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TECHNICAL MEMORANDUM CHMHILL
Review of Environmental Impacts, Copper Valley
Intertie and Alternatives
PREPARED FOR: Dennis McCrohan/AIDEA
PREPARED BY: Dave Gray
DATE: January 22, 1996
This technical memorandum has been prepared at the request of AIDEA to address en-
vironmental issues raised during the December 1995 public meetings.
Summary
This discussion reviews the comparative environmental impacts of the proposed transmis-
sion intertie between Sutton and Glennallen and a number of potential alternatives. Five
project alternatives and a no action alternative are included. The project alternatives are:
e Intertie
e New Diesel (upgraded diesel units in Glennallen and Valdez)
¢ Hydroelectric generation at Silver Lake with supplemental diesel generation
e Hydroelectric generation at Allison Lake with supplemental diesel generation
e Coal-fired generation at Valdez
Each alternative is discussed in terms of its relative impacts on a number of elements of the
environment, as defined by the National Environmental Policy Act (NEPA). Elements cov-
ered in this discussion include visual quality, economics, protected habitats and species,
water quality, air quality, cultural resources, and social/recreational impacts. Table 1 pro-
vides a summary of potential impacts by alternative and element.
The information compiled here is drawn from three main sources: Volume 2 of the April
1994 Copper Valley Intertie Feasibility Study, the 1992 Allison Lake Reconnaissance Study,
and public comment in response to the 1995 update to the Copper Valley Intertie Feasibility
Study. These are the only documents that have focused specifically on the impacts of the in-
tertie and alternatives. Where existing documents provided little or no information on spe-
cific categories of impact (for example, economic and cultural resource issues), professional
judgment and public comment on the project were used in determining potential impacts
and issues of concern.
Both of the studies done to date were based on conceptual project designs and limited, if
any, study-area reconnaissance. The preliminary nature of the information available makes
it impossible to identify environmental “fatal flaws” at this time. However, a number of po-
tentially significant impacts can be identified that could substantially affect the cost and/or
feasibility of each of the alternatives as they are further developed.
One likely outcome of any of the alternatives is litigation over environmental and/or social
impacts. While public comment from the Matanuska Valley indicates that the visual
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TABLE 1
Comparative Impacts of Sutton-Glenallen Intertie and Altematives
Resource/Issue No Action Intertie New Diesel Silver Lake Allison Lake Valdez Coal
Visual Quality No impact Significant impact on Matanuska Potential for minor localized impacts | Changes in views resulting from Changes in views resulting from Alli- Localized impacts at generating fa-
Valley per 1994 feasibility study; reservoir creation and construction son Lake drawdown and water level _ cility, including potential emission
portions of intertie would be visible of generating facilities; no known changes in Solomon Gulch; no plume; potential for significant im-
from Lake Louise Road, trail sys- sensitive viewer groups in site known sensitive viewer groups pacts at mine site in Matanuska
tems, and recreation areas and vicinity affected Valley, including effects of coal stor-
could affect sensitive viewer groups age and truck, rail, and barge
transportation
Economics Potential for limitation of develop- Potential for negative impacts on Potential positive and negative ef- See New Diesel alternative See New Diesel alternative See New Diesel alternative; potential
Protected Species
Water Quality
Air Quality
Cultural Resources
ment in CVEA service area due to
power cost and supply issues
No impact
o
py No impact
Continued burning of diesel without
modern controls could adversely af-
fect local air quality
No impact (sates potential for archaeologi>
tourist-oriented businesses in Mata-
nuska Valley due to visual quality
changes
Potential for impacts on moose,
caribou, Dall sheep, trumpeter swan,
bald eagles, and salmonid species
resulting from intertie’s proximity to
important habitat areas and from in-
creased hunting access
auras ot I See
Erosion/sedimentation during intertie)
construction and as long-term
impact of access roads could affec!
impacts of natural gas
generation in CEA or MLP service
area as low.
Natural gas generation would result
in some emission of pollutants, pri-
marily NO; however, pollutant
emissions from diesel generation in
CVEA service area would be signifi-
cantly reduced
cal sites and disruption of resource-
based Native activities;
identified recorded siteS, but consul-
tation with Native corporations on
current activities would be required
to assess full extent of potential
impacts
fects on CVEA service area eco-
nomic development relative to
intertie
Little impact
1994 study rated water quality im-
pacts of diesel generation as
medium
Impacts of diesel generation rated
high in 1994 study, with potentially
significant emissions of sulfur ox-
ides, NO,, and CO; control technol-
ogy could result in lower emissions
than No Action alternative
Potential impact limited to area of
generating facilities
Loss of habitat for wildlife, including
productive goat and bear habitat,
during filling of reservoir; potential
impacts on pink and chum salmon in
Duck River from changes in stream
flow
Effects of streamflow changes on
existing water quality have not been
analyzed, but could be significant;
effects of potential submarine cable
construction should also be explored
Supplemental diesel generation
would have similar emission types to
those described for New Diesel al-
ternative, but overall reduced reli-
ance on diesel could result in net
emission reductions for service area
Potential for inundation of cultural
resource sites; record search and/or
survey are not known to have oc-
curred; current Native fishing and
resource activities, if any, have not
been documented
Similar to Silver Lake, with potential
for impacts on bear, goat, wolf,
wolverine, and other species; pro-
posed minimum instream flow
requirements may be insufficient to
maintain pink and chum salmon
populations; effects of Allison Lake
water turbidity on hatchery produc-
tion are a potential concern
Similar to Silver Lake; as noted
above, turbidity may be an issue
Similar to Silver Lake, except that
diesel supplementation and resulting
emissions would be somewhat
higher
Similar to Silver Lake, though im-
pacts may be less because no land
would be inundated
economic impacts of mining opera-
tions could include both long-term
employment opportunities and
negative effects on tourism/ recrea-
tion in immediate mine area
Impacts of mining on nearby habitat
have not been studied, but could be
significant
1994 study rated water quality im-
pacts of coal generation as medium;
impacts of mining operation have not
been studied, but could be signifi-
cant
Fluidized-bed technology would re-
sult in lower SO, and NO, emissions
than traditional coal plants; however,
impacts rated high in 1994 study due
to lack of specific plant information
and potential for emissions plume to
affect Class | airsheds
Impact limited for generating facility,
but potential exists for sites or cul-
tural activities in the proposed min-
ing area
$EA/1002C12A.D0C
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REVIEW OF ENVIRONMENTAL IMPACTS, COPPER VALLEY INTERTIE AND ALTERNATIVES
impacts of the intertie would be a primary target for such litigation, Silver Lake and Allison
Lake also have the potential to attract litigation based on protected species and water qual-
ity issues. Although not in itself a fatal flaw, litigation could cause sufficient delay to render
a project effectively infeasible. Other areas with the potential to cause project delay or re-
quire substantial mitigation include:
e FERC licensing requirements related to instream flow for the two hydroelectric alter-
natives
e Identification of endangered species and their habitats in the intertie or hydroelectric
project areas
e Identification of significant cultural resources at or near any of the proposed sites
e Federal requirements for air pollution control technology under the Prevention of Sig-
nificant Deterioration (PSD) program, which would likely apply to the Valdez coal al-
ternative and possibly to the new diesel generation alternative
During public comment on the intertie project, a number of commenters expressed concern
about the potential effects of electromagnetic fields (EMF) on public health in communities
near the transmission line. As described in the 1994 Feasibility Study, current research has
not shown a causal relationship between EMF and any specific disease, and EMF levels
outside the project's right-of-way are expected to be minimal. However, to address public
concerns, route alignments were cited at least 600 feet from all occupied structures when-
ever possible.
It should be noted that the majority of the available environmental data has been developed
for the intertie project, and thus the impacts of that project can be discussed in greater detail
than the impacts of the alternatives. However, each of the alternatives also has the potential
for significant adverse impacts on the natural and built environments. If power generation
alternatives are investigated further as a result of the state feasibility determination, it
should be done on the basis of consistent levels of data for each alternative studied to allow
for an objective comparison of the options. Ultimately, the preferred and secondary alterna-
tives will be analyzed in detail during the NEPA process. The analysis would include all the
elements of the environment discussed here, and potentially others identified during the
EIS scoping process.
Visual Quality
No Action Alternative
This alternative would entail the continued use of the existing CVEA diesel generation fa-
cilities in the Glennallen and Valdez areas. No visual quality impacts are associated with
this alternative.
Intertie
The Copper Valley Intertie Feasibility Study provided a preliminary assessment of the vis-
ual impacts of alternative intertie routes through the Matanuska Valley. The overall poten-
tial for visual impacts was determined to be high. Few residences would be affected, and
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REVIEW OF ENVIRONMENTAL IMPACTS, COPPER VALLEY INTERTIE AND ALTERNATIVES
siting was generally designed to minimize visibility from the Glenn Highway. However,
recreational users of areas through which the line was routed would be affected by the pres-
ence of structural elements in a largely undisturbed landscape. Transmission line structures
and access roads in any of the largely barren drainages in the Talkeetna Mountains would
cause high visual contrasts and would be difficult to screen because of the lack of forest
cover. Specific areas of likely impact would include Lake Louise Road, which serves as the
sole access to the Lake Louise recreation area, and portions of the Chickaloon-Knik-
Nelchina Trail system. Potential adverse impacts on private property could occur along the
Glenn Highway from Cascade Creek to Hicks Creek. The northernmost of the two align-
ments studied would have fewer visual impacts overall than the southern, but still would
be visible from some locations on the Glenn Highway and to backcountry users in a number
of areas.
As described in later sections of this document, a primary concern of area residents is the ef-
fect of changes in visual quality on the local economy, which is largely based on tourism-
related services that depend on the scenic quality of the environment. The 1994 study
recommended a more definitive visual impact analysis that included field verification of
sight distances from the Glenn Highway, recreation areas, and lodges. Mitigation for visual
impacts would be based on the findings of such an analysis and would likely include
changes in the alignment to provide screening from areas of sensitive viewer concentration,
as well as potential changes in materials, colors, and structural configuration of the line
itself.
New Diesel
This alternative would involve the retrofit of existing diesel facilities and/or the construc-
tion of new facilities to replace aging equipment in both Glennallen and Valdez. Because
transmission of power would take place through CVEA's existing intertie between the two
cities, visual quality impacts would be localized to the immediate vicinity of the generating
plants. To the extent that upgrades were accomplished by retrofitting of existing facilities,
impacts would be minimal. New facilities would pose the potential for impacts, although
such impacts would presumably be mitigated by siting the facilities in a location removed
from sensitive viewer groups. There is also the potential for diesel emissions to cause a
visible “ice fog” in the plant vicinity under certain atmospheric conditions (e.g., winter air
inversions) in which dispersion of emissions is limited.
Silver Lake
This alternative would involve the construction of a dam and hydroelectric generating fa-
cilities at Silver Lake, located approximately 15 miles southwest of Valdez. The lake is rela-
tively remote and currently is accessible only by air or water. Construction of the dam
would raise the level of the lake by up to 125 feet, and the powerhouse and other generating
facilities would alter the undeveloped character of the landscape. However, the lack of sig-
nificant human use of the area would minimize the project's visual effects on sensitive
viewer groups. Visual impacts of new or upgraded diesel facilities to supplement and back
up Silver Lake generation would be as described above for the new diesel alternative.
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Allison Lake
The Allison Lake project would involve the generation of hydroelectric energy at Allison
Lake, located west of the Solomon Gulch reservoir, and diversion of water through a pipe-
line or tunnel to provide additional firm generating capacity at Solomon Gulch. The project
area is owned by the State of Alaska and managed by the Alaska Department of Natural
Resources. Drawdown of Allison Lake by up to 100 feet and the deposition of tailings from
the tunnel could cause impacts on the visual quality of the natural landscape; however,
both the lake and the Solomon Gulch Reservoir can only be viewed by air, and these effects
would not be visible to the general public. Mitigation, if necessary, could be accomplished
through the revegetation of affected areas. Visual impacts of new or upgraded diesel facili-
ties to supplement and back up Allison Lake generation would be as described above for
the New Diesel alternative.
Valdez Coal
This alternative would use fluidized-bed combustion technology to generate 22 MW of
power in Valdez. In addition to electrical generation, steam from the plant would be used
for heating of public facilities. Because the plant would presumably be sited in an industrial
area, effects on sensitive viewer groups were assumed to be low in the 1994 study. How-
ever, the potential exists for an emissions plume from the facility, containing sulfur oxides,
nitrogen oxides, and particulates (see Air Quality below), that could affect scenic vistas in
nearby viewsheds. Additional information would need to be obtained on the proposed site,
process, and area meteorology to determine the true extent of the potential impact.
