HomeMy WebLinkAboutCooper Valley Interim Final Report by R.W. Beck-Evaluation of Power Supply Alternatives for CVEA 1995Interim Final Report
Evaluation of
Power Supply Alternatives
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June 1995
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Interim Final Report
Evaluation of
Power Supply Alternatives
June 1995
—_— File
COPPER VALLEY ELECTRIC ASSOCIATION, INC.
P.O. Box 45, GLENNALLEN, ALASKA 99588
(907) 822-3211 FAX 822-5586 VALDEZ (907) 835-4301 FAX 835-4328
July 10, 1995
Alaska Industrio| Development end Export Authority
est Tudor Road
Anchorage, Alaska 99503-6690
SUBJECT: Interim Final Report
Dear Dennis:
As you requested, I have enclosed a copy of the Interim Final Report - June 1995
prepared by RW Beck.
If you have-any questions about the report you may contact either John Heberling
or me. For your information, the report has been provided to Dave Gray of
CH2M Hill.
Sincerely,
otf
Robert A. Wilkinson, CPA
Manager, Administration and Finance
Enclosure A , \ Wa Mey S Crh (Rom =
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- Serving the Copper River Basin and Valdez
INTERIM FINAL REPORT
EVALUATION OF
POWER SUPPLY ALTERNATIVES
TABLE OF CONTENTS
Section 1- INTRODUCTION
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SCOPE OF SERVICES
Section 2 - REVIEW OF POWER SUPPLY PROPOSALS
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Anchorage Municipal Light & Power... 2-4
Chugach Electric Association, INC. .......ccccseeseseseeseseseseeeseeeessesseseeeseeeeneseaeees 2-6
PROJEETION OF PURCHASED POWER (COSTS cnscce.scoss-cctusescussssovseesueseseseese 2-8
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Section 3 - POWER SUPPLY AND ECONOMIC ANALYSIS
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ALTERNATIVE RESOURCE SCENARIOS ....-ccocsscsccoscosesssvssseuesssesecreneuecsteansvestoons 3-3
Diesel Generation -
Sutton to Glennallen Transmission Line Option ...........cccsseseseeseseteseetesesees 3-5
INTEGRATED ‘CASE cist scosssiccausrsrbosssusearseasssssnecassssnctesresessusstsssersorectensseneesseeys 3-6
EVALUATION OF CASES AND COMPARISON OF RESULTS........:::eeeseesesees 3-6
Section 4 - SUMMARY AND FURTHER CONSIDERATIONS
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FURTHER CONSIDERATIONS ssssecsesseecsrenverscerssneeesssusneccrsecnssntucsnssenconeeesuoncacnese 4-3
This report has been prepared for the use of the client for the specific purposes identified in the
report. The conclusions, observations and recommendations contained herein attributed to
R. W. Beck constitute the opinions of R. W. Beck. To the extent that statements, information
and opinions provided by the client or others have been used in the preparation of this report,
R. W. Beck has relied upon the same to be accurate, and for which no assurances are intended
and no representations or warranties are made. R. W. Beck makes no certification and gives no
assurances except as explicitly set forth in this report.
Copyright 1995, R. W. Beck
All rights reserved.
WS6-95\3945\CVEA_RPT.DOC
Section 1
INTRODUCTION
INTRODUCTION
As part of its continuing effort to reduce its overall cost of power, Copper Valley
Electric Association, Inc. (CVEA) has undertaken a study of alternative power
supply options presently available. _CVEA provides electric service to
approximately 3,000 member-consumers in Valdez, Glennallen and the Copper
River Basin with power purchased from the State-owned Solomon Gulch
hydroelectric project supplemented with diesel generation. In April 1994, the
State of Alaska, through the Department of Community and Regional Affairs
(DCRA), Division of Energy, completed a Feasibility Study of a 138-kV
transmission line to interconnect CVEA’s electric system with the Railbelt system.
This transmission line, to be constructed between Sutton and Glennallen (the
“SGTL”), would make power generated from natural gas-fired combined-cycle
combustion turbines operated by Chugach Electric Association (CEA) and
Anchorage Municipal Light & Power (ML&P) available to CVEA. Power
production costs for both CEA and ML&P are significantly less than the cost of
power produced by CVEA’s diesel generators.
In May 1993, the State legislature appropriated $35 million for payment as a
50-year, zero-interest loan, pending completion of a feasibility study (the
“Feasibility Study”), to be used for the construction of the SGTL. Upon
completion of the Feasibility Study, DCRA accepted the Feasibility Study and
began negotiations with CVEA on the terms of the State loan. Subsequently, a
preliminary injunction was issued by U.S. federal court halting issuance of the
State loan. The preliminary injunction was dismissed on February 25, 1995.
In August 1994, CVEA issued a request for proposals for firm power to be
supplied to CVEA over the SGTL. Two proposals were received in October 1994,
one each from CEA and ML&P. The proposals identified general terms and
conditions of the proposed power sales and indicated the projected cost of power
to CVEA over a 20-year period based on certain assumptions of general inflation,
increases in the cost of fuel, future power requirements and other factors.
CVEA has retained R. W. Beck, Inc. (R. W. Beck) to review the power supply
proposals from CEA and ML&P and to provide a comparable analysis of the cost
that CVEA could expect to pay for power to be purchased over the SGTL. In
addition, CVEA requested that the study effort be extended to provide an
economic evaluation of the comparable costs associated with two other alternative
rR
INTRODUCTION
power supply options: continued diesel generation and potential integrated
operation with CEA. Several alternative power requirement, fuel cost,
construction cost and other scenarios were developed to evaluate the impact of
future conditions which vary from the base case assumptions.
This report summarizes the results of the power supply proposal review and the
expanded power supply and economic analysis. Section 2 of the report discusses
the two power supply proposals from CEA and ML&P and provides direct
comparison. The economic analyses of the alternative power supply options is
described in Section 3. Overall conclusions of the analysis are summarized in
Section 4.
It should be noted that although this study follows closely after the completion of
the SGTL Feasibility Study, several of the basic assumptions and power supply
options used in this analysis vary from those used for the Feasibility Study
primarily because many conditions have changed in recent months. In particular,
the specification of when, where and at what cost diesel generators are to be
added in the future has been refined significantly by CVEA and the projection of
future diesel fuel prices has been adjusted to reflect CVEA’s recent fuel purchase
history. CVEA’s diesel fuel costs have dropped significantly since the Feasibility
Study analysis was conducted. The cost of power to be purchased over the SGTL
as used in the economic analysis has been adjusted to reflect the projections
included in the power supply proposals received from CEA and ML&P. The base
case projection of power requirements for CVEA and the estimated cost of
construction of the SGTL used in this analysis are the same as used for the
Feasibility Study. Alternative low and high power requirement forecasts have
been developed for this study, however.
With regard to the economic analysis, this study varies significantly from the
SGTL Feasibility Study. In the Feasibility Study, the economic analysis evaluated
the costs and benefits associated with the development of the SGTL from the
perspective of the State’s potential investment in the SGTL. This study performs
all economic analyses from the perspective of CVEA. The projections of the costs
of power included in this study for the various power supply scenarios include all
costs associated with power supply for CVEA and consequently, represent the
actual cost of power production and purchases to CVEA. Further, the economic
analysis has been extended to include the projection of CVEA revenue
requirements for the alternative scenarios. This provides for a straight-forward
comparison of the impact on the cost of power to CVEA’s member-consumers
associated with each of the power supply cases.
R. W. Beck 1-2
INTRODUCTION
SCOPE OF SERVICES
The scope of services for this study was initially defined in a letter proposal to
CVEA dated November 3, 1994. Since that time adjustments have been made to
the scope to address circumstances that have changed with CVEA’s power supply
options in recent weeks. The scope of services as agreed upon by CVEA and
R. W. Beck is as follows:
a, Provide a complete review of the two power purchase proposals received
from CEA and ML&P using the basic data included in the proposals
augmented with additional information obtained from CEA and ML&P.
Provide a side-by-side comparison of the cost of power as proposed in the
two proposals on a comparable basis for the proposed term of the contracts
and include a description of the underlying principals used in the
calculations.
Determine the basic assumptions of capacity availability used by both CEA
and ML&P, particularly with regard to when new generating resources are
expected to be included in the ratebase.
Review the impacts on CVEA if CEA were to include the costs of the SGTL as
a CEA system cost and subsequently sell power to CVEA. Identify cost
impacts on CEA’s existing customers resulting from this “integrated case”.
Develop an economic analysis model for the purpose of estimating the cost of
power to CVEA for a 20-year period for two primary power supply plans as
follows:
= Diesel expansion case
m= SGTL case with power purchases from the lowest cost provider, either
ML&P or CEA.
Work with CVEA staff to develop the timing of retirements and additions and
costs to be associated with the diesel expansion case.
Perform the economic analysis for a set of base case assumptions and
conditions as well as for alternative assumptions. The alternative
assumptions are to be used to estimate the sensitivity of the results primarily
to varying power requirements and fuel costs.
Conduct a work session with CVEA staff and board members to discuss the
study methodology and assumptions and present the preliminary results.
Provide a written report summarizing the results of the study.
R. W. Beck 1-3
Section 2
REVIEW OF POWER SUPPLY PROPOSALS
INTRODUCTION
In August 1994, CVEA requested proposals for firm power to be delivered over
the SGTL and received responses from ML&P and CEA. Both ML&P and CEA
have significant surplus generating capacity available at the present time and both
utilities had expressed interest in supplying power to CVEA prior to the issuance
of the request for proposals. The power to be sold to CVEA by either ML&P or
CEA would be generated by natural gas-fired combustion turbines and combined-
cycle combustion turbines. CEA presently sells firm power to its retail customers
and three wholesale customers, Matanuska Electric Association, Homer Electric
Association and the City of Seward Electric System. In addition, CEA sells non-
firm economy energy to Golden Valley Electric Association (GVEA) over the
Anchorage-Fairbanks intertie. ML&P sells power to its retail customers and four
off-system customers. ML&P also competes with CEA and GVEA for the sale of
economy energy to Fairbanks Municipal Utility System.
