juneau would not begin until the second quarter of the third year of AIGC operations, a
7-year period was necessary to have 5 years of service in each community. Use of a shorter
period, for example 5 years, would require a higher commodity price for AIGC to achieve
its rate of return in the first 5 years.
Results
Table ES-2 shows the 7-year revenue requirement calculated in dollars per million B'
(MMBtu). ,
TABLE ES-2
Seven-Year Revenue Requirement
Cost Element $/MMBtu % of Total
Cost of Propane $3.30 29.2
Cost of Propane Transportation $ 2.20 19.5
Operation and Maintenance $2.94 26.0
Depreciation $0.76 6.7
Income Taxes $0.23 2.0
Return on Rate Base $ 1.87 16.6
Total $11.30 100.0
Less: Nonrate Revenue * -$ 0.43
Total Commodity Price $10.87
* Nonrate revenues include interest earnings ($0.03/MMBtu) and monthly service
charge ($0.40/MMBtu).
Note: $/MMBtu = dollars per million British thermal units, a standard unit of measure
Interest earnings and a monthly service charge of $7.95 to each customer was included in
the analysis. This charge would provide revenues equivalent to $0.43 per MMBtu and
would reduce the effective commodity price.
The total of $10.87 per MMBtu is the average commodity price AIGC would have to charge
over the first 7 years of operations, based on the assumed utility gas sales, investments, and
ES-5
EXECUTIVE SUMMARY
operating costs, to obtain its rate of return of 6 percent over the first 7 years of operation.
This is the average rate to be charged to all customers. If, for competitive reasons, certain
customers were charged a lower rate, the remaining customers would need to be charged a
higher rate to maintain the same overall revenues.
In year 7, the revenue requirement per MMBtu would be $9.83, one dollar and four cents
less than the 7-year price. At that point, AIGC would be able to reduce its commodity price
to its customers and still achieve its revenue requirements.
Certain AIGC costs would be unavoidable, largely fixed, or beyond AIGC’s ability to
control. These costs are for propane, propane transportation, depreciation, and taxes.
Therefore, any cost reductions would have to come from operations and return to rate base
or from increased sales. AIGC should be aggressive in controlling its costs, whether in
capital investment or operations.
Key Assumptions and Sensitivity
The most important assumptions leading to this commodity rate are as follows:
e AIGC will be able to serve all of the estimated seafood processor load in each
community, the annual seafood processor sales will be at the levels projected by AIGC,
and the capital cost to serve these loads will be relatively small. Without any seafood
processor loads, the first 7 year commodity price would be increased to $12.88 per
MMBtu.
e AGIC will achieve the assumed market penetrations for residential and small
commercial customers, and sales will be at projected levels.
e AIGC can attract the assumed 20 percent equity investment at 8 percent a year and can
sell long-term debt at 5.5 percent a year.
Another significant assumption is that the historic price relationship between fuel oil and
propane will continue in the future. Historically, the prices of fuel oil and propane have
generally moved in the same direction at the same time.
The price is particularly sensitive to projected sales. The larger the volumes of utility gas
that can be sold without increasing the capital investment, the lower would be the
commodity price to consumers. At Ketchikan, for example, reducing the residential load by
25 percent and shifting that load to large commercial and industrial users would reduce the
cost of utility gas by about $0.15 to $0.20 per MMBtu, with the deferred residential
customers added in later years. The assumed sales to residential and small commercial
customers are also important in determining the commodity price. A 10 percent sales
increase to these customers would lower the commodity price by $0.36 per MMBtu; a 10
percent decrease would increase the price by $0.42 per MMBtu.
Competitive Price Comparison
The combined AIGC commodity price and service charge need to be competitive with the
cost of fuel oil for space heating and hot water, or else AIGC will not achieve the market
penetrations that were assumed. Generally, the AIGC cost needs to be 20 percent lower than
ES6
EXECUTIVE SUMMARY
the equivalent cost of fuel oil and electricity to attract a significant number of customers.
This margin is necessary for potential consumers to be willing take action and incur a
modest level of conversion costs.
The price comparison assumes that the total cost of utility gas service will be at least
20 percent below the cost of fuel oil and electricity. If conversion costs are significant, the
marginal savings from the utility gas service will need to be greater. For fuel oil users, the
conversion cost might be modest; for electric hot water and space heat customers, the cost to
convert can be significant. Without a savings margin of 20 percent, the assumed penetration
rates and sales are unlikely.