The other potentially significant visual quality impact associated with this alternative is the
project proponent's proposal for development of a mine site in the Matanuska Valley to
supply the required coal. The level of impact would depend on the surrounding land uses;
the proximity and accessibility of the mine site to sensitive viewer groups; the type of min-
ing operation proposed (i.e., surface versus subsurface); and the areal extent of ground dis-
turbance, processing operations, and the like. Because of the scenic qualities of the valley
and the importance of these qualities to users of the area, the potential for visual impacts is
high and is directly correlated to the intensity of the proposed mining activities. Impacts
could also occur as a result of coal storage and transportation by truck, rail, and barge. The
route currently envisioned is truck transport to Palmer with transfer to rail car between
Palmer and Whittier, then via barge to Valdez.
Economics
No Action Alternative
Public comment from the CVEA service area and discussion in the Feasibility Study and
Feasibility Study Update indicate that the cost and reliability of electrical energy are impor-
tant factors in the economic viability of communities served by CVEA. The utility is cur-
rently isolated from the regional grid, and must provide redundant generation capabilities
in Glennallen and Valdez because of the potential for transmission failures between the two
load centers. This self-sufficiency increases the cost of power to customers as well as the lo-
cal and regional impacts of generation. Although the area is poised for economic develop-
ment, power cost and reliability issues may tend to discourage such development, as
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indicated in public comments included in Volume 3 of the 1994 Feasibility Study and made
by representatives of affected recreational businesses during public meetings in December
1995. CVEA and local business groups believe that future growth in the area would be hin-
dered if sole reliance on local generation resources were to continue, and that the availabil-
ity of cost-effective Railbelt power provided by the intertie would facilitate beneficial
economic development.
No studies have been done to quantify the potential effects of alternative generation and
transmission scenarios on the economy of the CVEA service area. Such studies would re-
quire examination of existing development plans and proposals for the area, an overall as-
sessment of economic development potential, and an analysis of the sensitivity of potential
development to power cost and reliability issues. The potential adverse effects of the intertie
on the economy of Matanuska Valley communities, as discussed below, would also need to
be considered in the analysis.
Intertie
The intertie could have both positive and negative effects. Construction of the intertie, as
discussed in Volume 2 of the 1994 Feasibility Study, could result in significant local em-
ployment opportunities for Matanuska Valley Residents and increased revenue for are
service businesses (e.g., restaurants and lodging). These effects would be limited in duration
to the construction period. Long-term positive economic effects on the CVEA service area
would also be realized through the availability of plentiful, relatively low-cost power from
the regional grid. As discussed under the No Action Alternative, the existing lack of such a
supply places limitations on the area’s economic development; with the intertie, business
expansion and other development would become more attractive, resulting in the potential
for increased employment opportunities and tax revenues.
As noted above, negative long-term economic impacts of the intertie would likely be related
in large part to the project's effects on the visual quality of lands used by tourists and rec-
reationalists. Public comment on the Feasibility Study and the update indicated that busi-
nesses such as guide services and lodges, which form an important part of the economy of
Sutton, Chickaloon, and Glacier View, would experience negative impacts because the
area's desirability as a tourist destination would decrease. Respondents believed that the
visual appearance of the line and its intrusion as a manufactured structure in the natural
landscape would detract from the "wilderness experience" sought by backpackers, hunters,
and other recreationalists, who consequently would be more likely to seek this experience
in an undisturbed area.
As with the No Action alternative, no work has been done to quantify the actual likelihood
and extent of economic impacts resulting from the presence of the intertie in the Matanuska
Valley. This work would need to identify specific businesses and business types likely to be
affected because of their nature or location, and would assess relative levels of impact on
the basis of recreationalist surveys conducted in relation to similar projects. Depending on
the level and quality of data available, the assessment could results in quantitative estimates
of potential income and tax losses in the affected communities.
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New Diesel
By providing increased power generation capacity to meet projected needs, the New Diesel
alternative would help to support planned economic development in the CVEA service
area. However, the full cost of these facilities would be borne by CVEA ratepayers. This
could result in power costs high enough to limit the area's overall economic development
potential. This issue would need to be explored for any alternatives that involved continued
reliance on local generating resources without connection to the regional grid: Negative
economic effects, if any, would likely be less than with the No Action Alternative. As with
the intertie, construction of new facilities would result in potentially significant temporary
opportunities for area workers and over the long term would result in lower operating costs
than with no action.
Silver Lake
Economic effects of generation at Silver Lake would be similar to those described for the
New Diesel alternative.
Allison Lake
Economic effects of generation at Allison Lake would be similar to those described for the
New Diesel alternative.
Valdez Coal
Economic effects of coal-fired generation at Valdez would be similar to those described for
the New Diesel alternative. In addition, mining operations near Sutton could provide em-
ployment opportunities for area residents, although they might also result in negative ef-
fects on nearby businesses oriented toward tourism or recreation.
Protected Species and Habitats
No Action Alternative
No protected species or habitats would be directly affected by the No Action Alternative.
Intertie
The Matanuska Valley contains significant populations of moose, caribou, Dall sheep,
trumpeter swan, and black and brown bear. Bald eagles may also use the area. The align-
ment also crosses or passes upstream of 14 anadromous fish streams and traverses 65 miles
of wetlands listed in the National Wetlands Inventory. As discussed in the 1994 Feasibility
Study, the intertie would pass through significant habitat of most of the species noted. Po-
tential impacts would include removal of mineral licks used by Dall sheep and crossings of
moose rutting and calving areas and trumpeter swan nesting areas. Trumpeter swans, in
particular, are sensitive to the presence of powerlines and tend to collide with them, result-
ing in injury or death. Although the intertie would not physically impede wildlife move-
ment, avoidance of the disturbed area could result in changes to existing migration patterns,
particularly since a 12-foot-wide wildlife movement corridor parallels much of the
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proposed alignment. Species sensitive to the presence of humans or manmade structures
could tend to change their customary ranges or travel patterns to avoid the intertie area.
Increased access to previously undeveloped areas could increase hunting of the existing
populations of moose, the Nelchina caribou herd, dall sheep, and brown bears. The inten-
sity of any increased hunting would depend on the specific locations of proposed access
roads with respect to these animals’ habitat areas. Additional access could enable hunters
from the Anchorage metropolitan area to compete with local residents who use the area for
subsistence hunting.
Although none of the 14 anadromous streams that the intertie would cross or pass upstream
of supports large populations of anadromous fish, the 1994 Feasibility Study suggests that
even slight effects on water quality would be detrimental. Such effects could result from
erosion into streams during the intertie's construction or from erosion of soil from access
road during project operations.
Mitigation measures for fish and wildlife impacts would include both those required by
agencies with jurisdiction (for example, federal bald eagle protection requirements and
trumpeter swan protection measures specified in the Copper River Basin Area Plan) and
those that could cost-effectively be implemented to reduce impacts of concern to valley
residents, such as increased pressures on species important to subsistence hunters. Mitiga-
tion would need to be based on the relative significance of expected impacts, as determined
by calculations of habitat loss and through coordination with resource agencies and other
concerned parties (such as hunting guides and subsistence hunters).
New Diesel
It is assumed that new diesel generation facilities would be sited in an area characterized by
industrial development. No impacts on protected species or habitat are anticipated.
Silver Lake
According to the Allison Lake Reconnaissance Study, Silver Lake and the surrounding area
support a sizable goat population and are among the most popular goat hunting areas in
Prince William Sound. Black bear habitat in the region is also rated good to excellent, with
bear feeding on the salmon that spawn in the area. Deer are few in the area, and waterfowl
use is not extensive. The Duck River (Silver Lake’s outlet stream) and the surrounding la-
goon area are reported to be one of the most productive regions in Prince William Sound for
pink salmon. Pink salmon escapement has been estimated to average around 51,000 per
year. Chum salmon and Dolly Varden are also abundant in the area. Salmon spawning beds
have been identified in the Duck River, The Lagoon, Reverse Creek, and a number of other
small tributaries in the area.
There would be a loss of habitat associated the Silver Lake project due to the raising of the
lake elevation by 100 feet, increasing the surface area by about 600 acres. Effects on wildlife
habitat have not been studied; what is known is that access and exposure to the region, and
therefore potential pressure on animal populations, will be increased with any development
in the area.
Development of a hydroelectric project at Silver Lake will raise the issue of minimum in-
stream flow requirements on the Duck River, which could have an effect on salmon
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production in the region. Two potential locations on the river have been identified for the
powerhouse, one at elevation 35 and one at elevation 65. The higher-elevation site is located
above what is reported to be an impassable fish barrier, while the lower-elevation site is
downstream of the barrier location. With either site, flows in the bypass reach would be
reduced under the developer’s proposal to approximately 5 cubic feet per second (cfs).
Although the project proponent has contended that most salmonid spawning takes place in
Bennett Creek, which flows into the river downstream of the lower powerhouse site, no in-
formation is currently available to support this contention. Discussions with the Alaska
Department of Fish and Game indicate that a level of between 100 and 200 cfs during the
summer months would be required to maintain salmon runs in the river. The spilling of
larger volumes of water than initially anticipated would reduce the generating capacity of
the project during the period when higher flows were required. The overall effect of esti-
mated instream flow requirements on the power supply and economic aspects of the Silver
Lake project are discussed in CH2M HILL’s January 29, 1996 technical memorandum en-
titled “Cost Estimates and Risk Analysis for Copper Valley Intertie and Alternatives.”
Another area of potential concern for fisheries resources is the control of water tem-
peratures in the Duck River during the early part of the winter, which is essential to prevent
premature hatching of salmonid eggs. To allow temperature control, the reservoir outlet
structure could be designed to allow water to be taken from the lake at varying levels. This
design is factored into the Silver Lake estimate included in the “Cost Estimates and Risk
Analysis” memorandum.
Two options are under study to deliver electricity from Silver Lake to Valdez: a 22-mile
overhead transmission line, or a 2.2-mile transmission line connecting to an 18-mile subma-
rine cable beneath Prince William Sound. The 22-mile overhead route would have similar
potential effects to the intertie in terms of wildlife and habitat, although over a shorter cor-
ridor. The submarine cable could result in temporary water quality impacts during con-
struction that would have the potential to affect marine life. No detailed study has been
done on the potential impacts of these transmission facilities.
Allison Lake
Wildlife species in the Allison Lake area include brown bear, black bear, mountain goat,
wolf, wolverine, marten, porcupine, and snowshoe hare. Wildlife surveys conducted by
ADFG in 1978 for the Solomon Gulch Hydroelectric Project FEIS indicated that the Solomon
Creek drainage provides relatively good habitat for black bear and that the coastal area is
prime habitat. The Allison Creek drainage habitat is similar to that of the Solomon drainage
and likely supports similar wildlife; according to the 1981 COE Feasibility Report, the most
commonly observed mammal near the proposed Allison Creek site is black bear. The closest
known bald eagle nests to the site are located near Lowe River, approximately 3 miles from
the project area. According to the USFWS, there are no other known endangered or threat-
ened species of flora and fauna in the study area.
According to the Alaska Department of Fish and Game (ADFG), much intertidal spawning
by pink and chum salmon takes place in the sand, gravel, and/or silt fans present at the
mouths of many area streams, including Solomon Creek and Allison Creek. Some dis-
agreement exists on exactly where spawning occurs; discussions with ADFG for the Allison
Lake Reconnaissance Study indicated that spawning may occur as far as 1 mile up Allison
Creek, while other sources suggest that spawning occurs 1.5 miles below the outlet of
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Allison Lake. In addition, the 1981 COE Feasibility Report states that spawning occurs only
1/4 mile from the mouth of Allison Creek.
As noted above for Silver Lake, reduced flows in Allison Creek during periods of water di-
version could affect spawning areas and overall fish populations in the creek. Comments
from resource agencies on the Allison Lake Reconnaissance Study indicated concern that
minimum instream flow requirements used to estimate generating capacity were not suf-
ficient to ensure the viability of fisheries resources. Concern has also been expressed by the
Solomon Gulch Hatchery, downstream of the reservoir, that introduction of Allison Lake
waters could result in unacceptably high turbidity or the introduction of disease-carrying
organisms. However, available data do not support this concern, according to the 1994
Feasibility Study.
Valdez Coal
Because the coal generation facility in Valdez is expected to be located in an industrial area,
it would not be likely to affect animals or their habitat. However, the proposed mine near
Sutton would have the potential to result in adverse effects on these resources. As discussed
above under Visual Quality, the extent of such effects would depend upon the size and
location of the mine, the mining methods employed, and other factors. Insufficient infor-
mation is available to determine the level of impact at this time.