CEA presently has 612 MW of generation capacity of which 148 MW is
hydroelectric capacity. In 1993, CEA’s total system peak demand was 356 MW.
Approximately 51% of the energy sold by CEA is attributable to CEA’s retail
system with the remainder associated with sales to the wholesale customers.
Generating utilities in the Railbelt are required to maintain generating reserves
equal to 30% of their respective peak demands. With allowances for generating
reserves, CEA had approximately 150 MW of surplus generating capacity in 1993.
CEA presently forecasts that its total system power requirement will increase at
approximately 1.56% per year over the next 23 years.
ML&P has 375 MW of generating capacity and had a peak demand of 143 MW in
1993 representing a 189 MW generating capacity surplus after reserve
requirements. ML&P’s power requirements are forecasted to increase at 1% per
year for ML&P’s medium load growth scenario.
ML&P and CEA both have extensive planning efforts underway continuously to
evaluate future power requirements and power supply resources. As part of
these planning efforts, the need for additional generating resources is being
evaluated and the available generating resource options and alternative costs are
being investigated.
Although the two power supply proposals are different in many ways, they are
similar in that both contracts are for up to a 20-year term and CVEA would pay
aT
REVIEW OF POWER SuPPLY PROPOSALS
both a demand charge and an energy charge for the amount of power purchased.
In general, the demand charge would be established based on the allocation of the
respective system’s fixed power production costs according to the percentage of
total system peak demand that CVEA’s load represents. The energy charge is
basically the cost of fuel used to generate the power to be sold to CVEA plus
variable operations and maintenance costs. Since CEA and ML&P both generate
power using natural gas as fuel and the cost of natural gas to both utilities is
similar, the energy cost component in both proposals is comparable. Both
proposals indicate that the cost of power to CVEA would be adjusted over time to
reflect actual costs of power production in the future.
Both proposals state that the power to be sold to CVEA is firm, i-e., available at all
times, and would be sold on a “take-and-pay” basis. Take-and-pay means that
CVEA would pay only for the power it actually uses as opposed to guaranteeing
the purchase of a fixed amount of power. CEA’s proposal clearly indicates that all
power requirements of CVEA in excess of Solomon Gulch generation will be
supplied for the duration of the contract term on a take-and-pay basis. ML&P’s
proposal, however, states that power will only be supplied to CVEA as long as
ML&P has sufficient power resources available unless CVEA reserves and pays for
a fixed amount of power. At the present time it is projected that ML&P will have
adequate generating capacity to supply CVEA’s demand for the duration of the
contract. If ML&P’s loads grow faster than currently projected or significant
amounts of power are sold to other utilities, CVEA may need to reserve a certain
amount of power to be purchased and essentially convert its power purchase
arrangement to “take-or-pay”.
It is expected that the actual terms and conditions of a power purchase contract
would be negotiated following selection by CVEA of the chosen provider.
A comparison of the principal aspects of the two proposals is shown in Table 2-1.
Both ML&P and CEA have provided projections of the cost of power to CVEA
under alternative load growth scenarios. We have not duplicated all of these
scenarios as part of this study. For the purpose of comparison, however, the base
case projections are shown in Table 2-2 under the subheading, Comparison of
Proposals.
R. W. Beck 2-2
REVIEW OF POWER SupPPLy PROPOSALS
TABLE 2-1
COMPARISON OF POWER SUPPLY PROPOSALS
PRINCIPAL TERMS AND CONDITIONS
STMT ML&P Proposal CEA Proposal
10-20 Years (CVEA Option) 10-20 Years (Negotiated)
APUC CEA Board, APUC
Solomon Gulch Yes No
| Banking
Delivery Point O'Neill Substation Teeland/Palmer Substations
| Energy:
| Billing Energy
Base Specified O&M Rate Average of CEA system
Fuel:
aan ical Rate eae Incremental Average of CEA system
Inflation Light Sweet Crude Oil Futures | Beluga
Between 88% and 110% of
Marathon price
Marathon
1/3 Light Sweet Crude Oil
| 1/3 PPI of Natural Gas
1/3 CPI-U of Fuel Oil
Capacity:
Billing Demand Greater of: CVEA Actual coincident peak net of
1.) Reserved Capacity Solomon Gulch
Allocated Demand __ | Billing Demand Greater of:
Net CP for previous year
Y* (Net NCP-70% S.G. capacity)
where Y =
0.0 in 1st year
0.2 in 2nd year
0.4 in 3rd year
| 0.6 in 4th year
0.8 in 5th year
1.0 thereafter
Capacity Increase Reserved Capacity or | Not Applicable
| Requirements above __ | purchase non-firm energy
| Reserved amount
continued on following page
R. W. Beck 2-3
REVIEW OF POWER SuPPLY PROPOSALS
fe ML&P Proposal CEA Proposal
Capacity Costs Generation Generation, Transmission, General
}| Allocated and Administrative
Load Growth
Limited by Available
Resources. CVEA has right of
first refusal before AML&P
offers capacity to other
utilities.
Commitment to provide all of
CVEA’s net requirements
DESCRIPTION OF PROPOSALS
ANCHORAGE MUNICIPAL LIGHT & POWER
ML&P has provided a proposal to supply the net power requirements of CVEA
for a term of between 10 and 20 years, at the option of CVEA. ML&P would sell
power to CVEA generated by ML&P gas-fired generators and would provide
delivery at the O'Neill Substation in Sutton. The proposal states that power
would be sold on a firm, “take-and-pay” basis and that CVEA would pay only for
the power that it takes from ML&P. The amount of power purchased, however,
is subject to a minimum purchase requirement if CVEA elects to reserve a certain
amount of capacity. The proposal establishes a Base Capacity Amount as an
agreed upon minimum capacity to which CVEA would be entitled without
reservation and would pay for whether or not it is used. This amount would
approximate CVEA’s initial year peak demand over the SGTL coincident with
ML&P’s system peak demand. It is not clear if the Base Capacity Amount would
become a minimum purchase requirement that CVEA would be obligated to pay
for each year even if CVEA’s load decreases.
The price of power to be sold to CVEA would include an energy component and a
capacity charge. The capacity charge is to be based on CVEA’s contribution to the
prior year’s total ML&P system peak demand, or CVEA’s reserved capacity
amount, whichever is greater. The capacity charge is structured to compensate
ML&P for an allocated share of the annual production costs associated with
having generating capacity available to meet the firm requirements of its
customers. At the present time, ML&P indicates that these production costs are
approximately $9 million per year and include depreciation expense, debt service
and ML&P’s allowed return on its equity in its production plant. CVEA’s firm
capacity charge would be calculated each year by multiplying the total ML&P
annual capacity cost by the ratio of CVEA’s coincidental peak demand during the
year to the total ML&P system peak demand during the same year. The total
ML&P system peak demand in this equation would include the demand
requirement of CVEA over the SGTL at the time the system peak occurs. If CVEA
R. W. Beck 2-4
REVIEW OF POWER SuPPLY PROPOSALS
elects to reserve a capacity amount, the reserved amount is used in the calculation
of the capacity charge rather than the actual amount used by CVEA.
CVEA will be able to use the Solomon Gulch project to its advantage in
establishing the annual capacity charge. Since the capacity charge is based on
CVEA’s demand over the SGTL at the time of ML&P’s system peak demand,
CVEA may be able to operate the Solomon Gulch project so as to reduce its
demand on ML&P at that time. For the purpose of the presentation of estimated
power costs, ML&P has assumed that Solomon Gulch will generate 6 MW at the
time of ML&P’s system peak demand.
From time to time, CVEA may reserve a capacity amount for which it will pay
regardless of whether or not the full amount is used. ML&P has not guaranteed
that it will maintain adequate generating capacity to supply CVEA’s load in the
future unless CVEA actually reserves a capacity amount. At the present time, it is
projected that ML&P will have sufficient generating capacity through the possible
20-year maximum term of the contract. In the future, ML&P has indicated that it
will notify CVEA if it intends to enter into a power sales contract with another
utility which could affect ML&P’s available capacity and allow CVEA to reserve a
capacity amount. Figure 2-1 shows ML&P’s existing capacity resources and
projected loads, with CVEA’s load, through 2017.
The energy component of ML&P’s proposed contract is based on the incremental
cost of generating the power to be used by CVEA. The cost will include the
incremental cost of fuel, start-up costs (in situations where the incremental load
requires starting a generating unit), ML&P’s variable cost of production operation
and maintenance (O&M), and wheeling charges for the transmission of power to
the O’Neill Substation over transmission lines currently owned by others. The
energy charge is designed such that ML&P’s existing customers will realize no
negative cost impacts from the sale of power to CVEA. Over time, the energy cost
will be adjusted to account for actual costs. ML&P’s natural gas fuel prices are to
be adjusted in proportion to the rate of increase (or decrease) in Light Sweet
Crude Oil Futures, an index that is similar to the index for the West Texas
Intermediate Crude Oil for which the State of Alaska Department of Revenue
(DOR) has developed projections.
Presently, ML&P’s variable O&M charge is 2.26 mills per kWh. This charge is
projected to increase over time at the general rate of inflation. Wheeling charges
for transmission are estimated by ML&P to be 0.06 cent per kWh between ML&P’s
Plant No. 2 and Palmer over Alaska Power Administration lines and 0.1 cent per
kWh between Palmer and the O’Neill Substation over MEA lines.
ML&P has developed projections of the cost of power to CVEA under various
load scenarios. These projections show that under certain CVEA load conditions,
higher than the base or medium load growth scenario, the energy charge to
R. W. Beck 2-5
REVIEW OF POWER SUPPLY PROPOSALS
CVEA is slightly higher. This is because of the incremental nature of the charge
and with higher loads, ML&P expects to need to operate slightly less efficient
generating units.