The cost of electricity that was used in the comparison is the incremental cost of electricity
from the applicable electric utility tariffs for residential, small commercial, and seafood
processors (the utility’s industrial rate was used). The comparative fuel oil prices used for
each community are the 5-year average cost per gallon from data collected by University of
Alaska Fairbanks, Cooperative Extension Service, Food Cost Survey, September 1996
through September 2001.
These costs were weighted to reflect the projected AIGC sales mix (residential/small
commercial and seafood processor), which determines the weighted cost of both electricity
and fuel oil against which AIGC will be competing. The costs were then adjusted to reflect
the conversion efficiencies for space heat and hot water heating. If the efficiency rate for a
particular appliance for a particular fuel type is less than 100 percent, the effective
commodity price for the consumer will increase. The adjusted price of utility gas was
compared to the adjusted price of electricity and fuel oil in each community. The
information is summarized in Table ES-3. For utility gas fuel, a 90 percent efficiency was
used for gas furnaces and 86 percent for hot water heaters.
Assuming a new gas appliance for space heat, the commodity price for utility gas would be
about 11 percent less than fuel oil in Ketchikan. In Sitka it would be 19 percent less than fuel
oil, and in Juneau, 24 percent less. This is within the competitive range in Sitka and Juneau.
In Ketchikan, attracting customers might be more difficult.
If, instead of new appliances, existing fuel oil furnaces and boilers were to be converted to
utility gas at an efficiency of 70 percent, the effective price of utility gas would be more
expensive than fuel oil in Ketchikan and Sitka. Consumers in Juneau would realize savings
of approximately 3 percent if they elected to convert to utility gas. However, it is uncertain
whether a savings of 3 percent would entice customers to convert to utility gas.
The commodity price needs to meet various competitive thresholds in each community for
the space heat market. AIGC must capture the space heat market in order to have sufficient
sales volumes. For a given competitiveness threshold, 20 percent, the required commodity
price is indicated. This analysis assumed that industrial fuel oil costs are 90 percent of
residential and small commercial fuel oil costs.
The larger the fuel oil price discount given to industrial users relative to residential users,
the more competitive the market will be. This is especially true in Ketchikan and Sitka
where the industrial users have a more significant share of the expected load. A greater
price discount for industrial users in Juneau would not have as large an impact because the
expected load in Juneau is dominated by the residential sector.
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EXECUTIVE SUMMARY
TABLE ES-3
Comparative Cost of Competitive Energy Sources
AIGC Electricity Cost ($/kWh) Fuel Oil Cost ($/gallon)
Utility Gas
($S/MMBtu) Ketchikan Sitka Juneau Ketchikan Sitka Juneau
Cost of Electricity/Fuel Oil
Residential/Small Commercial $0.088 $0.095 $0.088 $1.35 $1.49 $1.55
Seafood Processors $0.076 $0.085 $0.045 $1.22 $1.34 $1.40
Weighted Cost $11.27 $0.083 $0.090 $0.083 $1.30 $1.42 $1.53
Conversion Efficiency
Space Heat (New Appliance) 90% 100% 100% 100% 70% 70% 70%
Space Heat (Burner Conversion) 70% NA NA NA 70% 70% 70%
Hot Water Heater 86% 95% 95% 95% 70% 70% 70%
Adjusted Cost per MMBtu ;
Space Heat (New Appliance) $12.52 $24.27 $26.49 $24.19 $14.07 $15.37 $16.56
Space Heat (Burner Conversion) $16.10 NA NA NA $14.07 $15.37 $16.56
Hot Water Heater $13.11 $25.54 $27.88 $25.46 $14.07 $15.37 $16.56
Percent Savings
Space Heat (New Appliance) 48% 53% 48% 11% 19% 24%
Space Heat (Burner Conversion) NA NA NA -14% -5% 3%
Hot Water Heater 49% 53% 49% 7% 15% 21%
Figure ES-1 shows the estimated annual cost for space heat and hot water in Ketchikan,
Sitka, and Juneau for five comparable residences that have the following energy uses: all
electric heat and hot water appliances, all bottled propane appliances, fuel oil heat, and
electric hot water appliances; combined fuel oil space heat/hot water with electric hot water
appliances; and all utility gas appliances. These figures are for comparative purposes only.
The following data were used to calculate the estimated annual residential energy cost:
e Utility gas price of $10.87/ MMBtu (see Table ES-2) plus a monthly service charge of
$7.50 per month.
e Residential rates for electricity and fuel oil as presented in Table ES-3.
e Prices for bottled propane in each community obtained from the University of Alaska
Fairbanks, Cooperative Extension Service, Food Cost Survey, September 1996 to
September 2001.