Water Quality
No Action
No impacts on water quality would occur as a result of the No Action alternative.
Intertie
The intertie project would involve electrical generation using natural gas to meet CVEA
demand. Natural gas generation would occur within the service area of the Chugach Elec-
tric Association (CEA) or Matanuska Light and Power (MLP). The 1994 Feasibility Study
evaluated the relative water quality impacts of natural gas and coal generation facilities
over their respective life cycles, calculating these impacts on a basis of quantity per average
megawatt per year. The evaluation was based primarily on generic information available on
the types of generation facilities being evaluated. Natural gas generation assumed for the
intertie was concluded, on the basis of this information, to have a low level of environ-
mental effects. Water consumption per average megawatt per year was estimated at 8.4
acre-feet, thermal discharge at 28,800 MMBtu, and total suspended solids at 1.14 tons. Other
categories of discharges evaluated were not consistent between the two alternatives and do
not lend themselves to a comparative analysis.
Water quality effects of the intertie itself would be related to the potential for erosion of soil
and other materials into nearby surface waters during project construction and operation.
As discussed above under Protected Species and Habitats, even small effects on water
quality could affect salmonid species in project-area streams. An estimate of the total acre-
age disturbed during construction and the length, location, and composition of access roads
would be required to assess the relative significance of potential impacts. Best management
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practices for erosion control, such as silt fences, temporary sedimentation basins, and timely
revegetation of disturbed areas, could be used to minimize the effects of construction on
streams.
New Diesel
The discussion of water quality impacts for diesel generation in the 1994 Feasibility Study
did not include quantitative estimates of life-cycle effects. Potential impacts cited included
adverse effects of cooling water discharges on biochemical oxygen demand, chemical oxy-
gen demand, total suspended and dissolved solids, ammonia, and thermal discharges,
which could affect fisheries resources in receiving waters. The overall water quality effects
of diesel generation were estimated to be of a medium level.
Silver Lake
Water quality impacts on Silver Lake were not specifically discussed in the Allison Lake Re-
connaissance Study. Likely sources of potential impact would include erosion and sedimen-
tation during construction and the effects of reduced stream flow on Duck River,
particularly the potential for increased summer temperatures and resulting reductions in
dissolved oxygen concentrations.
Allison Lake
Potential water quality impacts of the Allison Lake project would include those described
above for Silver Lake. In addition, the effects of mixing Allison Lake and Solomon Gulch
Reservoir waters were discussed in the 1994 Feasibility Study. Information collected by the
U.S. Army Corps of Engineers in 1979 indicated that Allison Lake water met all state and
federal surface water quality standards for physical, chemical, and biological parameters.
As noted above, representatives of the Solomon Gulch Hatchery have expressed concern
about the potential for disease-causing organisms or unacceptable turbidity in Allison Lake
water; however, according to the Feasibility Study, such effects are not anticipated.
The impacts of supplemental diesel generation would be as discussed above for the New
Diesel alternative, but would occur on a smaller scale because the amount of diesel genera-
tion required would be less.
Valdez Coal
Life-cycle water quality effects of coal generation were rated as “medium” in the 1994
Feasibility Study on the basis of generic information for coal-fired facilities. Water con-
sumption per average megawatt per year was estimated at 17.4 acre-feet, thermal discharge
at 44,200 MMBtu, and total suspended solids at 0.063 ton. Other discharges into receiving
waters would include relatively minor amounts of oil and grease, chloride, iron, and
copper.
1002C112.D0C 1
REVIEW OF ENVIRONMENTAL IMPACTS, COPPER VALLEY INTERTIE AND ALTERNATIVES
Air Quality
No Action
Assuming that current levels of power production were maintained at the existing diesel
facilities, air quality would remain similar to existing conditions. It should be noted, how-
ever, that the existing facilities likely have higher levels of emissions per kilowatt hour than
facilities using newer combustion technology and pollutant controls.
Intertie
The 1994 Feasibility Study assessed the air quality impacts of the proposed natural gas gen-
eration facility in the CEA or MLP service areas as low, based on the clean-burning quality
of natural gas combustion turbines. The primary air quality concern would be NOx emis-
sions, which tend to be a problem because of high combustion temperatures. NOx emis-
sions are typically controlled through the injection of water or steam into the CT combustor,
which can reduce emissions by up to 80 percent. The appropriate control technology to
safeguard environmental quality is determined during permitting, which would be admin-
istered by the Alaska Department of Environmental Quality (ADEC). Table 2 shows the
Feasibility Study estimates of fuel-cycle air pollutant emissions, based on a GE Frame 7
combined-cycle unit.
TABLE 2
Air Quality Impacts of Natural Gas Generation
Generation
Gas Extraction Transportation (Ib/kWh and
Pollutant (tons/MW/year) (tons/MW/year) tons/MW/year)
Sulfur Oxides 94.600 0.0004 0.0000089
2.80
Oxides of Nitrogen 5.630 0.266 0.0011
0.04
Particulates 0.126 0.000064
2.33
Carbon Dioxide 0.00032
4,174.00
Volatile Organic Com- 0.00011
pounds
Source: Copper Valley Intertie Feasibility Study, April 1994.
In addition to its relatively low impact on air quality in the area where the natural gas tur-
bine is sited, the intertie project would improve air quality in the CVEA service area
through reductions in diesel generation and the consequent emissions. These reductions
have not been quantified in existing studies of the project.
1002C112.D0C
REVIEW OF ENVIRONMENTAL IMPACTS, COPPER VALLEY INTERTIE AND ALTERNATIVES
New Diesel
Air quality impacts of new diesel facilities in the Copper Valley service area were rated high
in the 1994 Feasibility Study, based on similar analyses of alternative sources of generation.
Diesel generation would result in potentially significant emissions of sulfur oxides, oxides
of nitrogen, and carbon dioxide. Mitigation of NOx would be accomplished in the same
manner as for natural gas generation; sulfur oxides would be controlled through the use of
scrubbers. The level of control required would depend upon estimated emissions levels; any
federally designated “criteria pollutant” emission of over 250 tons per year could be subject
to the Prevention of Significant Deterioration permitting process, administered by ADEC,
which specifies stricter controls to limit emissions. Table 3 shows the Feasibility Study esti-
mates of pollutant emissions during generation in pounds per kilowatt-hour for two models
of diesel engines. Emissions associated with resource extraction and transportation are as-
sumed to be the same as for natural gas generation.
TABLE 3
Air Quality Impacts of Diesel Generation
Pollutant DE R-46 (Ib/kWH) CAT 3608 (Ib/kWh)
Oxides of Nitrogen 0.3800 0.0220
Carbon Monoxide 0.00510 0.0049
Particulates 0.00015 0.0019
Volatile Organic Compounds 0.00098 0.0025
Sulfur Oxides 0.00460 0.0046
Source: Copper Valley Intertie Feasibility Study, April 1994.
Silver Lake
Air quality impacts associated with the Silver Lake project would be limited to those related
to supplemental diesel generation. Such impacts would be similar to those described above
for the New Diesel alternative, but would be proportionately less because of the lower gen-
eration requirements. In addition, by reducing the overall need for diesel generation in the CVEA service area, the project would result in reduced emissions from the existing facili-
ties. The net effect of the project on diesel emissions in the service area has not been calcu-
lated as part of the studies done to date.
Allison Lake
Impacts for the Allison Lake project would be similar to those for Silver Lake. Because Alli-
son Lake’s total hydroelectric generating capacity is lower, however, diesel use and the re-
sulting air quality impacts would be higher than for Silver Lake.
1002C112.D0C 13
REVIEW OF ENVIRONMENTAL IMPACTS, COPPER VALLEY INTERTIE AND ALTERNATIVES:
Valdez Coal
As described in the Feasibility Study, the fluidized-bed combustion technology proposed
for the Valdez coal project would result in substantially lower NOx and SOx emissions than
for conventional coal-fired facilities. However, because no information specific to the pro-
posed facility was available, it could not be confirmed that the plant’s emissions plume
would not cause adverse effects on nearby Class I airsheds. This uncertainty resulted in the
assignment of a high impact rating to the coal facility. Table 4 shows the estimated air
emissions per average megawatt per year, based on generic information on the atmospheric
fluidized-bed combustion process.
TABLE 4
Air Quality Impacts of Coal Generation
Pollutant Mining and Processing Transportation Generation
(MW/year) (MW/year) (MW/year)
SO, (tons) 0.009 0.14 1.8
NOx (tons) 0.140 0.128 15.3
Particulates (tons) 0.007 4.08 1.6
CO, (tons) 9,313.0
CO (tons) 0.028 0.189 1.54
Fugitive Dust (tons) 0.020 12.0
Heavy Metals (Ib) 2.8
Radium 226 (curies) 0.000004
Methane (tons) 7.01
Source: Copper Valley Intertie Feasibility Study. April 1994.
Cultural Resources
No Action
No impacts on cultural resources would result from the No Action alternative.
Intertie
Although the Matanuska Valley Moose Range (MVMR) had not been completely surveyed
for cultural resources as of the publication of the 1994 Feasibility Study, the Alaska Heritage
Resources Survey had recorded eleven cultural resources within the MVMR at that time,
including Native grave sites, bridges, and mines. Numerous abandoned mines are present
in the MVMR, including the National Register of Historic Places-eligible Eska Mine. The
MVMR Management Plan lists the Chickaloon River Trail, the Chickaloon-Knik-Nelchina
Trail, the Boulder Creek Trail, and the Old 98 Trail as trails with historical value. Areas with
1002C112.D0C 14
REVIEW OF ENVIRONMENTAL IMPACTS, COPPER VALLEY INTERTIE AND ALTERNATIVES
a high potential for cultural value are present along the southern portion of the Kings River,
the Chickaloon River and Boulder Creek. As of 1993, the Matanuska-Susitna Borough had a
federal preservation grant to identify and evaluate historic sites on portions of the Chicka-
loon-Knik-Nelchina Trail.
Several Native village corporations own land or have selected land within the project area
under the Alaska Native Claims Settlement Act of 1971. The proposed routes pass through
lands owned by the Cook Inlet Regional Incorporated (CIRI), the Chickaloon Moose Creek
Native Association (CMCNA), the Tazlina Village Corporation and the Ahtna Regional
Corporation. At one of the public meetings held in 1993, representatives of the Chickaloon
Village Traditional Council stated that their lands were not accurately depicted on a project
land-status map. As of 1993, few if any consultations with tribal stakeholders had been
conducted. As noted above, lands in the Matanuska Valley are reported to be in current use
for subsistence hunting; presumably some portion of this hunting is done by Native resi-
dents.
Because of the need for federal permits and land crossing approvals, the project would re-
quire compliance with Section 106 of the Historic Preservation Act and related statutes.
Dames & Moore, in consultation with the State Office of History and Archaeology at a
March 1993 agency meeting, determined that the potential transmission line routes had not
been surveyed and that an archaeological survey would need to be done if the project were
to proceed to completion. An ethnographic survey may also be required if Native properties
are affected.
New Diesel
The potential for impacts on cultural resources under this alternative would be limited to
the discovery of a previously unidentified historic or prehistoric site during construction of
diesel generation facilities. Since facilities are assumed to be sited in developed industrial
areas, this potential is not considered significant.
Silver Lake
The potential exists for cultural resource sites to be inundated during filling of the Silver
Lake reservoir or disturbed by construction of generating facilities. Available information
does not indicate whether records searches or surveys for cultural resources have been
completed for the Silver Lake site. It is likely that both would be required for compliance
with Section 106 as a prerequisite to obtaining federal licenses for the project. In addition,
Native corporations would need to be contacted to discuss the potential for resources and
any traditional uses of the area.
Allison Lake
As with Silver Lake, it is not known whether cultural resource records searches or surveys
have been done in conjunction with project proposals. Because the lake would be drawn
down rather that dammed, no sites would be inundated; construction of generating facili-
ties and/or excavation of the tunnel to Solomon Gulch could encounter previously undis-
covered resources. Section 106 compliance would minimize the potential for adverse
impacts.
1002C112.D0C 15
REVIEW OF ENVIRONMENTAL IMPACTS, COPPER VALLEY INTERTIE AND ALTERNATIVES
Valdez Coal
Impacts for the coal-fired generating facility would be similar to those of diesel generation
and are expected to be minimal. The mining operation could affect cultural resources
and/or current cultural activities of Native people, depending upon its location and extent.
Further information would be needed on the proposed mine to determine the actual poten-
tial for impacts.