As shown in Figure 2-1, ML&P has sufficient generating capacity to supply all of
its load requirements through 2017 based on current load projections. ML&P
does not intend to install any new generating resources during this time period,
however, it does expect to repower and refurbish some of its existing resources.
In its projection of the cost of power to CVEA, ML&P has included the expected
costs of these production plant improvements.
ML&P’s proposal indicates that Solomon Gulch energy can be “banked” by
CVEA. This would permit CVEA to utilize the full output of the Solomon Gulch
project rather than spill water in the summer as is presently done because the
energy generation capability of the project exceeds CVEA’s present loads. The
present pricing structure of Solomon Gulch power would probably not make
banking of the energy economically attractive to CVEA since power could be
purchased from ML&P at a lower rate than the Solomon Gulch purchase power
rate. ML&P has further indicated that if it were allowed to dispatch the Solomon
Gulch project, the net cost of power sold to CVEA may be 2-4 mills per kWh less
than if CVEA dispatches Solomon Gulch.
CHUGACH ELECTRIC ASSOCIATION, INC.
CEA’s proposal is to supply firm power in the amount of CVEA’s net
requirements on a take-and-pay basis with no minimum purchase amount.
Unlike ML&P, CEA will provide for the full power requirements of CVEA, net of
Solomon Gulch generation, regardless of how CVEA’s or CEA’s loads change over
time. CEA would deliver power to CVEA at the O'Neill Substation, however,
CEA has not included the cost of wheeling the power over MEA transmission
lines between Palmer and the O'Neill Substation, estimated to be 0.1 cent per
kWh, in its proposed rates to CVEA. The proposed term of the contract is 10 to 20
years beginning at the completion of the SGTL. The power sales rate for power
purchased from CEA will be tariffed rates subject to approval by the Alaska Public
Utility Commission. Similar to the proposal from ML&P, the actual cost that
CVEA pays for power will change over time depending on CEA’s actual cost of
power production. CEA presently sells firm power to three other utilities. The
terms and conditions of the power sales contracts between CEA and its other
utility customers may factor in to the terms and conditions that CEA would
eventually negotiate with CVEA.
The price of power to CVEA would include a monthly customer charge (currently
$150), a demand charge and an energy charge. The demand charge is related to
CVEA’s allocated share of CEA’s total fixed generation, transmission, and
R. W. Beck 2-6
REVIEW OF POWER SUPPLY PROPOSALS
administrative and general costs, which include depreciation, interest expense
and other fixed costs. Each year, CEA would determine the total allocated
demand charge on a pro rata basis based on CVEA’s contribution to CEA’s total
coincidental peak demand. CVEA could use Solomon Gulch to its advantage in
lowering the demand charge by operating Solomon Gulch at or near its full
capacity at the time of CEA’s peak demand. Although the demand charge is
established once per year, it would be charged on a monthly basis for the total
monthly demand that CVEA places on CEA.
During the first five years of the proposed contract, CEA would establish the
CVEA demand charge as discussed above except that the CVEA demand factor to
be used in the allocation of fixed costs would be based on the greater of the
following:
1. CVEA coincidental peak demand at the time of CEA’s system peak, and
2. A factor Y multiplied by (CVEA’s non-coincidental peak demand less 70% of
the capacity of Solomon Gulch), where Y equals 0, .2, .4, .6, .8 and 1.0 in the
first through sixth years, respectively.
The adjustment in Item 2, above, allows a phasing in of the total demand charge
to CVEA but whether or not it in itself will provide benefits to CVEA, as compared
to the straight coincidental peak allocation for Item 1, depends on how CVEA will
operate Solomon Gulch. Although Item 2 would be the lower of the two
alternatives in the first year, if Solomon Gulch is operated at or near full capacity
at the time of CEA’s system peak Item 2 could become the larger of the two
alternatives within a year or two. CEA has indicated that it could dispatch
Solomon Gulch as a CEA system resource. Under this scenario it is not known
how the demand allocator would be established since the use of Solomon Gulch
would be at the discretion of CEA.
CEA’s demand charge is expected to increase during the proposed contract term
primarily because of the planned addition of new generating units to supply
CEA’s total system requirements. CEA is currently planning to retire several of its
Beluga generating units beginning in 2005. In addition, CEA has an agreement
with Alaska Electric Generation and Transmission Cooperative, Inc. (AEG&T) and
Homer Electric Association for the use of the 40 MW Soldotna #1 gas-fired
combustion turbine that is expected to terminate in 2005. New generators are
planned by CEA to be added in 2006, 2007, 2008, 2011, 2014 and 2016. Figure 2-2
shows CEA’s existing and planned generating capacity as it compares to CEA’s
projected system load requirements, including the load of CVEA. As can be seen
in Figure 2-2, CEA expects its current generation surplus to decrease significantly
in approximately ten years but the addition of new generating units will provide
sufficient capacity to supply projected load requirements.
R. W. Beck 2-7
REVIEW OF POWER SuPPLY PROPOSALS
The new generating units presently planned by CEA contribute significantly to
the increase over time in CEA’s projected cost of power to CVEA. If CEA were to
refurbish its existing units rather than replace them with new units, cost savings
may be realized that could lower the projected cost of power.
CEA’s energy charge is established based on the cost of fuel, variable production
O&M and the variable cost of power purchases. The energy charge is projected to
increase over time with assumed increases in general inflation and in fuel costs.
CEA purchases natural gas from three sources, the Beluga River Field Producers
(Arco, Shell and Chevron), Marathon Oil Company and Enstar Natural Gas
Company. The price of natural gas to CEA is established by contract and adjusted
over time according to certain indices generally tied to oil prices.
PROJECTION OF PURCHASED POWER COSTS
In projecting the cost of power from each of the two proposers, ML&P and CEA,
we have relied upon the projections provided by ML&P and CEA with certain
modifications to these projections which were made at our request. In their
respective proposals, each utility made various assumptions with regard to
inflation and fuel cost escalation. We requested and ML&P and CEA provided
modified power rate projections using common assumptions for these variables.
The projections made by ML&P and CEA were developed using their respective
in-house financial and power supply modeling capabilities.
In addition to the inflation and fuel cost assumptions, it was also noticed that CEA
had used different CVEA power requirements projections in its rate projections
than ML&P had used beginning in 2006. There was also a difference in the
assumed operation of the Solomon Gulch project that was noticed between the
two proposals. In order to compare the two proposals, we developed alternative
projections of the total cost of power to be incurred by CVEA using the same
power requirements and Solomon Gulch operation. For the projections, CVEA’s
purchased power requirements are based on the medium load growth scenario
from the load forecast developed for the SGTL Feasibility Study, less Solomon
Gulch annual energy generation. The Solomon Gulch project is further assumed
to be generating 6 MW at the time the coincidental peak demand occurs.
Three separate projections of the total power cost to CVEA from CEA and ML&P
are provided. Table 2-2 shows the comparison of power costs from ML&P and
CEA using the power rates provided by CEA and ML&P using the same
assumptions for inflation and fuel cost escalation. Annual inflation is assumed to
be 3.5% for 1994 and 1995, 3.6% for 1996, 3.8% for 1997, 3.6% for 1998 through
2000, and 3.7% thereafter. This is the projection of annual inflation as provided
by CEA. Fuel costs have been escalated so as to be consistent with the DOR Fall
1994 base-case projection of West Texas Intermediate Crude Oil prices. The
R. W. Beck 2-8
REVIEW OF POWER SUPPLY PROPOSALS
calculations for Table 2-2 use the CVEA load forecast assumptions used by ML&P
and CEA which are different. As can be seen in Table 2-2, the ML&P power cost,
although higher than the power cost for CEA for the first two years, is lower in
the later years when comparing the two original proposals. The total present
value savings to CVEA in purchasing from ML&P over the 20-year contract
period would be $9,891,000 assuming an 8.5% annual discount rate.
Table 2-3 shows the comparison of power costs for the two proposals with the
same CVEA power requirements and using the same power rates as used for the
case shown in Table 2-2. In this case, the total present value savings to CVEA
represented by purchasing power from ML&P is $8,361,000.
A third case has also been developed to show the comparable cost of power to
CVEA if the demand cost allocator used by CEA in determining its demand
charge is based on Solomon Gulch generating only 6 MW at the time of CEA’s
system peak. In its base case projections, CEA had assumed that Solomon Gulch
would generate approximately 12 MW at the time of system peak thereby
lowering the allocated demand cost to CVEA. Table 2-4 shows the results of this
case while also employing the comparable fuel, inflation and CVEA load
requirement assumptions described for the previous two cases. As can be seen in
Table 2-4, the total present value savings to CVEA if power were to be purchased
from ML&P is $14,596,000 using an 8.5% discount rate.
Figure 2-3 shows the projected cost of power to CVEA on a cents per kWh basis
for the three scenarios. Note that the projected cost of power from ML&P is the
same for all three scenarios. As can be seen in Figure 2-2, power purchases from
ML&P are projected to be lower than from CEA in nearly all years of the contract
period.
In addition to its proposal for power sales, CEA has approached CVEA with the
concept of integrated operations. The integrated case is discussed in detail in the
following subsection of this report.
INTEGRATED CASE
In a letter to CVEA dated March 14, 1994, CEA proposed the concept of including
the cost of constructing and operating the SGTL as a CEA system cost. In this
letter, CEA indicated that such an arrangement could potentially be beneficial to
CVEA, CEA and its wholesale customers. Very little detail was provided with the
letter and CEA indicated in subsequent discussions that it was not in a position to
provide further analysis for this “integrated case”. Because the integrated case
could offer significant benefits to CVEA, it was considered important by CVEA to
review this concept further.