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EXECUTIVE SUMMARY
ALL ELEC. = Electric
Space Heat and Hot
Water Appliances
BOTTLED PROPANE =
Bottled Propane for Space
Heat and Hot Water
Appliances
FUEL OIL/ELEC. = Fuel
Oil for Space Heat and
Electric Hot Water
Appliances
COMBINED = Fuel Oil
for Space/Water Heating
and Electric Hot Water
Appliances
UTILITY GAS = Utility
Gas Space Heat and Hot
Water Appliances (New)
FIGURE ES-1
Comparative Cost of Competing Energy Sources for Residential Customers
Ketchikan
a S $3,500 = oe
B $3,000 | 28°? o ‘ $2,485 & $2,500
= $1,893
3 e000 py $1,442 = $1,500 % $1,000
= $500
$ $0 § ALL ELEC. BOTTLED FUEL COMBINED UTILITY PROPANE OIL/ELEC. GAS
Sitka
a § $3500 8s $2,977 > $3,000
5 $2,500 a 5 s2,tst $1,918
3 $2,000 $1,484 5 $1,500 3 | 3 $1,000 |
= $500 2 $0
< ALL ELEC. BOTTLED FUEL COMBINED UTILITY PROPANE OIL/ELEC. GAS
Juneau
% $4,000 o $3,588 S $2,500 $3,175 |
5 =m $2,538 $2,370 | i $2,500 $1.768|
3 $2,000 :
$ $1,500 |
& $1,000
$500 — $0
< ALL ELEC. BOTTLED FUEL COMBINED UTILITY PROPANE OIL/ELEC. GAS
ES-9
EXECUTIVE SUMMARY
e Efficiency rates for space heat (new appliance), space heat (burner conversion), and hot
water heaters as presented in Table ES-3.
e Average annual energy consumption by a residential user in each community for space
heating and hot water heating: Ketchikan = 111.20 MMBtu, Sitka = 114.50 MMBtu , and
Juneau = 138.10 MMBtu.
e Assumed hot water heater energy use of approximately 21.60 MMBtu/year.
Conclusion
This project will provide a competitive and clean alternative fuel source to Ketchikan, Sitka,
and Juneau and is feasible provided that the assumptions, conditions, and projected annual
sales volumes are met as presented in this economic assessment. Deviations from any
assumptions, conditions, and projected sales volumes might increase or decrease the
commodity price and affect both the revenue requirements and the feasibility for the
proposed utility gas system.
The cost estimates and sensitivity analysis for the proposed utility gas system indicate that
AIGC will have to aggressively manage the required infrastructure and associated costs in
order to meet the competitive price targets over its first 7 years of operation. Once AIGC is
established, its ability to offer a competitive price will improve. In year 7, the revenue-
requirement-based commodity price is $9.83, which is $1.04 less than the 7-year commodity
price.
The lower sales levels in the first 3 years, when service is started in Ketchikan, Sitka, and
Juneau, would require a higher commodity price in order to meet revenue requirements.
This is the challenge faced by all capital-intensive undertakings. The analysis assumed that
AIGC will serve all of the available estimated seafood processor loads. If the served loads
are less than those assumed, the 7-year commodity price would have to be higher. If there
are other summer peaking loads than can be served with minimal additional capital
investment, they can substitute for seafood processor load. Adding additional large winter
peaking loads would not be nearly as beneficial to the commodity price as summer peaking
loads.
To the extent AIGC can increase sales without increasing capital costs, it could reduce the
commodity price. Conversely, to the extent sales do not materialize as projected, the
commodity price would need to be higher and less competitive.
If the long-term price of propane can be reduced below the assumed $0.30 a gallon, the
commodity price can be reduced about $0.11 per MMBtu for each $0.01 per gallon reduction
in the price of propane.
ES-10
SALE uo|pW / ¢ Today's Comparative Costs of Fuels within the AIGC Service Area
$28.00
$26.00
$24.00
$22.00
$20.00
$18.00
$16.00
$14.00
$12.00
$10.00
$8.00
$6.00
$4.00
$2.00
$0.00
Electric $27.68 Bottled
Propane
Fuel Oil -
Fuel Oil - Rural CH2MHill $2207 ‘¢iec2 Vian oe wie $14.33 Utili Case Gas Model Approved Utility $9.23 Tariff Rate Model ‘ Gas $7.25 Fuel Type $10.87