SEA/1002C112.DOC
1002C112.D0C 16
TECHNICAL MEMORANDUM
Copper Valley Intertie Power Flow
PREPARED FOR: Dennis McCrohan Blaske tndustiiet Development and GtBSHt, ; PREPARED BY: Dave Gray il Autboti
DATE: January 28, 1996
At your request, CH2M HILL has reviewed power flow limitations, by direction of flow, on
the proposed Copper Valley Intertie. This memorandum briefly presents the findings from
this review.
Power Flow Limitations
The current design criteria for the Copper Valley Intertie (from Sutton to Glennallen) is
based on the transmission of about 15 MW from generating utilities in the Railbelt to serve
loads of the Copper Valley Electric Association (CVEA), primarily in Glennallen and
Valdez. The 15-MW capacity limitation is imposed by the design of the Railbelt
transmission network, not the Intertie. This transmission capacity will meet CVEA’s
present load and allow for some load growth.
The Copper Valley Intertie Feasibility Study, completed by R.W. Beck in April 1994 included a
detailed transmission system electrical analysis that identified this limitation. This analysis
concluded that under certain abnormal conditions on the Chugach Electric Association
(CEA) transmission system, CVEA loads greater than about 15 MW will cause
unacceptably low voltage conditions on parts of the CEA and Matanuska Electric
Association (MEA) 115-kV systems. These abnormal conditions could include line outages
for emergencies or for maintenance. In planning for these conditions, CVEA would have
three options: (1) it could limit Intertie loads to 15 MW; (2) it could allow for its connection
to the Intertie to be severed from the Railbelt grid when loads reach 15 MW, or (3) it could
install and operate Static VAR Compensators (SVC) at one or both ends of the Intertie.
With the addition of one or more SVC’s, power flow beyond the 15 MW limit is possible.
The SVC is a high-voltage, high-speed, solid-state switching device that can manipulate the
power factor of the transmission line load, and thus control the transmission voltage.
SVC’s are both complicated and expensive, and are usually installed in specially designed
substation buildings where operation and maintenance conditions can be controlled.
CVEA has opted to keep its loads on the Intertie below 15 MW and allow for its connection
to be severed from the Railbelt grid if its loads surpass the 15 MW limit. Historically this
has been a common practice among Railbelt utilities. Once CVEA loads require that CVEA
take more than 15 MW over the Intertie, it may install the SVC (and pay for it with
revenues from the new load requirements). On the other hand, by the time loads on the
Intertie reach this level, transmission conditions on the CEA system may have changed and
no longer cause the need for SVC on the Intertie.
cvo 1 117526.C0.10
COPPER VALLEY INTERTIE
Reverse Power Flow
The Copper Valley Intertie could transmit power in either direction. While the power flow
capacity from Sutton to Glennallen was established in the Copper Valley Intertie Feasibility
Study, the capacity of a reverse flow from Glennallen to Sutton has not been established. A
power flow study would be needed to establish the exact reverse power flow limitations
with and without SVC.
However, it is likely that the reverse flow capacity without SVC will be at least equal to the
15 MW for flows from Sutton to Glennallen. In fact, the reverse flow capacity may well be significantly greater than 15 MW because power flowing into the Railbelt would support
voltage on the Railbelt transmission grid.
While substantial reverse flow capacity would exist on the Intertie, it is not likely to be used
for the foreseeable future. As stated in the Copper Valley Intertie Feasibility Update completed
by CH2M HILL in November, 1995, there is little market opportunity for reverse flows on
the Intertie. Given the substantial surplus of low-cost gas-fired generation in the Railbelt,
there would not be opportunity to market energy priced above 3 to 4 cents per kWh. As
indicated in the Copper Valley Intertie Feasibility Update, there are not any identified
generation projects in or near the CVEA system with costs as low as in this range.
cvo 2
TECHNICAL MEMORANDUM CRMHILL
Projected CVEA Cost of Power Assuming State Loan
Is Available for Any New Power Supply Alternative
PREPARED FOR: Dennis McCrohan
PREPARED BY: Dave Gray
DATE: January 29, 1996
Summary
At your request, CH2M HILL has calculated the projected cost of power for CVEA under
the hypothetical condition that the $35 million, interest-free State of Alaska loan for the
Copper Valley Intertie could be reappropriated for construction of an alternative power
supply project. Use of loan proceeds for projects other than the Intertie is not allowed by
the enabling legislation for the loan, but analysis of the effect of reappropriation may be
helpful in deliberations on the feasibility of power supply alternatives for CVEA.
As shown in Table 1 and Figures 1 through 4, the 80/20 Integrated Intertie produces the
lowest cost of power for CVEA regardless of whether the State loan could be used for
alternative projects.
TABLE 1
CVEA Cost of Power' for Power Supply Altematives: State Funding for Intertie Only Vs. For Any Alternative
(Levelized Cents per kWh, 1999-2013)
Low Fuel Cost Forecast High Fuel Cost Forecast
Loan for Intertie Only Loan for Any Alternative Loan for Intertie Only Loan for Any Alternative
Difference Difference Difference Difference
Costper from80/20 Costper from80/20 Costper from 80/20 Costper from 80/20
Alternative kWh Intertie kWh Intertie kWh Intertle kWh Intertie
1994 All Diesel 11.24 2.00 10.82 1.58 11.71 2.32 11.29 1.90
Modified 1995 All Diesel 10.38 1.14 10.23 0.99 10.91 1.52 10.76 1.37
Intertie 10.09 0.85 10.09 0.85 10.31 0.92 10.31 0.92
80/20 Integrated Intertie 9.24 0.00 9.24 0.00 9.39 0.00 9.39 0.00
Allison Lake* na na 10.63 1.39 na na 10.81 1.42
Silver Lake Option A na na 10.78 1.54 na na 10.82 1.43
Silver Lake Option C na na 9.59 0.35 na na 9.63 0.24
Silver Lake Option C-- na na 9.92 0.68 na na 10.01 0.62
Adjusted®
‘Based on Medium-High/Medium-Low load forecast.
“Includes generation charge of 6.4 cents per kWh for generation at Solomon Gulch.
“Adjusted for probability that generation will be reduced by 15 percent to maintain adequate in-stream flows during pink
salmon spawning season.
SEA/$35MILL.DOC 1
PROJECTED CVEA COST OF POWER ASSUMING STATE LOAN IS AVAILABLE FOR ANY NEW POWER SUPPLY ALTERNATIVE
Analysis
CVEA’s cost of power was calculated for the following alternatives under the assumption
that the $35 million State loan would be available for the capital cost of any power supply
alternative:
1994 All Diesel
Modified 1995 All Diesel
Intertie (with sole financial responsibility by CVEA)
80/20 Integrated Intertie
Allison Lake
Silver Lake Option A
Silver Lake Option C
The definition of each of these alternatives, except for Silver Lake Option C, is included in
the Copper Valley Intertie Feasibility Study Update (November 1995); these definitions are
not repeated here. Silver Lake Option C is based on a design concept developed by White-
water Engineering in November, 1995; it is discussed in CH2M HILL’s technical memo-
randum on cost estimates and risk analysis for the Copper Valley Intertie and alternatives
(January 29, 1996).
Consistent with the Intertie Feasibility Update, CVEA’s cost of power for each alternative
was projected for the 15-year period of 1999 through 2013. This analysis was limited to
conditions assumed for the medium-high and medium-low forecasts of CVEA loads. How-
ever, analysis was conducted to test the cost of power under both high and low fuel price
forecasts. Also like the Intertie Feasibility Update, the cost of power calculations associated
with each alternative include all generation and purchased power costs projected to be in-
curred by the utility. By taking all costs into account, differences among alternatives can be
directly translated into differences in CVEA rates.
As noted above, results of the calculations are shown in Table 1 and Figures 1 through 4.
As shown, the 80/20 Integrated Intertie alternative produces the lowest cost of power for
CVEA regardless of whether the state loan could be used for alternative projects. With the
state loan limited to the Intertie only, the 80/20 Integrated Intertie would result in a cost of
power ranging from 1.1 to 2.3 cents per kWh less expensive than the All Diesel alternatives
shown in the table. If the state loan were available for any power supply alternative, the
80/20 Integrated Intertie would range from 1.0 to 1.9 cents per kWh less expensive than
these All Diesel alternatives. As noted above, these calculations are based on the assump-
tion that the loan would be available only for capital investment in new plant and equip-
ment. Since the investment in diesel generation is relatively low ($12 million every 20 years
in the 1994 All Diesel alternative), the availability of the state loan for this alternative has
less of an impact on the associated cost of power for CVEA it does for other alternatives.
Even if the state loan were available for the Allison Lake alternative, its associated cost of
power would be 1.4 cents per kWh higher than that for the 80/20 Integrated Intertie. A
contributing factor to this relatively large difference is the generation charge of 6.4 cents per
kWh for the portion (about half) of generation that would occur at Solomon Gulch with this
alternative.
SEA/$35MILL.DOC 2
PROJECTED CVEA COST OF POWER ASSUMING STATE LOAN IS AVAILABLE FOR ANY NEW POWER SUPPLY ALTERNATIVE
Silver Lake Option A is the same alternative evaluated in the Intertie Feasibility Update.
Even with the state loan, CVEA’s cost of power with this alternative would be 1.4 to 1.5
cents per kWh more expensive than with the 80/20 Integrated Intertie.
Silver Lake Option C is a relatively low cost design for this alternative. However, in-stream
flow requirements from regulatory agencies are likely to result in a 10 to 20 percent
reduction in useful generation capability of the project. This is discussed in more detail in
CH2M HILL’s January 22, 1996 technical memo on the environmental effects of the Copper
Valley Intertie and alternatives and in CH2M HILL’s January 29 technical memorandum on
cost estimates and risk analysis for the Copper Valley Intertie and alternatives.
Figures 1 and 2 show CVEA’s projected cost of power if in-stream flows are not restricted
and if the state loan were available for the Silver Lake Option C project. The associated cost
of power would be only 0.2 to 0.4 cents per kWh higher than that with the 80/20 Integrated
Intertie. Most of the difference would occur in the first 6 years of Intertie operation (1999-
2005). Thereafter, the cost of power with the Intertie or Silver Lake Option C would be
roughly equivalent.
Figures 3 and 4 show CVEA’s projected cost of power if in-stream flow requirements result
in a 15 percent reduction in useful power generation from the Silver Lake Option C project.
Under these circumstances, the associated cost of power would be 0.6 to 0.7 cents per kWh
higher than that with the 80/20 Integrated Intertie.
SEA/$35MILL.DOC 3
Cost of Power (cents/kWh) Figure 1
Projected CVEA Cost of Power
Assuming a State Loan for the Capital Cost
of Any New Power Supply Alternative
14.0 +— ee eee >> Low Fuel Cost _--
12.0 +
10.0 4
@ ° 6.0 4
4.0 5
2.0
0.0 4 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Year
—— 1994 All Diesel —— Allison Lake —— Modified '95 All Diesel —— Silver Lake (Option A _.. Intertie —— Silver Lake (Option C —— 80/20 Integrated Intertie
Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period.
(2) Assumes Medium-High/Medium-Low Load Forecast.
Cost of Power (cents/kWh) Figure 1
Projected CVEA Cost of Power
Assuming a State Loan for the Capital Cost
of Any New Power Supply Alternative
90 pt Low Fuel Cost --
12.0 4
10.0 +
8.0 4
6.0 4
4.0 4
2.0 + | |
} i i |
i 0.0 - + + + + + 4 + + + ++
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Year
—— 1994 All Diesel —— Allison Lake — Modified '95 All Diesel —— Silver Lake (Option A ~~ Intertie —— Silver Lake (Option C —— 80/20 Integrated Intertie
Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period.
(2) Assumes Medium-High/Medium-Low Load Forecast.
Cost of Power (cents/kWh) Figure 2
Projected CVEA Cost of Power
Assuming a State Loan for the Capital Cost
of Any New Power Supply Alternative
440 High Fuel Cost
12.0 +
10.0 +
8.0 4
6.0 4
40 4
2.0 |
0.0 + + + + + + + + + + + + + + + + + | 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Year
—— 1994 All Diesel —— Allison Lake — Modified '95 All Diesel —— Silver Lake (Option A ~~ Intertie —— Silver Lake (Option —— 80/20 Integrated Intertie
Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period.
(2) Assumes Medium-High/Medium-Low Load Forecast.
Cost of Power (cents/kWh) 14.0 7-—~
12.0 4
10.0 4
8.0 4
6.0 4
4.0 4
2.0 4 0.0 +
1995
Figure 3
Projected CVEA Cost of Power
Assuming a State Loan for the Capital Cost
of Any New Power Supply Alternative
(tt Low Fuel Cost & Adjusted Silver Lake Generation -- 0
i | | i
|
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Year
—— 1994 All Diesel —— Allison Lake — Modified '95 All Diesel —— Silver Lake (Option A ~~ Intertie —— Silver Lake (Option C —— 80/20 Integrated Intertie
Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period.