R. W. Beck 2-9
REVIEW OF POWER SUPPLY PROPOSALS
In order to evaluate the cost effects of the integrated case on both CVEA and CEA,
we relied upon a model that we previously developed to project CEA wholesale
power costs. The debt service and operating costs of the SGTL were included as a
CEA system cost and allocated over all of CEA’s power sales. The SGTL is
assumed to be financed with a $35 million, zero-interest State loan with the
remainder of the construction cost financed with a $21.3 million loan with a 7.5%,
30-year term. The basic CEA system costs included in this projection are based on
CEA’s 1994 Financial Forecast which are not necessarily consistent with the
system costs used by CEA in its projection of power sales rates to CVEA in its
proposal as previously described. The analysis as developed, however, is
consistent with itself and can be used to determine the cost impacts of the
integrated case.
The results of the integrated case analysis are shown in Table 2-5. In this table,
CEA Base Costs w/o CVEA are the costs of operating CEA’s production and
transmission system as currently projected without CVEA. The Additional Costs
w/CVEA lines indicate the additional production costs associated with CEA
supplying power to CVEA. The Intertie Costs lines show the capital and O&M
costs associated with the SGTL. The CEA Costs w/Intertie line totals the costs that
CEA will incur if it were to serve CVEA and pay the costs of the SGTL. Finally,
Table 2-5 shows the projected revenues that CEA would receive from sales to
CVEA and the net benefit or cost to CEA. The two blocks of results on Table 2-5
show the net benefit or cost to CEA for two scenarios. The first scenario uses
CEA’s assumption of the CVEA billing demand allocator whereby the Solomon
Gulch project generates at near capacity at the time of CEA’s system peak
demand. The second scenario allocates demand costs assuming that the Solomon
Gulch project is only generating 6 MW at the time of CEA’s system peak demand.
Although neither of these two scenarios shows a benefit to CEA, the net cost to
CEA is less for the second scenario because CVEA’s share of CEA allocated
demand costs would be higher and CVEA would consequently pay more for its
power purchases.
As can be seen in Table 2-5, the costs to CEA associated with the integrated case
exceed the projected power sales revenues from CVEA in all years for the “High
Demand Allocation Case”. This implies that CEA would need to raise the cost of
power to all of its customers if it were to include the SGTL as a CEA system cost.
CEA had originally proposed the integrated case with the intention that system
costs would be higher in the early years but that eventually the margins received
from the sales to CVEA would exceed the annual costs of supplying CVEA plus
the costs of the SGTL. If CVEA loads are higher than assumed in our analysis, the
benefits may exceed the costs at an earlier time. It is expected that CEA would not
be able to implement the integrated case if the annual costs to its system exceed
the benefits for more than a few years because of the impact on CEA’s existing
customers. CEA could however establish rates for power sales to CVEA that
R. W. Beck 2-10
REVIEW OF POWER SUPPLY PROPOSALS
allocated a higher percentage of the SGTL costs to CVEA than to CEA’s other
customers.
Although CEA system costs may go up with the integrated case, there are obvious
benefits to CVEA. If CEA were able to carry the capital repayment and operating
costs of the SGTL as a CEA system cost as shown in Table 2-5 and CVEA were able
to purchase power from CEA at a wholesale rate comparable to the rate projected
for MEA, the cumulative present value of the total power cost to CVEA for the 20-
year period 1995 through 2014 is estimated to be $78.2 million. This compares to a
total cumulative present value of power costs for the same period of $83.9 million
for the base SGTL case representing a present value savings of $5.7 million for the
integrated case. The resulting total cost of power to CVEA for the integrated case
is 8.3 cents per kWh for the year 2000. This compares to 9.1 cents per kWh for the
base diesel case and 9.6 cents per kWh for the base SGTL case for the same year.
The wholesale power purchase rate to CVEA is projected to be approximately 6.7
cents per kWh in 1999 increasing to 9.3 cents per kWh in 2014. The wholesale rate
projections are based on projections developed by CEA as presented in CEA’s
1994 Financial Forecast with adjustment for including the costs of the SGTL as a
CEA system cost. The estimated impact on the wholesale cost of power resulting
from the sale of power to CVEA and including the cost of the SGTL in CEA’s
ratebase is approximately 0.1 cent per kWh in 2000 decreasing to essentially no
impact by 2008. This cost differential will vary depending on how the Solomon
Gulch project factors in to the allocation of CEA system demand costs to CVEA.
In developing the estimate of the total power cost for the integrated case, it is
assumed that CVEA would continue to operate and use the output of the
Solomon Gulch project to supply its own loads. Because the cost of Solomon
Gulch power is projected to be slightly less than the projected cost of wholesale
power purchased from CEA, the net savings of the integrated case would be
lower if CVEA were to purchase its full requirements from CEA.
Figure 3-1 shows the projected cost of power to CVEA with the SGTL for both a
“non-integrated” ML&P purchase case and an integrated CEA purchase case. For
the non-integrated case, the annual costs of the SGTL are borne solely by CVEA
and power is assumed to be purchased from ML&P, the lower cost provider on a
“non-integrated” basis. Both of these cases assume medium load growth,
continued sales to PetroStar, medium fuel escalation and the purchase of power
to supply loads that are the net of power to be provided by the Solomon Gulch
project.
R. W. Beck 2-11
Figure 2-2
Chugach Electric Association
Projected Loads and Resources
7, Resources —a— CEA Load Plus 30% Reserves —— CEA Plus CVEA
; aa —_
Table 2-2
Copper Valley Electric Association
Comparison of Power Supply Proposals
Proposed Rates - Minimal Modification (1)
Net Delivered Energy Projected Rates Projected Costs
ML&P CEA ML&P. CEA (2) ML&P. CEA ML&P Savings
Energy Energy Energy Capacity Average | Energy Capaci Average || Energy Capacity Total | Energy Capacity Energy Capacity Total
Year} (GWh) _(GWh)___% Dif. | (c/kWh)_(c/kWh)_(c/kWh) | (c/kWh)_$/kW-mo_(c/kWh)_(c/kWh) }|_ ($000) __ ($000) __($000)_| ($000) __($000) ($000) _ ($000) __ ($000)
1998 36.4 36.4 0.0% 2.52 1.49 4.01 2.80 3.08 0.92 3.72 917 541 1,458 1,019 335 102 (206) (105)
1999 37.3 373 0.0% 2.61 1.46 4.07 2.93 3.43 1.02 3.95 973 544 1517 1,091 381 118 (163) (45)
2000 38.2 38.1 0.0% 271 1.44 4.15 3.09 4.26 1.32 441 1,033 549 1,582 1,180 502 147 (46) 100
2001 39.1 39.1 0.0% 2.81 1.42 4.23 3.15 6.05 1.99 5.14 1,097 556 1,653 1,230 777 133 221 354
2002 39.8 39.8 0.0% 2.92 1.41 4.33 3.32 GI 2.62 5.93 1,162 562 1,724 1319 1,040 156 478 635
2003 40.4 40.4 0.0% 3.04 1.40 444 3.45 9.92 3.41 6.86 1,230 567 1,797 1395 1379 165 812 977
2004 41.1 41.1 0.0% 3.16 1.39 4.55 3.55 10.16 3.44 6.99 1,299 4 1,870 1,457 1412 159 841 1,000
2005 41.7 41.7 0.0% 3.29 1.38 4.67 3.67 10.69 3.59 7.26 1371 575 1,946 1,529 1,497 158 922 1,079
2006 42.3 43.4 26% 3.42 1.37 4.79 4.19 10.72 3.49 7.67 1,448 578 2,026 1816 1512 369 934 1303
2007 42.9 45.2 5.2% 3.56 1.35 4.91 4.22 10.94 3.45 7.67 1,528 579 2,107 1,905 1,559 376 980 1356
2008 43.6 46.9 7.7% 3.70 1.33 5.03 4.02 11.09 3.41 742 1,614 579 2,193 1,885 1,599 271 1,019 1291
2009 44.2 48.8 10.3% 3.85 131 5.16 4.23 11.65 3.50 7.73 1,704 578 2,282 2,062 1,708 358 1,130 1,488
2010 44.9 50.6 12.8% 4.00 1.29 5.29 444 12.13 3.57 8.00 1,794 577 2371 2,245 1,805 451 1,228 1,679
2011 45.5 525 15.4% 4.15 1.27 5.42 4.64 13.02 3.78 8.41 1,890 576 2,466 2,434 1,982 544 1,407 1,951
2012 46.2 544 17.9% 431 1.25 5.56 485 13.08 3.69 8.54 1,991 575 2,566 2,638 2,011 647 1,436 2,083
2013 46.9 56.4 204% 4.48 1.23 5.70 5.08 13.01 3.58 8.66 2,097 574 2671 2,867 2,017 770 1,443 2,213
2014 46.5 58.4 25.5% 4.65 1.21 5.85 5.21 13.21 3.55 8.76 2,162 561 2,723 3,040 2,075 878 1514 2392
2015 46.2 60.4 30.7% 482 1.19 6.01 5.47 13.22 3.46 8.93 2,230 549 2,778 3,303 2,093 1,073 1544 2,617
2016 45.9 62.5 36.1% 5.01 1.17 6.18 5.66 13.49 3.50 9.16 2,299 536 2,836 3,539 2,185 1,240 1,648 2,888
2017 45.6 64.6 41.7% 5.20 115 6.35 5.92 13.25 3.38 9.30 2,372 524 2,896 3,822 2,185 1,450 1,661 3,112
Present Value (1998 - 2017) @ 8.5% 19,387 9,891
Note: (1) Rates pursuant to projections provided by AML&P and CEA revised for consistent fuel escalation and inflation.
(2) CEA's rates do not include potential wheeling costs over MEA's system of approximately 1 mill per kWh.