(2) Assumes Medium-High/Medium-Low Load Forecast.
Cost of Power (cents/kWh) 14.0 +—-
12.0 4
10.0 +
8.0 4
6.0 +
4.0 4
2.0 4 0.0
1995
Figure 4
Projected CVEA Cost of Power
Assuming a State Loan for the Capital Cost
of Any New Power Supply Alternative
o_o High Fuel Cost & Adjusted Silver Lake Generation --.
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
+. +
Year
—— 1994 All Diesel —— Allison Lake — Modified '95 All Diesel —— Silver Lake (Option 3 ~~ Intertie —— Silver Lake (Option C —— 80/20 Integrated Intertie
Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period.
(2) Assumes Medium-High/Medium-Low Load Forecast.
2012 2013 2014
AIDEA
ALASKA INDUSTRIAL DEVELOPMENT & EXPORT
AUTHORIY
INTERNAL MEMORANDUM
TO: Riley Snell
FROM: paid Glomons
DATE: January 31, 1996
RE: Sutton Glennallen Intertie
cc: Dennis McCrohan
You requested that I address the criticism of the Sutton Glennallen Working Groups
recommendation that a 10 year credit enhanced commitment by Petro Star Valdez (PSV)
to remain a customer of CVEA was not a sufficient period of time to protect CEA and
CVEA ratepayers if the Intertie was constructed.
According to CH2M Hill, a 20 year take or pay obligation would provide the assurance
critics are suggesting is needed. “In order to obtain a 20 year take or pay, CVEA would
need to commit to a power sales rate that is lower than that needed to secure a 10 year
take or pay commitment. The underlying issue is risk management. Ifa 20 year
arrangement is needed to significantly reduce risk (or perceived risk), then less of the
‘rewards’ from the Intertie will remain with CVEA (and its other customers) because a
lower rate would be needed to entice Petro Star to make such a commitment. If CVEA
and its customers can live with a higher level of risk, a greater reward is potentially
achievable to CVEA.” The bottom line is that a long term agreement will lock the parties
into a set rate. The longer the period, the lower the rate. From CVEA’s standpoint, as
their costs rise they will not be able to pass increases on to PSV. Their upfront risks
maybe reduced, but they could likely pay for it in the future.
Even though they are projected to remain a customer through 2018 under the medium-low
forecast, a 20 year take or pay commitment may be unreasonable from PSVs’ perspective.
It is likely that they would consider such a commitment to be too risky for a full take or
pay commitment in light of refinery economics and their current supply contracts with the
North Slope producers.
CVEA is using a take or pay contract to seek assurance that their investment in the
Intertie would be covered. CH2M Hill has suggested an alternative to a take or pay
commitment that may help reduce risk for both PSV and CVEA. They suggest that rather
than attempting to cover Intertie investment costs with take or pay provisions that also
cover variable costs not actually incurred if PSV leaves the CVEA system, CVEA could
require payment of a fixed demand charge that covers PSV prorata share of the Intertie
costs (energy charges to PSV would be reduced proportionately). Under these conditions,
PSV would need only commit to a 20 year take or pay for the demand charge. Such a
commitment could be reduced if other loads in the CVEA service area grow at rates
higher than projected and thereby cover CVEA’s implicit investment in the Intertie. Such
an arrangement may be more attractive to both PSV and CVEA.
There are other factors that should also be considered. If CVEA signed a 10 year take or
pay contract with PSV, it is unlikely PSV would leave the system after that period of time
to self generate power. PSV probably could not generate power at a lower cost than that
provided by the Intertie. Additionally, a 10 year take or pay contract takes them out until
the year 2009. Ifthe oil pipeline shuts down in 2018 as forecasted in the medium-low
scenario, they would have only 9 years to depreciate their capital investment. This may be
too short of a period to adequately recover their investment.
Finally, if the Intertie is not constructed, losing PSV as a customer will have a negative
impact on CVEA ratepayers. Currently, CH2M Hill calculates that rates would increase
by 1.5 cents per Kwh. Therefore, losing PSV could further exasterbate the ratepayers
situation.
TECHNICAL MEMORANDUM CHMHILL
Cost Estimates and Risk Analysis for Copper Valley
Intertie and Alternatives
PREPARED FOR: Dennis McCrohan
PREPARED BY: Dave Gray
DATE: January 29, 1996
Summary
This memorandum presents 1) CH2M HILL’s analysis of cost estimates for the Copper
Valley Intertie and other power supply alternatives for Copper Valley Electric Association.
(CVEA), and 2) risk assessment of the least cost alternatives and analysis of the potential
impact of these risks on project cost and schedule for these alternatives. The power supply
alternatives are:
e All Diesel generation (including the “1994 All Diesel” and the “Modified 1995”
alternatives)
e Intertie to natural gas generation in Alaska’s Railbelt region
e Allison Lake hydroelectric generation
e Silver Lake hydroelectric generation
¢ Valdez Coal cogeneration
Cost Estimates
Construction cost estimates for each alternative and operation and maintenance (O&M) cost
estimates for one alternative with relatively high O&M costs (the All Diesel alternative)
were evaluated. The cost estimates evaluated were presented in the Copper Valley Intertie
Feasibility Study completed in 1994 (referred to as the “Intertie Feasibility Study”); these
estimates were subsequently used in the Copper Valley Intertie Feasibility Study Update in
1995 (referred to as the “Intertie Feasibility Update”).
Public comment on the Intertie Feasibility Update was made during meetings in held in the
first week of December, 1995. A number of the comments made during these meetings
reflected concern about the accuracy and consistency of cost estimates for the alternatives
evaluated. This memorandum is intended to respond to these concerns.
CH2M HILL reviewed the approach taken to develop construction cost estimates for each
alternative and checked the consistency among these estimates. Risk analysis to test the
probability of cost overruns was conducted for the least-cost alternatives.
Summary results of the overall analysis are shown in Table 1. Original cost estimates for
the various alternatives were either developed for the Intertie Feasibility Study or taken
from other studies. Estimates taken from other studies were adjusted to 1993 dollars, as
shown in the first three columns of Table 1. Adjustments CH2M HILL made to these
$EA/1002C1F5.D0C
1/30/96 1
estimates are reflected in the fourth column. Comparison between the third and fourth
columns show that CH2M HILL generally accepts estimates made for the Intertie Feasibility
Study.
Table 1
Analysis of Construction Cost Estimates for Copper Valley Intertie and Alternatives
CH2M HILL Cost Estimate/Review
Intertie Feasibility Study Base Estimate Risk-Adjusted Estimates’
Original Cost Estimates 1993 in 1993 20th 50th 80th
Dollars (000) Basis Year Dollars’ (000) Dollars (000) Percentile Percentile Percentile
All Diesel 11,625° 1993 11,625° 12,125 9,960 10,840 11,700
Intertie 47,604 1993 47,604 47,604 45,400 47,600 49,800
Allison Lake 30,937 1992 32,240 32,240 na na na
Silver Lake Option A 52,496 1992 54,185 54,185 na na na
Silver Lake Option C na na na 39,635 34,100 35,600 37,400
Valdez Coal 36,600 1993 36,600 36,000 na na na
1 Risk-adjusted estimates show the level at which actual costs have a given probability of occurring or be in below.
For example, there is an 80 percent probability that the construction cost for the Intertie will be at or below
$49.8 million.
2 These data were used in the Copper Valley Intertie Feasibility Update for resource cost and cost of power
calculations.
3 Construction cost estimates for the All Diesel Alternative as defined in the 1994 Intertie Feasibility Study.
CH2M HILL’s evaluation of CVEA’s diesel generation option concluded that 1) construc-
tion costs included in the Intertie Feasibility Study are realistic and 2) replacement of CVEA
diesel units would result in improvements in generation efficiency and continuation of
O&M staff at existing levels. The conclusion regarding operations is consistent with the
“Modified All Diesel” alternative evaluated in the Feasibility Study Update.
Table 1 also shows costs for a new design proposed for Silver Lake (Option C). This
estimate is based on a proposed design by Whitewater Engineering. Cost estimates
prepared by Whitewater were evaluated and adjusted to the $39.6 million estimate shown
in the table.
Risk Assessment and Analysis
Risk analysis of Intertie construction shows that the cost to build the project will not likely
vary by substantial amounts from the cost estimate. As Table 1 shows, there is an 80
percent chance that the project will cost less than $49.8 million.
Risk analysis for the All Diesel alternative indicates that construction costs will likely fall
between $10.0 and $11.7 million; there is an 80 percent chance that these costs will be less
than $11.7 million. This is about the same as originally estimated by R.W. Beck and slightly
less than estimated by CH2M HILL.
Two findings from the risk analysis of Silver Lake Option C have significant, but opposite,
impacts on the economics of this project. First, it is highly probable that construction costs
will be less than estimated by CH2M HILL. Second, the energy output from Silver Lake
will not likely be as high as planned. That plan includes a reduction in instream flows
during the summer salmon spawning season from about 450 cubic feet per second (cfs) to
SEA/1002C1F5.D0C 2
5 cfs. It is likely that regulatory agencies will require 100 to 200 cfs be maintained. This will
reduce usable output from the plant by 10 to 20 percent.
Conclusions
On the basis of these findings, CH2M HILL recommends that analysis included in the
Feasibility Study Update not be further refined with the exception of including evaluation
of the Silver Lake Option C in the benefit-cost analysis. Based on CH2M HILL’s cost
estimate and Whitewater’s planned output for Silver Lake, this project is one of the least
cost alternatives. As shown in Table 2, it compares well with the Intertie and Modified All
Diesel alternatives (assuming CVEA loads grow in the medium-low to medium-high
range).
However, risk analysis indicates that the cost of the project may be lower than estimated
and that instream flow requirements for salmon spawning will likely result in lower output
than planned. If the Silver Lake were to be built for only $35.6 million but output was
limited to 85 percent of Whitewater’s plan, Silver Lake Option C would compare marginally
less well with the Intertie:
Low Fuel/ High Fuel/
Med. Low Med. High
Load Fet. Load Fet.
Present Value of Costs (1993$ * 10°
Intertie 54,227 59,101
Silver Lake 57,369 61,870
Percentage Difference 5.8% 4.7%
On the basis of data currently available, Allison Lake is still not considered as a realistic
option because of the Four Dam Pool charge associated with this alternative. (The effects of
this charge are not reflected in Table 2.)
Following this summary are two sections. The first section contains a description and
analysis of the cost estimate for each alternative. The second section is a risk analysis of three least-cost alternatives: the Intertie, the All Diesel, and the Silver Lake Option C alternatives. Each of the two sections begins with a brief review of the approach taken for
the analysis in the section.
SEA/1002C1F5.00¢ 3
TABLE 2
Present Value and Benefit-Cost Ratio for Power Supply Alternatives
-Low Fuel Cost Escalation_ High Fi t Escalati
Med. High Med. Low Med. High Med. Low
Alternatives Load Fct. Load Fct. Load Fet. Load Fet.
r Value of 0)*:
1994 All Diesel 60,483 55,924 67,632 61,697
Modified 1995 All Diesel 56,955 49,592 65,054 55,893
Intertie 56,088 54,227 59,101 56,603
Allison Lake ‘ 59,972 55,606 63,223 57,520
Silver Lake--Option A 69,911 68,109 71,056 68,701
Silver Lake--Option C 58,644 56,895 59,780 57,492
Valdez Coal 88,683 83,962 84,499 79,574
Savings Compared to Diesel ($000):
1994 All Diesel 0 0 0 0
Modified 1995 All Diesel 3,528 6,332 2,578 5,804
Intertie 4,395 1,697 8,531 5,094 Allison Lake * 511 318 4,409 4,177
Silver Lake-Option A -9,428 -12,185 -3,424 -7,004
Silver Lake---Option C 1,839 -971 7,852 4,205
Valdez Coal -28,200 -28,038 -16,867 -17,877
Benefit /Cost Ratio:
1994 All Diesel 1.00 1.00 1.00 1.00
Modified 1995 All Diesel 1.06 1.13 1.04 1.10
Intertie 1.08 1.03 1.14 1.09 Allison Lake ‘ 1.01 1.01 1.07 1.07
Silver Lake--Option A 0.87 0.82 0.95 0.90
Silver Lake--Option C 1.03 0.98 . 1.13 1.07
Valdez Coal 0.68 0.67 0.80 0.78
‘Possible generation resources at Alyeska and Petro Star are excluded from this analysis due to lack
of data on resource development costs.