Table 2-3
Copper Valley Electric Association
Comparison of Power Supply Proposals
Proposed Rates - Revised CEA Loads
Projected Rates (2) Projected Costs
Projected Sales (1) ML&P CEA (3) ML&P. CEA (4) ML&P Savings
et CEA
Delivered Billing
Energy Net Peak Demands} Energy Capacity Average] Energy Capacity Average}] Energy Capacity Total | Energy Capacity Total | Energy Capacity Total
Year (GWh)__ (MW)__ (MW-mo) | (¢/kWh)_(¢/kWh)_(c/kWh) | (c/kWh)_$/kW-mo (c/kWh)_(c/kWh)]]_($000) ($000) ($000) ($000) ($000) ($000) | ($000) ($000) ($000)
1998 36.4 9.4 108.7 2.52 1.49 4.01 2.80 3.08 0.92 3.72 917 541 1,458 1,019 335 1354 102 (206) (104)
1999 37.3 95 111.0 2.61 1.46 4.07 2.93 3.43 1.02 3.95 973 544 1517 1,092 381 1,472 118 (163) (44)
2000 38.2 97 117.9 2.71 1.44 4.15 3.09 4.26 1.32 441 1,033 549 1,582 1,181 502 1,683 147 (46) 101
2001 39.1 99 128.4 2.81 1.42 4.23 3.15 6.05 1.99 5.14 1,097 556 1,653 1231 777 2,008 134 221 355
2002 39.8 10.0 133.9 2.92 1.41 433 3.32 A 2.61 5.93 1,162 562 1,724 1319 1,040 2,360 157 478 635
2003 40.4 10.1 139.0 3.04 1.40 4.44 3.45 9.92 3.41 6.86 1,230 567 1,797 1395 1379 2,774 166 812 977
2004 41.1 10.2 139.0 3.16 1.39 4.55 3.55 10.16 3.44 6.99 1,299 571 1,870 1,458 1412 2,870 159 841 1,000
2005 417 10.3 140.0 3.29 1.38 4.67 3.67 10.69 3.59 7.26 1371 575 1,946 1,530 1497 3,026 158 922 1,080
2006 42.3 10.4 141.5 3.42 1.37 4.79 4.19 10.72 3.58 LAE: 1,448 578 2,026 1,771 1516 3,287 323, 938 1,262
2007 42.9 10.5 142.9 3.56 1.35 491 4.22 10.94 3.64 7.86 1,528 579 2,107 1811 1,564 3375 283 985 1,268
2008 43.6 10.6 144.4 3.70 1.33 5.03 4.02 11.09 3.68 7.69 1,614 579 2,193 1,749 1,602 3,351 136 1,023 1,159
2009 44.2 10.7 145.9 3.85 131 5.16 4.23 11.65 3.85 8.07 1,704 578 2,282 1,869 1,700 3,570 166 1,122 1,288
2010 44.9 10.9 147.5 4.00 1.29 5.29 444 12.13 3.99 8.42 1,794 577 2371 1,989 1,789 3,778 195 1,212 1,407
2011 45.5 11.0 149.0 4.15 1.27 5.42 4.64 13.02 4.26 8.90 1890 576 2,466 2,110 1,940 4,050 220 1365 1,584
2012 46.2 111 150.6 431 1.25 5.56 4.85 13.08 4.27 9.11 1,991 575 2,566 2,238 1,970 4,208 247 1395 1,642
2013 46.9 11.2 152.2 448 1.23 5.70 5.08 13.01 4.23 9.31 2,097 574 2,671 2,382 1,980 4362 285 1,406 1691
2014 46.5 11.3 153.8 4.65 1.21 5.85 5.21 13.21 4.37 9.57 2,162 561 2,723 2,423 2,032 4,454 261 171 1,732
2015 46.2 11.4 155.4 4.82 1.19 6.01 5.47 13.22 445 9.91 2,230 549 2,778 2,526 2,054 4,580 296 1,506 1,802
2016 45.9 11.6 157.0 5.01 1.17 6.18 5.66 13.49 4.62 10.28 2,299 536 2,836 2,600 2,118 4718 300 1,582 1883
2017 45.6 11.7 158.7 5.20 1.15 6.35 5.92 13.25 461 10.53 2372 524 2,896 2,698 2,102 4,800 326 1,578 1,904
Present Value (1998 - 2017) @ 8.5% 19,387 27,748 8,361
Note: (1) Adjusted CEA projected energy to be consistent with CVEA's medium-high load forecast. The percentage increase in net peak was applied to the projected billing demands for the period 2006-2017. (2) Rates pursuant to projections provided by AML&P and CEA revised for consistent fuel escalation and inflation.
(3) CEA's rates do not include potential wheeling costs over MEA's system of approximately 1 mill per kWh. (4) The projected demand and energy rates provided by CEA were applied to the adjusted demand and energy to calculate the expected demand and energy revenues.
Table 2-4
Copper Valley Electric Association
Comparison of Power Supply Proposals
Proposed Rates - Revised CEA Loads and High CEA Demand Allocator
Projected Rates (2) Projected Costs
Projected Sales (1) ML&P. = CEA (3)(4) ML&P CEA ML&P Savings Net CEA Delivered Billing
Energy Net Peak Demands| Energy Capacity Average] Energy Capacity Average]| Energy Capacity Total | Energy Capacity Total | Energy Capacity Total
Year (GWh)___ (MW) __(MW-mo) | (c/kWh)_(c/kWh)_(c/kWh) | (c/kWh)_ $/kW-mo_(c/kWh)_(c/kWh)]}}_ ($000) ($000) ($000) ($000) ($000) ($000) _| ($000) __ ($000) ($000)
1998 36.4 94 69.6 2.52 1.49 4.01 2.80 4.69 0.90 3.70 917 541 1,458 1,019 326 1346 102 (215) (113)
1999 37.3 9.5 714 2.61 1.46 4.07 2.93 4.90 0.94 3.87 973 544 1517 1,092 350 1441 118 (194) (75)
2000 38.2 9.7 73.3 2.71 1.44 4.15 3.09 9.92 1.90 5.00 1,033 549 1,582 1,181 727 1,907 147 178 325
2001 39.1 9.9 75.1 2.81 1.42 4.23 3.15 16.00 3.08 6.23 1,097 556 1,653 1,231 1,202 2,433 134 646 780
2002 39.8 10.0 76.6 2.92 1.41 4.33 3.32 21.45 4.13 7.44 1,162 562 1,724 1319 1,644 2,963 157 1,082 1,239
2003 40.4 10.1 77.9 3.04 1.40 4.44 3.45 26.85 5.17 8.62 1,230 567 1,797 1395 2,093 3,488 166 1,526 1,692
2004 41.1 10.2 79.2 3.16 1.39 4.55 3.55 26.96 5.20 8.75 1,299 571 1,870 1458 2,136 3,594 159 1,565 1,724
2005 41.7 10.3 80.5 3.29 1.38 4.67 3.67 28.98 5.60 9.27 1371 575 1,946 1,530 2,334 3,864 158 1,759 1,917
2006 42.3 10.4 81.8 3.42 1.37 4.79 4.19 30.17 5.83 10.02 1,448 578 2,026 1771 2,468 4,238 323 1,890 2,213
2007 42.9 10.5 83.1 3.56 1.35 4.91 4.22 31.33 6.06 10.28 1,528 579 2,107 1811 2,603 4,414 283 2,024 2,307
2008 43.6 10.6 84.4 3.70 1.33 5.03 4.02 32.38 6.27 10.29 1,614 579 2,193 1,749 2,732 4,482 136 2,153 2,289
2009 44.2 10.7 85.7 3.85 1.31 5.16 4.23 31.46 6.10 10.33 1,704 578 2,282 1,869 2,696 4,565 166 2,118 2,284
2010 44.9 10.9 87.0 4.00 1.29 5.29 444 30.99 6.01 10.45 1,794 577 2371 1,989 2,697 4,687 195 2,120 2315
2011 45.5 11.0 88.4 4.15 1.27 5.42 4.64 32.22 6.26 10.89 1,890 576 2,466 2,110 2,848 4,958 220 2,272 2,492
2012 46.2 111 89.8 431 1.25 5.56 4.85 34.05 6.62 11.46 1,991 575 2,566 2,238 3,056 5,294 247 2,481 2,728
2013 46.9 11.2 911 4.48 1.23 5.70 5.08 33.05 6.43 11.51 2,097 574 2,671 2,382 3,012 5394 285 2,438 2,723
2014 46.5 113 92.5 4.65 1.21 5.85 5.21 33.53 6.67 11.87 2,162 561 2,723 2,423 3,102 5,525 261 2,542 2,802
2015 46.2 114 93.9 482 1.19 6.01 5.47 32.37 6.58 12.04 2,230 549 2,778 2,526 3,040 5,566 296 2,492 2,788
2016 45.9 11.6 95.3 5.01 1.17 6.18 5.66 32.68 6.79 12.45 2,299 536 2,836 2,600 3,114 5,714 300 2,578 2,879
2017 45.6 117 96.7 5.20 1.15 6.35 5.92 31.97 6.78 12.70 2372 524 2,896 2,698 3,092 5,790 326 2,568 2,894
Present Value (1998 - 2017) @ 8.5% 19,387 33,983 14,596
Note: (1) Adjusted CEA pro} energy to be consistent with CVEA's medium-high load forecast. The projected demand was estimated as CVEA NCP less 6 MW of Solomon Gulch. The billing demands were adjusted for the expected usage of Solomon Gulch. (2) Rates pursuant to projections provided by ML&P and CEA revised for consistent fuel escalation and inflation. (3) CEA demand rates were adjusted for the potential high demand allocator assuming the same demand as for the ML&P rate. This reflects an upper range of the CEA proposal. (4) CEA's rates do not include potential wheeling costs over MEA's system of approximately 1 mill per kWh.