*M-H/M-L = Medium-High/Medium Low. Since the difference between the medium high and medium
low forecasts is only the length of time Petro Star’s Valdez refinery is in operation, these forecasts are
identical if Petro Star is assumed to leave the CVEA system.
*1993 dollars based on a 4.5 percent discount rate. “Excludes 4-Dam Pool charge.
SEA/1002C1F5.D0C
Evaluation of Cost Estimates for Each Alternative
Approach
Evaluation of the cost estimates for each alternative was conducted through:
e Review of reports and other documentation supporting each estimate. This review was
performed by experts in the primary technology employed for each alternative
e A formal request to the owner or developer of each project alternative for new
information pertaining to the given alternative and review of information received.
e Aworkshop focusing on the various estimates and consistency among the estimates.
Workshop participants included the individuals reviewing the cost estimate for each
alternative, individuals who developed the original estimates, and cost estimating and
risk analysis facilitators. A checklist was developed as a basis to evaluate the
consistency of inclusion of specific cost elements in each estimate. Cross analysis was
also conducted.
e Analysis of information gained from the supporting documentation and the workshop.
On the basis of this analysis, professional opinion was used to determine if adjustments to
the cost estimates were warranted on the grounds of either their own merit or for
consistency among the estimates.
All Diesel Alternative
Project Description
Currently, diesel generators are being used at Glennallen and Valdez for generating and re-
serve requirements above those met by hydroelectric generation at Solomon Gulch. These
two sites each have seven machines, as shown in Table 3.
The all diesel alternative assumes that Solomon Gulch and diesel generation would con-
tinue to be used to meet CVEA generation and reserve requirements. Under this alterna-
tive, several new units would be purchased to replace existing units at the time that major
overhauls would otherwise occur.
New generating units would be chosen as Caterpillar 3600 series engines. The choice of this
supplier is intended to avoid support and supply problems exhibited with the existing En-
terprise (recently) and Fairbanks Morse (historically) units. The size of engine to be pro-
vided is set between 1,650 kW and 2,200 kW, presumably to support ease of installation and
provide flexibility in load following.
The addition of an additional engine generator at Glennallen can be accommodated with
the existing building configuration—additional units would require expansion of facilities.
There is presently no room for additions at the Valdez plant. Also, it is assumed that a
300,000-gallon fuel tank would be required at Valdez to supplement the current fuel system.
Modifications to plant switchyard systems could certainly be required at either plant, due to
the age of the present system and due to the demands of new generating equipment.
SEA/1002C1F5.00C 5
TABLE 3
CVEA Existing Diesel Generation
Glenallen Capacity (kW) Valdez Capacity (kW)
Unit 1: Fairbanks Morse 300° Unit 1: Fairbanks 600
1959 Morse 1966
Unit 2: Fairbanks Morse 300° Unit 2: Fairbanks 600
1959 Morse 1966
Unit 3: Fairbanks Morse 600 Unit 3: Fairbanks 600
1963 Morse 1966
Unit 4: Fairbanks Morse 600 Unit 4: Enterprise 1700
1966 1972
Unit 5: Fairbanks Morse 600 Unit 5: Enterprise 2500
1966 1975
Unit 6: Enterprise 2200 Unit 6: Enterprise 950
1975 1975
Unit 7: Enterprise 2200 Unit 7: Solar (Turbine) 2800
1975 1976
“Unit is no longer in service.
Cost Estimate
In the Intertie Feasibility Update, data on diesel generator costs were evaluated from two
sources: the Intertie Feasibility Study and CVEA’s power supply study entitled Intertie Final
Report, Evaluation of Power Supply Alternatives. Cost estimates included in the Intertie
Feasibility Study were judged to be more realistic in this cost estimate review. Engine
generator cost estimates developed for the Intertie Feasibility Study are shown in Table 4.
TABLE 4
R.W. Beck Diesel Generator Cost Estimates
Description Caterpillar 3606 (1993 dollars) Caterpillar 3608 (1993 dollars)
Engine 749,560 883,875
Generator 80,500 107,500
Cooling System 50,930 67,540
Exhaust System 10,230 12,210
Air Start System 26,400 26,400
Fuel System 27,500 27,500
Station Battery 7,700 7,700
Switchgear 110,000 110,000
Total Equipment 1,062,820 1,242,725
Engine Cost/kW 592 527
Permitting, Site Prep, :
Engineering, Installation 255,077 298,254
Delivery 31,885 37,281
Contingency 159,423 186,409
Total 1,509,205 1,764,669
Cost per kW 937 821
SEA/1002C1F5.00C
This estimate was performed at a preliminary level of detail, which is not unusual for a
facility of this kind.
The contingency amount shown is about 15 percent of equipment costs. Delivery is
3 percent of equipment costs, and permitting /site preparation/ engineering /installation
costs are shown as 24 percent of equipment costs.
Costs included in the estimate that may be overestimated or may even not be incurred are:
e Costs shown for permitting/site preparation/engineering /installation do not necessar-
ily reflect the existing conditions at the sites. Provisions generally exist for new ma-
chines, particularly if they replace existing machines. Air permits may be simply
revised, site work may be minimal and engineering is limited to building and system
changes (engine engineering is included in the purchase price). Installation is partially
covered by engine support (provided by the supplier).
¢ Switchgear costs assume upgrade and/or new equipment provided with the new ma-
chines. Existing electrical systems may be sufficient, or require minimal changes, to
support the new machines.
Costs that appear not to be included in the estimate are:
e Switchyard improvements are not shown; either site may require substation and other
improvements, estimated by R.W. Beck at $550,000.
e Engine foundation and structural support systems may not be adequate for the new ma-
chines. The area provided for expansion (or developed for expansion) may require
foundation preparation or piling to support the new machine.
e Air shed capacities are limited at Valdez. Both plants operate above PSD limits and
hence Title V air permit requirements apply. This could translate to air modeling and
other air permitting work, triggered solely by the addition of modern equipment-the
last machine was added at Glennallen in 1975 and at Valdez in 1976.
CH2M HILL recommends the All Diesel alternative cost estimate be augmented as shown
in Table 5.
This cost estimate reflects installation of five 3608 CAT engines (as shown in 1995 CH2M
HILL report) at Glennallen (2) and Valdez (3). It assumes retirement of Unit 6 at Glennallen
and Units 4, 5 and 6 at Valdez, and relocation of Unit 7 at Glennallen to Valdez.
This cost estimate also shows $500,000 in permitting costs, recognizing potential problems
at both sites with air shed and permitting to Title V requirements.
SEA/1002C1F5.00C 7)
TABLE 5
CH2M HILL Adjustments to R.W. Beck Capital Cost Estimates for All-Diesel Alternatives
Cost (1993 dollars)
Description R. W. Beck CH2M HILL
Structures and Improvements 2,000,000 2,000,000
Engine Generator & Accessories 6,214,000 6,214,000
Substation/Transmission 550,000 550,000
Delivery 186,000 186,000
Total Direct Construction Costs 8,950,000 8,950,000
Permitting 0 500,000
Engineering & Design 1,401,000 1,491,000
Subtotal 10,441,000 10,941,000
Contingency 1,184,000 1,184,000
Total 11,625,000 12,125,000
Possible limitations to this cost estimate are as follows:
e Fuel system changes have been discussed for the Valdez plant, but were not acknowl-
edged for the Glennallen plant. Cost at either site may not be adequately addressed in
the cost estimate.
¢ Electrical substation improvements have not been defined at either plant. The allowance
shown in the cost estimate may not be sufficient for both plants.
Conclusion
The engine generator cost estimates provided for this alternative are reasonable, and typical
for projects of this type. However, they may not adequately reflect powerplant building
changes, significant fuel system changes or electrical substation improvements, all of which
could be required.
Copper Valley Intertie
Project Description
The proposed 138-kV transmission line between the towns of Sutton and Glennallen would
allow the Copper Valley Electric Association (CVEA) to purchase relatively low-cost power
from the generating utilities of Alaska’s Railbelt region. The approximately 134-mile-long
intertie project would connect CVEA’s 138-kV system to the 115-kV Matanuska Electric
Association (MEA) transmission system. MEA is served by the Chugach Electric Associa-
tion transmission grid which is interconnected with Chugach and Anchorage Municipal
Light and Power gas-fired generation resources.
SEA/1002C1F5.D0C 8
Cost Estimate
Table 6 shows a summary of the cost estimate of the intertie prepared by R.W. Beck as part
of the 1994 Copper Valley Intertie Feasibility Study. This estimate was intended to be an
appropriately accurate representation of the total cost to develop and construct the project,
so that fair economic comparisons can be made with the other power supply options.
The estimate was based on investigations conducted by R.W. Beck and its consulting part-
ners. The estimate was based on consideration of the electrical system impact, the preferred
line route, and a specific construction concept. Dames and Moore. Inc., was responsible for
the environmental analysis, and Power Technologies, Inc. (PTI) was responsible for the elec-
trical system analysis. PTI modeled the Railbelt system with the CVEA system connected
through the intertie. Numerous loading and system switch positions were used in com-
puter simulations to determine the limitations imposed by the intertie. PTI found that with
one Chugach 115-kV line segment out of service, CVEA loads above the planning load level
of approximately 15 MW would require the addition of a Static VAR Compensator (SVC) at
the new Sutton substation. To avoid the installation and the expense of the SVC, CVEA has
elected to sever the intertie under these conditions and meet system load with a mix of
available resources of including load shedding, if necessary. This approach is consistent
with historic Railbelt utility practices.
The R.W. Beck study includes estimates of the construction cost for four candidate line
routes and recommends an “apparent preferred” route, as mentioned above. These esti- mates are both comprehensive and highly detailed. The analysis supporting the estimate
begins with basic construction concepts and then uses numerous linked spreadsheets for
the extension of material and labor costs. For example, the study considers the overall cost
impact of several conductor types that meet the economic conductor size. The study also
includes preliminary design of the strength, weight, and cost of several types of structures.
The estimate itemizes the quantity and distribution of structure heights, span lengths, and
construction assemblies, including insulators, nuts, and bolts, for each of the four distinctly
different segments of the line route. The four line segments are referred to as structural
Loading Zones that are distinguished by the weather exposure, terrain, vegetation, and soil
conditions .
Cost estimate contingencies are normally included to provide funds for additional costs that
cannot be anticipated at the time of the estimate but could reasonably be expected. Such
costs might include material and labor cost increases, changes during construction due to
soil conditions, regulatory rule changes, or inadvertent design omissions. The R.W. Beck
estimate includes contingencies that include all of these categories.
SEA/1002C1F5.00C 9
TABLE 6
Copper Valley Intertie Cost Estimate
Description
Cost
(1993 dollars)
Transmission Line Construction
Structures
Foundations
Guys and Anchors
Framing
Conductor
Right-of-Way Clearing
Mobilization
Subtotal Transmission Line Construction
Substation Construction
New Sutton Substation
Bump Station No. 11 Substation
Subtotal Substation Construction
Direct Construction Cost
Engineering Services
Construction Management
Environmental Services and Permitting
Right-of-Way Acquisition
Owner's Costs
Subtotal
Contingency
Total Cost
7,717,699
7,598,190
1,226,521
2,642,195
6,503,487
2,792,960
1,284,405
30,765,457
1,824,316
1,793,903
3,799,130
34,564,587
3,337,900
2,159,352
1,405,000
713,000
1,360,392
43,540,231
5,245,036
47,604,356
‘Preferred Route Alternative D.
SEA/1002C1F5.D0C 10
Evaluation of Cost Estimate
The Power Engineers study of 1993! developed a total Intertie project cost estimate (1993
dollars of $40,428,919 compared with the R.W. Beck total of $47,604,356). Power’s estimate
appears to be somewhat less comprehensive and somewhat less detailed in itemizations.
Because the line routes assumed by the two estimates are different2, differences occur in
right-of-way clearing, access, and judgments of construction efficiencies.
The assumed design configurations for both estimates are similar. However, several design
assumptions make the Beck estimate higher than that by Power Engineers. First, because
of access problems at the existing O’Neil Substation, Beck determined that the Sutton
terminus would require a new substation some distance from the old substation. Second,
Beck assumed a somewhat larger and stronger ACSR conductor (605 kcmil Teal) compared
to the conductor (556 kcmil Dove) that Power used in their estimate. These design
differences probably account for approximately $1,000,000 of the estimate difference.
A large difference also appears in Right-of-Way acquisition while Beck estimates $2,118,000
and Power estimates $449,000; a $1,669,000 difference. Beck included an Environmental
Impact Study that was not anticipated as necessary by Power at the time of their estimate.