|
Table 2-5
Copper Valley Electric Association
Estimated Effect of Intertie Case on CEA's System Costs ($000)
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2001 2012 2013 2014 2015 2016 2017
CEA Base Costs w/o CVEA $180,740 $188,569 $199,544 $206,980 $214,437 $221,288 $233,949 $252,313 $261,259 $266,787 $274,587 $282,778 $296,887 $315,371 $323,812 $338,571 $349,159 $364,924 $375,571
Additional Costs w/CVEA
Fuel Cost Increase 916 1,094 1,085 1s 1,196 1,229 1,219 1,658 1,786 1,682 1724 1,923 2,088 2,271 2523 2,139 2,295 2,465 2,703
Other Costs oO 0 (25) 1 (25) u 0 1 0 2: 1 1 it (24) 1 2 (23) (22) (24)
Total CEA Costs w/CVEA. 181,656 189,663 200,604 + = 208,096 §= 215,608 §9= 222,518 += 235,168 += 253,972 263,045 268,471 = -276,312 =. 284,702. 298,976 9 317,618 +9 326,336 §=— 340,712 9 351,431 = 367,367 = 378,250
Intertie Costs
Capital Costs 2503 2,503 2,503 2,503 2,503 2,503 2,503 2,503 2,503 2503 2503 2503 2,503 2,503 2,503 2,503 2,503 2,503 2,503
O&M Costs 270 280 290 300 310 321 332 344 356 369 381 395 409 423 438 453 469 485, 502
Total Intertie Costs 2,774 2,783 2,793 2,803 2,814 2,825 2,836 2,848 2,860 2,872 2,885 2,898 2,912 2,926 2,941 2,957 2,972 2,989 3,006
CEA Costs w/Intertie $184,430 $192,446 $203,397 $210,899 $218422 $225,343 $238,004 $256,820 $265,905 $271,343 $279,197 $287,600 $301,888 $320,544 $329,277 $343,669 $354,403 $370,356 $381,256
Net Costs to Serve CVEA $3,690 $3,877 $3,853 $3,919 $3,985 $4,055 $4,055 $4507 $4,646 $4,556 $4,610 $4,822 $5,001 $5,173 $5,465 $5,098 $5,244 $5,432 $5,685
Cents per KWh 9.90 10.16 9.86 9.85 9.85 9.87 9.73 10.65 10.82 10.46 10.43 10.75 10.99 11.20 11.66 10.73 10.88 11 11.47
Net Benefit or (Costs) to CEA
Based on Adjusted Loads
CEA Revenues from CVEA $1,477 $1,752 $2,158 $2,584 $3,002 $3,091 $3,282 $3,635 $3,720 $3,686 $3,729 $3,799 $3,975 $4,216 $4,270 $4356 A392 $4503 $4579
Cents per KWh 3.96 459 5.52 6.49 742 753 7.87 8.59 8.66 8.46 8.44 8.47 8.73 9.13 9.11 9.17 9.11 9.21 9.24
Net CEA Benefit (Cost) ($2,213) _ ($2,125) __($1,695)_($1,335) ($983) ($963) ($773) ($871) ($926) ($870) ($881) __ ($1,024) __ ($1,026) ($958)__($1,195)__($742) ($853) ($929) __ ($1,106)
Based on High Demand Allocation
CEA Revenues from CVEA 1A77 1,931 2446 2,971 3,486 3,580 3,809 4,186 4,293 4,281 4311 4374 4576 4,852 4891 4,988 5,005 5,125 5,190
Cents per KWh 3.96 5.06 6.26 747 8.62 8.72 914 9.89 10.00 9.82 9.75 9.75 10.05 10.51 10.44 10.50 10.39 10.49 10.47
Net CEA Benefit (Cost 5276) 5299) 25) 95}
Note: All costs are based on the information provided in CEA's proposal and not adjusted for fuel price escalation and inflation. CVEA demand and energy assumed to be delivered at O'Neil Substation.
Cents per KWh —z- ML&P
Figure 2-3
CVEA Power Supply Comparison
Proposed Power Purchase Rates
t——+——t pes t t t—— t t t t 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
—m- CEA High Demand —¥— CEA Base —>< CEA Adj Loads
Section 3
POWER SUPPLY AND ECONOMIC ANALYSIS
INTRODUCTION
In order to evaluate the costs and benefits associated with the alternative resource
options available to CVEA, a detailed power supply and economic analysis has
been conducted. This analysis evaluates CVEA’s capacity loads and resources,
energy loads and resources and power supply costs for each year of a 20-year
period, 1995 through 2014 for two primary resource options:
= Diesel generation
= Implementation of the SGTL with power purchases from the lowest cost
Anchorage-area provider.
Alternatively, another option for evaluation, as previously described, is integrated
operation with CEA.
Each of these resource scenarios was established with a base case of assumptions.
Additional cases were then developed for alternative assumptions for load
growth, fuel costs, and new development capital costs.
An analytical model was developed to evaluate the alternative cases. This model
evaluates the need for additional CVEA capacity resources to supply load and
maintain sufficient generating reserves, determines what resources are used to
generate the energy requirements, and accumulates all costs associated with
power production, including capital and operating costs. All costs in the analysis
are shown in nominal (inflated) dollars.
ASSUMPTIONS
Principal assumptions used in the power supply and economic analysis are
summarized as follows:
1. Annual inflation is assumed to be 3.5%.
2. For the purpose of present value calculations, the annual discount rate is
8.5%.
3. Future CVEA generation additions will be financed with Rural Utility Service
(RUS) debt at a 5.0% annual interest rate. Repayment periods are 20 years for
diesel generators and 30 years for the SGTL.
AVE a
POWER SuPPLY AND ECONOMIC ANALYSIS
10.
FT
The SGTL will be financed with a $35 million, zero interest, 50-year State loan
and $20.2 million of RUS debt. The total construction cost of the SGTL,
$47.6 million in 1993 dollars, is the same as estimated in the SGTL Feasibility
Study. For the SGTL resource option, the initial year of operation of the
SGTL is 1999.
Diesel fuel prices in 1995 are $0.63 and $0.65 per gallon in Valdez and
Glennallen, respectively. Fuel prices are escalated at the general rate of
inflation plus two-thirds of the real annual escalation in oil prices of 1.1%,
2.0% and -1.5% for the medium, high and low fuel price cases, respectively, as
forecast by DOR in its Fall 1994 projections. The two-thirds factor is used to
represent the portion of delivered oil prices that would be tied to the cost of
oil as opposed to delivery cost.
CVEA future power requirements are based on the medium case forecast
provided in the SGTL Feasibility Study. For the high load forecast case, an
estimated load of 50,000 MWh per year is added to represent assumed energy
sales to the Alyeska Marine Terminal Facility. For the low load forecast case,
the estimated load of the PetroStar refinery is removed from CVEA’s total
energy requirement.
CVEA will maintain generating capacity in each of its load centers capable of
supplying the full peak demand of the particular load center with the largest
generating unit in that load center unavailable. With the SGTL, Glennallen
will only need to maintain generating capacity sufficient to supply its own
peak demand because there will be two transmission feeds available to supply
power.
Transmission losses over the SGTL are 5.0%. Transmission losses between
Valdez and Glennallen are 3.0%.
The total annual energy generation capability of the Solomon Gulch
hydroelectric project is 54,500 MWh of which 25,900 MWh would be
generated in the winter (October through May) and 28,600 MWh would be
generated in the summer (June through September). This is a maximum
energy generation capacity which would decrease if loads are not sufficient to
use all of the Solomon Gulch output.
The Solomon Gulch project will be operated so as to retain the capability to
generate 6 MW at any time during the winter months.
Fuel usage of CVEA’s diesel generators is 13.5 kWh per gallon for existing
units, 15.0 kWh per gallon for new units and 14.5 kWh per gallon for the most
efficient existing unit that is planned to be transferred from Glennallen to
Valdez in the diesel resource option.
R. W. Beck 3-2
POWER SUPPLY AND ECONOMIC ANALYSIS
12. Variable O&M costs for diesel generators is 1.25 cents per kWh in 1995
dollars. Costs will increase at the rate of general inflation.
13. The annual labor and benefits cost for a generator operator is $101,000 in 1995
dollars.
14. The cost of power purchased from the Solomon Gulch hydroelectric project is
6.6 cents per kWh of which 4.0 cents per kWh is a fixed debt service
component and 2.6 cents per kWh is the O&M component that will increase
over time at the assumed rate of general inflation.
15. Operating costs of CVEA, other than power production costs, will increase at
the assumed rate of general inflation.
ALTERNATIVE RESOURCE SCENARIOS
At the present time, CVEA has two primary resource scenarios that have been
identified as its principal future power supply options. Both scenarios provide
power sufficient to meet CVEA’s power supply requirements that are in excess of
the generating capability of the power from the Solomon Gulch hydroelectric
project. The SGTL however, will be capable of transmitting up to 40 MW which is
more than the forecasted power requirements of CVEA during the analysis
period. In developing each of the resource scenarios, consideration was given for
both the capacity and energy requirements of CVEA’s total power requirements.
The coincidental maximum or peak electrical demand of CVEA’s consumers plus
the need to maintain some generating capacity in reserve establishes the capacity
requirement. Since it is not practical for CVEA to install or remove generating
capacity each year as the capacity requirement changes, new generating resources
are usually sized to fulfill the projected capacity increases for several years in to
the future.
Upon establishment of the timing of new resource additions, the energy resources
needed to supply the total energy requirements are determined. CVEA is
obligated to use the energy output of the Solomon Gulch project before using
other resources. Solomon Gulch is not capable of supplying the full energy
requirement, however, which means that other energy resources are needed. In
the case of diesel generation, this additional generation requirement will be
further assigned to the most efficient diesel generators that CVEA has in its
system. In the analytical model developed for this study, the need for energy
generation is determined each year and the supply of this generation requirement
is then specified based primarily on a comparison of costs of the available
resources.