Beck included 12 percent for overall contingencies (construction and other cost) while
Power included 10 percent. This difference accounts for or about $1,000,000 of the
difference between the Beck and Power estimates. The Beck contingency includes
15 percent on direct construction costs and 10 percent on other costs. A 10 percent
contingency on construction is often appropriate for projects that are designed and ready
for bidding. However, because the geotechnical survey and detailed design has not been
completed for this project, and because the foundation work is such a large part of this
project, the Beck 15 percent contingency on construction is appropriate.
Adding the above estimate differences to the Power estimate brings the Power estimate to
about $45,000,000 which is within 5 percent of the Beck estimate.
During public meetings regarding the intertie in early December 1995, two questions were
raised about specific aspects of the intertie cost estimate. Answers to these questions are:
Helicopter costs : R.W. Beck includes the use of helicopters in their construction estimate
where they are either required or economical to use. Beck estimates 683 hours at $239/hr
for a Bell personnel helicopter and 573 hours at $3000/hr for a heavy-lift Vertol 107-2 heli-
copter.
Comparison with other 115-kV or 138-kV Construction Projects in Alaska: The Beck estimate
divides the line route into four loading zones that result in differing costs per mile depend-
ing on the construction, terrain, and access constraints. These costs are $227,000/mile for
Zone 1, $223,000/mile for Zone 2, $245,000/mile for Zone 3, and $377,000/mile for Zone 4.
These costs compare favorably with actual costs that were incurred for other projects with
similar construction conditions in Alaska.
1 Power Engineers, Sutton to Glennallen 138kV Transmission Intertie Project, Volume 2, Final Report, prepared for the Copper Valley Electric
Association, Dated January, 1993.
2 The Beck and Power Engineers routes are similar over the western-most 40 miles. At Syncline Mountain, the route assumed by Power Engineers
travels to the south and that assumed by R.W. Beck travels to the north. From that point to the east end of the project, Beck’s route remains 2 to 5 miles
to the north of the Power Engineers route. The Power Engineers route runs just to the North and parallel to the Glenn Highway.
SEA/1002C1F5.00C "1
Given that the two estimates are for different line routes, these estimates are considered to
be comparable.
Conclusion
The R.W. Beck estimate is an adequate and credible representation of the itemized and
overall Intertie costs for the purpose of economic comparison with other power supply
options.
Allison Lake Hydroelectric Project Alternative
Project Description
Allison Lake is located about 2 miles southwest of Solomon Gulch Reservoir. The Allison
Lake Project evaluated in the 1994 Intertie Study and the 1995 update, would divert water
from Allison Lake to the Solomon Gulch Reservoir during the winter months in order to
provide additional generator at the Solomon Gulch Project. Several design options at Alli-
son Lake were reviewed in the Allison Lake Reconnaissance Study, prepared by HDR
Engineering, Inc. (HDR) in September 1992. The preferred option identified in this study
consists of an 11,950-foot-long tunnel from Allison Lake to the Solomon Gulch Reservoir, a lake tap approximately 2,100 feet below the surface of Allison Lake, and a 3,145-kW
hydroelectric generation facility located at the discharge from the tunnel into the Solomon
Gulch reservoir. Water would be withdrawn from Allison Lake, flow through the tunnel,
and then pass through the generation facility and discharge into Solomon Gulch Reservoir.
This water from Allison Lake would then be available to provide additional generator at the
existing Solomon Gulch generation facility. The total expected average annual energy to be
produced from the new powerhouse plus the increased production from the existing
Solomon Gulch facility was estimated to be about 27,400 MWh.
Another alternative, that would not require the passing of Lake Allison water into the
Solomon Gulch reservoir or any other modifications to the Solomon Gulch hydroelectric
project, would be a stand-alone project on Allison Creek. The U. S. Army Corps of Engi-
neers studied such a project in 1981 and their construction cost estimate was subsequently
updated by HDR in 1992. The project would consist of an Allison lake tap and a combina-
tion of tunnel and pipeline to convey water down to a new powerhouse on Allison Creek just above its mouth near sea level. The estimated project cost was substantially higher than the preferred option ($53,666,932 in 1992 dollars) and the expected average annual energy
was assumed to be somewhat lower (25,900 MWh).
Currently the Alaska Business and Industrial Development Corporation (ABIDC) holds a
FERC Preliminary Permit to study a standalone project on Allison Creek. The project con-
cept is similar to that studied by the Corps of Engineers in 1981 except for the following:
e A trench and siphon intake would replace the lake tap.
¢ The water would be conveyed down to the powerhouse by pipeline only, rather the
tunnel /pipeline combination.
ABIDC is currently proposing a 5-MW installation at this site. A cost estimate has not been
prepared by ABIDC.
SEA/1002C1F5.D0C 12
Cost Estimate
Table 7 provides a summary construction cost estimate for the Allison Lake project. It is a
summary of a more detailed cost estimate prepared in 1992 by HDR as part of their Allison
Lake Reconnaissance Study.
Table 7
Allison Lake Project
Summary Construction Cost Estimate
Cost
——
Land and Land Rights
Structures and Improvements
Reservoirs, Dams, and Waterways
Description
Turbines and Generators (Incl. Gov. & Exciter)
Accessory Electrical Equipment
Miscellaneous Mechanical Equipment
Structures and Improvements (Trans. Facilities)
Substation Equipment & Structures
Fixtures, Conductors & Devices
Total Direct Construction Costs
Design Engineering (9%)
Geotechnical , Borings, & Seismic Surveys
FERC and Other Licensing
Construction Management (8%)
Subtotal
Contingency
1992 Estimated Construction Cost
112,000
300,000
20,547,250
1,849,253
500,000
400,000
1,643,780
24,940,283
5,996,975
30,937,258
Evaluation of Cost Estimate
The level of cost detail provided for this alternative was ample for a reconnaissance-level
investigation. The estimate included a cost contingency of approximately 24.0 percent of
construction and other costs. This appears appropriate for this level of study.
The major uncertainty with this alternative is with the construction of the “lake tap”
underneath Allison Lake. Considerable amount of debris apparently exists on portions of the lake bottom, and to the extent that it exists at the proposed lake tap location is unknown
SEA/1002C1F5.D0C 13
at this time. No cost allowance for any dredging was included in the estimate. In addition
the exact location at which the lake tap is to be made is of critical importance and
considerable subsurface investigation and analysis will be required before construction can
begin. Poor rock conditions could even potentially render this alternative unfeasible.
Conclusions
In our opinion, the cost estimate as developed by HDR is reasonable and the project, as
configured, appears to provide for a “utility grade” (50-year) facility, consistent with the
standards we believe are necessary.
Silver Lake Hydroelectric Project Alternative: Option A
Silver Lake is situated about 15 miles southwest of Valdez. The outlet from the lake forms
the Duck River which flows into Galena Bay. The Allison Lake Reconnaissance Study
briefly reviewed two options for project development: Option A , proposed by Stone &
Webster in 1982 and 1983, and Option B proposed by Whitewater Engineering Corporation
(Whitewater) in 1992. Following is an evaluation of Option A.
Project Description
This option includes a 125-foot high roller-compacted concrete (RCC) dam, 6,000 feet of
108-inch pipeline, and a 15-MW powerhouse located at elevation 65 on the Duck River. The
powerhouse would be equipped with three 5-MW Francis turbines. Transmission to the
Solomon Gulch Project would be accomplished with a 22-mile-long overhead transmission
line. The total expected average annual energy to be produced by this option was estimated
to be about 44,800 MWh.
Cost Estimate
Table 8 provides a summary construction cost estimate for the Silver Lake (Option A) proj-
ect. It is a summary of a more detailed cost estimate prepared in 1992 by HDR as part of
their Allison Lake Reconnaissance Study.
Evaluation of Cost Estimate
The original cost estimate for this option was prepared in 1982 by Stone & Webster as part
of a Cordova power supply interim feasibility assessment. HDR developed the costs con-
tained in Table 2 by using the quantities previously developed by Stone & Webster and
applying their own unit prices. HDR presented the estimate in about the same level of detail
as provided in their Allison Lake estimate. In recent discussions with HDR it was agreed
that a cost allowance for geotechnical investigations should by added to their 1992 estimate
and that has been done, as shown in the table. This estimate included a contingency of
approximately 22.5 percent on the construction and other costs, which again appears
appropriate for this level of study.
The Silver Lake site is more remote than the Allison Lake which will make access for diffi-
cult and expensive. However there doesn’t appear to be any major technical barriers to
development of a project at Silver Lake.
SEA/1002C1F5.D0C 14
The Duck River and surrounding lagoon area is reported to be a very productive region for
pink salmon. The elevation 65 site for the powerhouse is above what has been considered to
be an impassable fish barrier. Thus the environmental impacts on the fishery have been
viewed as minimal.
Table 8
Silver Lake (Option A) Project
Summary Construction Cost Estimate
Description Cost a ) _,
Land and Land Rights 1,175,000
Structures and Improvements 2,571,250
Reservoirs, Dams, and Waterways 20,619,500
Turbines and Generators (Incl. Gov. & Exciter) 4,095,000
Accessory Electrical Equipment 440,000
Miscellaneous Mechanical Equipment 50,000
Structures and Improvements (Trans. Facilities) 30,000
Substation Equipment & Structures 300,000
Fixtures, Conductors & Devices 6,600,000
Total Direct Construction Costs : 35,880,750
Design Engineering (9%) 3,229,268
Geotechnical , Borings, & Seismic Surveys 500,000
FERC and Other Licensing 400,000
Construction Management (8%) 2,870,460
Subtotal 42,880,478
Contingency 9,615,725
1992 Estimated Construction Cost 52,496,203
Conclusions
The cost estimate for this option, as developed by HDR, in our opinion is reasonable and
the level of accuracy appears consistent with the Allison Lake Project estimate. This Silver
Lake option appears to also provide for a “utility grade” installation.
SEA/1002C1F5.0c 6
Silver Lake Hydroelectric Project Alternative: Option C
Project Description
As mentioned above, Option B to hydroelectric development at Silver Lake was developed
by Whitewater Engineering in 1992. Whitewater updated its plan and related cost estimate
ina letter to AIDEA, dated November 13, 1995. The updated Whitewater plan is referred to
as Silver Lake Option C. It is similar to the Silver Lake Option A, except the powerhouse site
would be lowered from elevation 65 to elevation 35 and a submarine transmission cable
would be substituted for the overhead transmission line. By locating the powerhouse down
at elevation 35 there would be some increase in energy production over the elevation 65
site, but that value has not been calculated yet. Whitewater recently received a FERC
Preliminary Permit to further study the site.
Cost Estimate
A summary of Whitewater’s current construction cost estimate for Silver Lake (Option C) is
shown in Table 9. This estimate was provided in Whitewater’s November 13, 1995, memo
which it updated on January 18, 1996. Some adjustments to the latest estimate were made
by CH2M HILL. The January 18 Whitewater estimate as adjusted by CH2M HILL is also
shown in Table 9 (in the column entitled “CH2M HILL”).
Evaluation of Cost Estimate
It is our understanding that Whitewater’s costs are based upon their recent experiences on
the Black Bear and Power Creek projects in southeast Alaska plus some reliance on the costs
developed by HDR for the Silver Lake (Option A) alternative. The estimate contained a
$300,000 allowance for two operators residences which was deliberately excluded from the
table for consistency because this was not included in the Silver Lake (Option A) estimate.
The CH2M HILL costs provided in the table are Whitewater costs with the following
modifications:
e Anallowance of $1,000,000 was added to acquire the necessary land rights to develop
the project. This is the same figure used in the Silver Lake (Option A) estimate.
Whitewater assumed that the affected property owner(s) would be paid a royalty on
power sales revenues and this would become an operating expense. It was assumed that
this would be equivalent to the $1,000,000 up-front payment.
e Whitewater’s estimate includes an allowance of $250,000 for a prefabricated metal
building for the powerhouse superstructure. The Silver Lake (Option A) estimate con-
tains a $600,000 allowance for a more substantial concrete /masonry building super-
structure. For consistency between the two alternatives, the difference ($350,000) was
added to our estimate. (If a prefabricated metal building were installed, maintenance
would increase above assumed levels.)
e Whitewater’s November 13, 1995, costs for installation of the penstock were adopted.