The two primary resource scenarios are described as follows:
R. W. Beck 3-3
POWER SupPLyY AND ECONOMIC ANALYSIS
DIESEL GENERATION
In this scenario, diesel generators are proposed to be used to fulfill the capacity
and energy requirements of CVEA net of Solomon Gulch. This is the Base Case
because it represents the present situation. Several modifications are proposed to
be made to CVEA’s diesel generating plants over the next few years in order to
improve the operation of these facilities and to lower overall operating costs. In
general, CVEA plans to automate the diesel plants by installing supervisory
control and data acquisition (SCADA) controls on several of the existing diesel
generating units and on all units installed in the future. All diesel generators
would then be able to be remotely controlled from a single dispatch control center
at the Solomon Gulch powerhouse reducing the need for operators at both the
Glennallen and Valdez diesel plants.
Other plans involve the removal and replacement of the two 2,500 kW Enterprise
units presently located in the Glennallen power plant with two SCADA-controlled
2,865 kW units in 1996. A 4,000 kW oil-fired combustion turbine is also planned to
be installed in Glennallen in 1997. This turbine would be used primarily as
backup and as a quick-start peaking unit. One of the diesel generators removed
from Glennallen would be moved to Valdez in 1997, installed in the power plant
and retrofitted with SCADA controls. With the completion of these
improvements, CVEA expects to be able to reduce its diesel O&M staff by five
employees, four in Glennallen and one in Valdez.
R. W. Beck 3-4
POWER SUPPLY AND ECONOMIC ANALYSIS
The following table shows the planned diesel case improvements and additions.
TABLE 3-1 |
DIESEL SCENARIO
PROPOSED ADDITIONS AND IMPROVEMENTS |
Estimated Cost |
Year Action ($000)
1996 | Install two new 2,865-kW diesel generators in GDP $2,699
1996 | Remove Units 6 and 7 from GDP included a
1996 |Add SCADA controls to new GDP diesel generators $164
1996 |Add SCADA controls to VDP 4 and 5 $164
1997 | Install GDP Unit 7 in VDP $120
1997 | Add SCADA controls to “new” VDP diesel generator $59
1997 | Install new solar turbine in GDP $1,384
SUTTON TO GLENNALLEN TRANSMISSION LINE OPTION
For the purpose of this analysis, the SGTL is projected to be available in 1999 at
the earliest. It would be capable of delivering up to approximately 40 MW of
power to CVEA although it will be necessary to install static VAR compensation
for system reliability purposes if power deliveries exceed approximately 15 MW.
If development of the SGTL were to proceed, it is not expected that CVEA would
pursue any of the diesel generator improvements indicated in the diesel option.
Rather, CVEA would continue to operate the system as it is presently operated
until the SGTL became operational. With the SGTL, the generation reserve
requirement in Glennallen is reduced because there would be two independent
transmission feeds in to Glennallen, one from Valdez and one from Sutton. It is
still expected that adequate generating capacity would be maintained in Valdez
by CVEA to supply the full local load requirement in the case of a transmission
failure.
With installation of the SGTL, CVEA expects to reduce its diesel O&M staff by a
total of seven employees leaving two operators to keep the diesel generation
system maintained and in standby mode. Power is to be purchased from
Anchorage area utilities and delivered over the SGTL to CVEA. Since it is
estimated that ML&P would provide the lowest cost power sale to CVEA, the
estimated cost of purchased power included in the analysis is based on the
provisions of the ML&P power purchase proposal described in Section 2 of this
R. W. Beck 3-5
POWER SUPPLY AND ECONOMIC ANALYSIS
report. The cost of the SGTL is based on the cost estimate included in the
Feasibility Study. It is assumed that the SGTL will be funded with the $35 million
state loan with the remainder funded with RUS loans. Following is the estimated
financing requirement of the SGTL.
TABLE 3-2
ESTIMATED FINANCING REQUIREMENT
AND SOURCES OF FUNDS FOR THE SGTL
Project Cost (1993$) $47,600
Inflation to Completion 6,200 |
Interest During Construction 1,400
Total Cost $55,200
Sources of Funds:
State Loan(1) $35,000
RUS Loan(2) 20,200
Total Financing Requirement $55,200
(1) 50-year, zero interest loan.
(2) 5 percent interest, 30-year repayment.
INTEGRATED CASE
As previously described in Section 2 of this report, an alternative SGTL case
whereby CEA bears directly the cost of the SGTL has been developed. In the
integrated case, CEA is assumed to recover the costs of the SGTL through power
sales to all of its wholesale and retail customers. In developing this case, it was
assumed that the $35 million State loan would be made available to CEA for
construction of the SGTL. Remaining costs of the SGTL would be financed with
long-term debt at an assumed 7.5% annual interest rate.
EVALUATION OF CASES AND COMPARISON OF RESULTS
Each of the two basic resource options have been evaluated to determine the cost
of power that CVEA would incur if the options were implemented. The Base
Case assumptions, which include the medium load forecast and medium fuel
escalation, have also been varied to show the impact of the assumptions on the
results of the analysis.
R. W. Beck 3-6
POWER SUPPLY AND ECONOMIC ANALYSIS
The alternative variables used in the analysis are described as follows. Unless
indicated otherwise, all variables, other than the specifically identified changed
variable for a case, remain the same as for the Base Case.
=~ =Low and High Fuel Escalation - All fuel costs are assumed to escalate at the
DOR low and high fuel cost escalation rates, respectively.
= Low Load Case - The PetroStar refinery load is assumed to be supplied by
PetroStar itself beginning in 1996. CVEA loads, excluding PetroStar, are
assumed to increase at the rate of increase in the medium load forecast
scenario. For the diesel option, all improvements and additions defined for
the Base Case are assumed to be implemented.
m= High Load Case - CVEA is assumed to sell power to the Alyeska Marine
Terminal Facility beginning in 1999. All other CVEA loads, including those of
PetroStar, are assumed to increase in accordance with the medium load
forecast. Power sales to Alyeska are assumed to be made at the average
system power sales rate. For the diesel option, this case is not considered
applicable.
= Two-year SGTL Delay - The SGTL is assumed to be delayed two years and
begin operation in 2001. Costs of the SGTL are increased to include two
additional years of inflation applied to the total construction cost. CVEA is
assumed to supply all loads prior to operation of the SGTL with its existing
resources.
m= Five-year SGTL Delay - The SGTL is assumed to be delayed five years and
begin operation in 2004. Costs of the SGTL are increased to include five
additional years of inflation applied to the total construction cost. CVEA is
assumed to supply all loads prior to operation of the SGTL with its existing
resources although two additional diesel power plant operators are assumed
to be needed in the Valdez diesel plant beginning in 1997. At the time the
SGTL becomes operational, these two operators as well as seven other
operators are to be released.
= 10% Cost Overrun - All construction costs are assumed to be increased by 10%.
The analytical model used to evaluate the alternative cases projected the total
costs of power supply for each year of a 20-year study period, 1995 through 2014.
The annual costs were then discounted to January 1995 and accumulated to
establish a single value for comparison. Another value used for comparison is the
levelized cost of power.
Figure 3-1 shows the projected annual cost of power to CVEA for the base case
diesel and SGTL options and for the CEA integration case. As can be seen in
Figure 3-1, CVEA’s cost of power in 1995 is estimated to be 8.6 cents per kWh.
R. W. Beck 3-7
POWER SupPLY AND ECONOMIC ANALYSIS
This is the cost associated with power purchases from Solomon Gulch and the
costs of fuel, operation, maintenance, depreciation and interest expense associated
with the existing diesel generators. The cost of power for the three cases diverges
slightly in 1996 with the assumed addition of a new diesel generator for the diesel
alternative. The cost of power further diverges in 1999 with the addition of the
SGTL. At that time, the cost of power for the SGTL case becomes the higher of
the three alternatives and the cost of power for the CEA integration case becomes
the lowest.
Figure 3-1 shows that, for the base case assumptions, the CEA integration case
would provide the lowest cost power to CVEA through 2014. Although the base
SGTL case would provide higher power costs than the diesel case in the first few
years of the SGTL’s operation, it crosses below the diesel case in 2004. For the
base case assumptions, the cumulative present value of the total cost of power
through 2014 is projected to be $85.1 million, $83.9 million and $78.2 million for
the diesel, SGTL and CEA integration cases, respectively. This indicates that in
present value terms, if CVEA were to construct the SGTL and purchase power
from ML&P, CVEA would save $1.2 million in power costs over the 20-year
period when compared to the diesel case. The savings over the cost of diesel
generation would increase to $6.9 million for the CEA integration case.
For the low load case where PetroStar is assumed to supply its own power
requirements beginning in 1996, the results of the analysis are shown in
Figure 3-2. As can be seen in Figure 3-2, the CEA integration case still provides
the lowest cost of power in each year of the analysis following the assumed
installation of the SGTL in 1999. The cost of power for the SGTL case is higher
than the cost of power for the diesel case until 2013 because the fixed costs of the
SGTL must be allocated over fewer kWh if PetroStar is not being served by CVEA.
In 1999, the estimated cost of power is 10.9 cents per kWh for the SGTL case
without PetroStar as compared to 9.5 cents per kWh for the SGTL case with
PetroStar. The cost of power in 1999 for the diesel case is not as drastically
affected by the loss of the PetroStar load, being 9.5 cents per kWh for the low load
case without PetroStar and 9.0 cents per kWh for the base case. For the diesel
case, CVEA would not incur as much investment in new diesel generation plant if
the PetroStar load were not served.
Because the CEA integration case assumes that the cost of the SGTL is borne by
CEA, CVEA’s power costs under this alternative are the least affected by the loss
of the PetroStar load. In 1999, the cost of power is estimated to be 8.1 cents per
kWh for the base case CEA integration case as compared to 8.5 cents per kWh if
the PetroStar load is not served. The actual impact on CEA wholesale power rates
of not serving PetroStar was not estimated as part of this study. The impact on a
cost per kWh basis is not expected to be overly significant, however.
Nevertheless, CEA should be consulted further on this matter.
R. W. Beck 3-8
POWER SUPPLY AND ECONOMIC ANALYSIS
For the low load case without PetroStar, the cumulative present value of CVEA’s
cost of power is $68.7 million, $72.3 million, and $63.0 million for the diesel, SGTL,
and CEA integration cases, respectively. For this case the cumulative present
value of the cost of power for the SGTL alternative is greater than that for the
diesel case by $3.6 million. The CEA integration case would provide savings of
$5.7 million when compared to the diesel case and $9.3 million when compared to
the SGTL case.
The 2-year and 5-year delay cases for the SGTL do not significantly affect the
resulting cost of power to CVEA. It is important to note for the delay cases,
however, that it is assumed that CVEA would hold off on any generation
improvements or additions through the entire delay period. This could result in
slight reductions in service quality and reliability to CVEA’s consumers until the
SGTL was completed. If CVEA were to construct the SGTL and could sell power
to the Alyeska terminal facility, as assumed for the high load case, CVEA’s
levelized cost of power would be approximately 1.2 cents per kWh or 12% lower
than it would be for the base case load forecast. This is because the fixed costs of
the SGTL are allocated over additional kWh sales. For the CEA integration case,
higher loads would not significantly affect the cost of power to CVEA because the
fixed costs of the SGTL are not a direct obligation of CVEA.
As can be expected, lower assumed future fuel prices lowers the estimated cost of
power to CVEA for both the diesel and SGTL cases since the cost of power
production for both cases is tied to oil prices. Higher assumed fuel prices would
increase the cost of power for both resource alternatives.
R. W. Beck 3-9
Cost of Power (cents/KWh) 14.0 ;
12.0
10.0
8.0
6.0
4.0
2.0
Figure 3-1
Projected CVEA Total Cost of Power
Base Case Resource Options
w ‘Oo wn co a SoS co Nn oO x wo xo YN eo a oO Saal N ao PH & & & F& &F& & 8 8 8 8 8B 8 8&8 & 8 & & & & 8 al Sel Sel Saal a N N N N N N N N N N N N N N N
Year
Case 1 - Base Diesel —l- Case 2 - Base SGTL —t— Case 2H - SGTL (CEA Integration)
Figure 3-2
Projected CVEA Cost of Power
Low Load Case (Less PetroStar) 14.0 4.0 (YUM%/S}Uad) 1aMOg JO }SOD 2.0 PLO e107 ZL0Z TLOZ OLOZ 6007 8007 £007 9007 S00z $007 €007 7007 1007 0007 6661 8661 2661 966T S661 Year
—*-— Case 2I - SGTL (CEA Int., Low Load) —#-SGTL — Diesel
Section 4
SUMMARY AND FURTHER CONSIDERATIONS
SUMMARY
This study had two primary components. The first dealt with the evaluation of
the two power supply proposals received by CVEA in response to its request for
proposals. The second component estimated the total cost of power that would
be incurred by CVEA over a 20-year period for alternative power supply
development options. The content of the second part of the study is typical of an
integrated resource planning study although somewhat limited in that not all
power supply and conservation options potentially available to CVEA were
investigated.
In order for CVEA to purchase power from either CEA or ML&P, the SGTL will
need to be constructed. The power supply proposals received by CVEA provide
information that was not available at the time of the SGTL Feasibility Study to
further evaluate the economic feasibility of the SGTL. Consequently, CVEA
decided to include the additional comparative evaluation of CVEA’s two primary
resource alternatives, diesel generation and power purchases over the SGTL, as
part of the overall study effort.
The power supply proposals received by CVEA from CEA and ML&P are similar
in that both would provide power for a 20-year term and CVEA would be
required to pay a demand charge and an energy charge for the amount of power
purchased. The cost of power purchased would be based on the cost of power
production (e.g., fuel and variable operations and maintenance costs) plus an
allocated share of the fixed generation costs (e.g., depreciation, interest expense,
insurance). Since both ML&P and CEA generate power with natural gas-fired
combined-cycle combustion turbines and fuel costs are comparable between the
two utilities, the energy cost component of the purchase power rate will be similar
from either CEA or ML&P. At the present time, however, CEA estimates that its
need for replacement of existing generation plant beginning in 2006 will
significantly affect its demand charge component to all of its customers, including
CVEA if CVEA were to purchase power from CEA. ML&P does not project that it
will have the same need for significant investment in its generation plant within
the 20-year contract term.
In order to directly compare the two power supply proposals, the proposals were
reviewed and standard assumptions were established from which the cost of
power to CVEA over the 20-year term could be estimated. For the most
Fae
SUMMARY AND FURTHER CONSIDERATIONS
comparable set of assumptions, it is estimated that the power supply proposal
from ML&P would result in present value savings to CVEA of $14.6 million in
total over the 20 years when compared to the proposal from CEA.
It is important to note that although both proposals state that power to be sold to
CVEA is firm, power will only be made available to CVEA by ML&P as long as
MLGP has sufficient power resources available unless CVEA reserves and pays for
a fixed amount of power. This means that ML&P’s contract does not fully meet
with CVEA’s request for a firm, net requirements, “take-and-pay” power supply.
The specific terms of any contract with CEA or ML&P would need to be
negotiated so it may be possible to establish contractual provisions that would
more fully meet with CVEA’s needs.
The evaluation of alternative power supply options determined the present value
of CVEA’s total power supply costs over the 20-year evaluation period. For the
base case assumptions of medium load growth and medium fuel price escalation,
it is estimated that if CVEA were to construct the SGTL and purchase power from
ML&P, CVEA would realize present value savings of $1.2 million in power
supply costs when compared to diesel generation. If CVEA were to lose the
PetroStar load, however, the present value power supply costs for the
SGTL/ML&P case would be $3.6 million higher than the comparable costs for the
diesel generation case. The PetroStar load is a very significant factor to the results
of the analysis.
Another case evaluated in the study was the CEA integration case whereby it was
assumed that CEA would construct the SGTL and include the costs of the SGTL as
a CEA system cost. The SGTL costs would then be borne by all CEA customers.
CEA would sell power to CVEA over the SGTL on a similar basis to power sales
CEA makes to its other wholesale customers. For the CEA integration case it is
estimated that CVEA would realize present value savings of $6.9 million in its
total power supply costs over the 20-year study period when compared to diesel
generation. The impact to CVEA of the loss of the PetroStar load would be much
less for the CEA integration case than it is estimated to be for the base SGTL case.
It is estimated that CVEA would still realize present value savings of $5.7 million
for the CEA integration case when compared to diesel generation if the PetroStar
load were not served by CVEA.
An important aspect of the CEA integration case is the impact on CEA revenue
requirements that would result from CEA incurring the cost of constructing and
operating the SGTL. For the base case load assumptions, it is estimated that CEA’s
costs to serve CVEA (which include the costs of the SGTL) would exceed the
benefits from the sale of power in all years of the analysis. Although the total cost
impacts on CEA’s total unit revenue requirement are relatively small on a cost per
kWh basis, it still may be difficult for CEA to implement the integrated case if costs
R. W. Beck 4-2
SUMMARY AND FURTHER CONSIDERATIONS
exceed benefits for more than a few years. With the CEA integration case, CEA is
assumed to take the risk associated with significant changes in CVEA’s power
requirements. If the PetroStar load were not served, CEA’s unit revenue
requirement would increase because the fixed costs of the SGTL would be
allocated over fewer kWh sales. On the other hand, if CVEA’s power
requirements were to expand as could happen if power were sold to the Alyeska
terminal facility, CEA and all of its customers would benefit from the integration
case.
FURTHER CONSIDERATIONS
As with any study of this kind, there are many other issues to consider when
reviewing the study results. In addition, during the course of the study several
issues became known that could significantly affect CVEA’s power supply
situation in the future. Principal among these issues are:
= The possibility that PetroStar may choose to develop an electrical
generating plant at its Valdez refining facility to generate power for its
own use and potentially sell power to CVEA. PetroStar has proposed to
use an off-product of its refining process to fuel a cogeneration power
plant that CVEA may be obligated to purchase power from if offered by
PetroStar.
= The possibility that the Alyeska marine terminal may want to purchase
power to supply all or a portion of its power supply needs, or conversely,
may want to sell surplus power from its generating plant to CVEA.
Alyeska recently evaluated the feasibility of using hydro-carbon vapors
recovered from tankers as a generating fuel.
= The Governor has requested an interagency review of the issues related
to the feasibility of the SGTL. The outcome of the review committee’s
investigation is not known at this time but it could have a profound
impact on CVEA’s power supply planning effort.
= The overall implications of the CEA integration case. The information
used in this study to estimate the cost impacts of the CEA integration case
was very limited. CEA indicated that it was not in a position to provide
further information at the time the study was conducted. CEA’s 1995
financial forecast should be considered in any subsequent analysis.
CEA’s position on the concept of integrated operation with CVEA should
also be further investigated, particularly with regard to recent changes on
the CEA board. In addition, possible alternative pricing structures, such
as a Copper Valley surcharge, should be discussed with CEA to
R. W. Beck 4-3
SUMMARY AND FURTHER CONSIDERATIONS
determine what impacts these alternative structures may have on the
ability of CEA to implement the integration case.
All of these issues could significantly impact CVEA’s power supply situation.
Unfortunately, many of the issues cannot be quantified for analysis at the present
time. Although CVEA may have some opportunity to influence some of the
potential outcomes, for the most part the issues are out of CVEA’s control. All of
these issues are currently ongoing and new information may be available at any
time. CVEA should continue to monitor each and all of the foregoing issues in
anticipation of additional power supply cost evaluation.
R. W. Beck 4-4