SEA/1002C1F5.00C 16
Table 9
Silver Lake (Option C) Project
Summary Construction Cost Estimate
Cost (1995 dollars)
Description Whitewater CH2M HILL
Land and Land Rights 215,000 1,215,000
Structures and Improvements 1,462,500 1,512,500
Reservoirs, Dams, and Waterways 12,859,000 14,059,000
Turbines and Generators (Incl. Gov. & Exciter) 3,060,000 3,900,000
Accessory Electrical Equipment 910,000 910,000
Miscellaneous Mechanical Equipment 50,000 50,000
Structures and Improvements (Trans. Facilities) 68,000 68,000
Substation Equipment & Structures 325,000 325,000
Fixtures, Conductors & Devices 6,440,000 6,440,000
Mobilization 2,000,000 2,000,000
Total Direct Construction Costs 27,389,500 30,479,500
Design Engineering 750,000 750,000
FERC and Other Licensing 800,000 800,000
Construction Management 1,000,000 1,000,000
Subtotal 29,939,500 33,029,500
Contingency 4,535,925 6,605,900
1995 Estimated Construction Cost 34,475,425 39,635,400
e Whitewater’s November 13, 1995, costs for purchase and installation of the turbine and
generator equipment was also adopted.
e Whitewater’s contingency was increased from 15 to 20 percent . Given Whitewater’s
approach to the project, it is reasonable to use a 20 percent contingency rather than the
24 percent figure used in the Allison Lake estimate and 22.5 percent used in the Silver
Lake Option A estimate.
Locating the powerhouse down as low as elevation 35 could result in adverse impacts on
the salmon fishery. Whitewater has indicated that the upstream migrating salmon turn in
Bennett Creek before they reach the proposed powerhouse; but this will require further
study.
$EA/1002C1F5.D0C
Also the swift currents and rough bottom conditions in Prince Williams Sound may make it
quite difficult to build and maintain the submarine transmission cable as proposed by
Whitewater. However the cost allowance for this cable is probably adequate to build an
overhead transmission line.
Conclusions
Whitewater’s cost estimate presumably reflects the intent of a private power developer and
engineer to take full financial responsibility for the planning, design, construction, and
perhaps even the operation of this project. Therefore it is difficult to draw a direct cost
comparison between this and the other alternatives whose estimates were developed by
independent engineers. However, in our opinion, Whitewater would be capable of
developing this project to “utility-grade” standards (50-year life) for $39.6 million.
Valdez Coal Plant Alternative
Project Description
Coal-fired powerplant to be located in Valdez, adjacent to CVEA's existing diesel
powerplant. The project, proposed by a private developer (Alaska Cogeneration Systems,
Inc. [ACSI]) includes twin boilers (coal-fired and oil-fired), twin steam turbines (6 MW and
12 MW), a district heating system, limestone dry scrubber/baghouse dry scrubber system, 3 cell cooling tower, ash handling system and coal storage and feed system. The coal-fired
boiler will be converted from a 26-year-old stoker unit to a fluidized bed unit, and the steam
turbines (850 F/900 psig) will be reconditioned.
The district heating hot water system is intended for government buildings, commercial
and dockside facilities, but there are no agreements in place to support such a system at this
time.
Coal for this project is provided from a mine in the Matanuska Valley near Sutton, operated
by the project developer. Coal would be containerized from the mine and shipped over-the-
road to the railhead, then transported to Whittier for truck transport to the site. The cost of
coal (estimated at $50/ton) includes mining, all transportation and delivery to the site.
The site is reported to be suitable for construction of a powerplant (bedrock), has nearby sewer and water supplies from Valdez, and is near the diesel plant switchyard for power
sales. Ash removal will be to a nearby landfill or backhaul to the mine. The developer has
air permits filed for a former project that he feels will apply to this project.
Operation of the plant will be primarily on coal fuel, 10 months of the year. Output will
vary from 10 MW firm capacity to 1 - 1.5 MW during late spring. Shutdown will be during
the summer periods (June - August). Maintenance of the plant will be performed primarily
during the shutdown. Projected schedule for construction is 18 months.
Cost Estimate
Costs submitted by ACSI have been summarized by R.W. Beck in their 1994 report, as shown in Table 10.
The contingency amount shown is 8 percent of total costs.
SEA/1002C1F5.D0C 18
Evaluation of Cost Estimate
The estimate provided has good detail in most areas and can be compared and evaluated
easily with other powerplant estimates. The contingency shown for this project is 7.5 per-
cent of construction and other costs; CH2M HILL recommends at least 15 percent of
construction and other costs for a well-defined project.
TABLE 10
ACSI Cost Estimate for Valdez Coal Alternative
Cost
Description (1993 dollars)
Site Acquisition 500,000
Foundation and Buildings 1,200,000
Boilers 4,000,000
Turbine Generator 2,000,000
Utility Work 500,000
Other 1,000,000
Piping 1,000,000
Electrical 2,200,000
Subcontractor Services 600,000
Miscellaneous Equipment 400,000
District Heating System 3,000,000
Water Supply and Treatment 500,000
Contractor Overhead and Profit 1,600,000
Total Direct Construction Costs 18,500,000
Permitting 150,000
Engineering and Design 850,000
Construction Management 1,000,000
Coal Reserves 2,300,000
Legal & development costs 1,900,000
Subtotal 24,700,000
Contingency 2,000,000
Total 26,700,000
Costs ACSI included in the estimate that may be overestimated or may even not be incurred
include the following:
e Engineering & Design: the developer intends to rely heavily upon the design documents
done for the proposed Air Force OTH-B project. If this is possible, engineering costs
would be minimal.
SEA/1002C1F5.00C 19
Permitting: the developer hopes to use existing air permits from the OTH-B project. If
true, permitting costs would be minimal.
Costs that appear not to be included in the estimate include the following:
Coal handling equipment: not specifically called out in the estimate, may not be ade-
quately provided for.
Ash handling and disposal: not shown in the estimate; equipment and disposal costs
could be significant.
Startup, commissioning and training costs: not shown.
Contractor overhead and profit appears low for a project of this type.
CH2M HILL recommends the Valdez Coal Project cost estimate be adjusted to the amounts
shown in Table 11.
There are several potential "fatal flaws" related to this project. They include:
ACSI apparently has little or no experience in coal mine operation, powerplant opera-
tion and district heat operation. The complicated fuel delivery scheme (road, rail, barge)
and sophisticated powerplant design (coal-fired fluid-bed boiler and steam turbines)
would challenge even the most experienced developer.
Refurbishment costs for the boilers and turbines are almost impossible to verify, but are
well below new equipment costs. If these equipment items cannot be refurbished, the
need for new equipment will make the project more costly than construction with new
equipment.
The lack of contracted district heating customers could severely hamper the economics
and operations of the coal plant. Steam demands determine the power levels possible
from the turbine generators. Revenue dollars from the heating plant offset project costs
and substantiate the cogenerator status of the project. Without full development of the
steam market, revenue requirements from the electric operation would increase to pro-
portionately higher levels.
The technical basis of the project is questionable, in several areas. First, operations of a
coal plant on a part-time or reduced load basis is unprecedented and will result in fuel
handling problems and early deterioration of equipment. Second, conversion of an old
stoker boiler to a fluid-bed boiler cannot be verified or guaranteed to any acceptable
level of confidence. Third, the planned goal of electrical interconnection of the plant at
the existing diesel plant substation may well be impossible (since both plants may be
required to operate at the same time), resulting in unplanned substation and distribu-
tion system costs.
The proposed transfer of air permits from past projects and equipment may not be ac-
cepted on a new project. Permitting in the Valdez area is anticipated to be difficult due
to the number of emission sources currently in operation. The proposed re-use of engi-
neering documents for this project may be flawed due to changes necessary for this
project.
$EA/1002C1F5.00C 20
TABLE 11
CH2M HILL-Adjusted Cost Estimate for Valdez Coal Alternative
Cost
Description (1993 dollars)
Site Acquisition $1,000,000
Foundation and Buildings $1,300,000
Boilers $4,000,000
Turbine Generator $2,000,000
Utility Work $1,000,000
Other $4,000,000
Piping $1,000,000
Electrical $2,200,000
Subcontractor Services $600,000
Miscellaneous Equipment $400,000
District Heating System $3,000,000
Water Supply and Treatment $500,000
Contractor Overhead and Profit $4,000,000
Total Direct Construction Cost $25,000,000
Permitting $250,000
Startup, Commissioning and Training $100,000
Engineering and Design $850,000
Construction Management $1,000,000
Coal Reserves $2,300,000
Legal & development costs $1,900,000
Subtotal $31,400,000
Contingency $4,600,000
Total $36,000,000
$£N/1002C1F5.00C 21
Conclusion
The cost estimate provided by the project developer is substantially low, when compared
against projects of similar complexity and technology. Construction costs alone for a project
of this type should be on the order of $25 million (as shown in Table 11), assuming used
equipment. New equipment would raise the cost much higher. Total costs for this project
should be on the order of $36 million.
All Diesel Alternative--Operation and Maintenance
Description
As described in the discussion of the construction cost for the All Diesel alternative, the All
Diesel alternative assumes that Solomon Gulch and diesel generation would continue to be
used to meet CVEA generation and reserve requirements. Under this alternative, several
new diesel units would be purchased to replace existing units at the time major overhauls of
the existing units would otherwise occur. Full capacity to meet local peak loads and reserve
requirements would be continue to be maintained at both Glennallen and Valdez.
Staffing levels at Glennallen presently total six persons: a chief operator, four engine opera-
tors (three operators / three shifts per day and one operator on rotation) and one engine
mechanic. Due to the isolation location of Glennallen, additional CVEA staff are not easily
available.
Valdez maintains a plant staff of four persons: a chief operator, two engine operators and
one engine mechanic. The Valdez plant is close to the Solomon Gulch hydro plant, which
has additional CVEA staff for that operation and a dispatch control center (including
SCADA system monitoring). Hydro plant staff are cross-trained in diesel plant operations,
and hence offer additional manpower to the Valdez plant as needed.
For the All-Diesel Alternative, the 1994 RW Beck study indicated that three new operators
would be added to the Valdez plant by 1997, to support new equipment and the increased
generation role.
The 1995 CVEA Power Supply Study assumed staffing requirements, indicating the termi-
nation of five operators (four at Glennallen and one at Valdez). This was assumed due to
installation of new, more reliable engine generators and the installation of supervisory
SCADA equipment in both plants.
This can be summarized as follows:
All Diesel Alternative
Case Glennallen Plant Staffing Valdez Plant Staffing
Status Quo five four
1994 Study five seven
1995 Study one three
SEA/1002C1F5.00C 22
Evaluation
The All Diesel Alternative must have an appropriate number of plant operators available
for engine (or gas turbine) generators that run in a primary power mode. Current staffing
levels (five at Glennallen and four at Valdez) are appropriate for this alternative. The instal-
lation of SCADA monitoring and newer generating equipment does not eliminate the need
for close supervision of equipment, particularly if CVEA wants to control damage to
equipment in an expeditious manner. However, the SCADA system would allow CVEA to
proceed with the All Diesel alternative without any increases in operation and maintenance
staff.
Conclusion
An increase in staffing levels for the All Diesel Alternative (as recommended in the 1994
study) is not warranted, even with the increased power generation. Similarly, a reduction
in staffing for this Alternative could seriously endanger the availability of generators at the
diesel plants.
Risk Assessment and Analysis of Costs and Schedule for
Selected Alternatives
As noted above, the least cost alternatives for new power supply at CVEA include the
Copper Valley Intertie, the All Diesel, and the Silver Lake Option C. In this section, project
uncertainties regarding construction costs for these alternatives are examined and cost
estimates associated with each adjusted to a “risk adjusted” range. Within this range,
probabilities of actual costs being at or below certain levels are calculated. In addition, risk
analysis was conducted for the operating costs of the All Diesel alternative. This was
because the operating costs associated with this alternative are the major component of its
life-cycle cost.
Risk-adjusted construction costs estimates for the Copper Valley Intertie, the All Diesel, and
the Silver Lake Option C alternatives are shown in Table 1. Risk-adjusted costs for All
Diesel operation are discussed later in this section.
Approach
The analysis proceeded in a two-step process. First, uncertainties (defined as conditions or
events that might affect either the project’s cost or schedule) are identified, categorized, and
measured as of high, medium, or low risk or as a potential fatal flaw. Mitigation ideas are
also developed for risks assessed as either high or medium. For each project alternative
studied, assessments for each of uncertainty factor were developed, typically in a day-long
workshop with experts familiar with the project or critical aspects required for project
construction and, in the case of All Diesel alternative, operations.
Second, on the basis of the risk assessment in step 1, risk analysis was performed to
determine probability-based cost estimates for each alternative. This analysis included:
¢ Integrating the results of the risk assessment workshop into the cost estimates (for
example, the cost of mitigation of risks was added to the cost estimates)
SEA/1002C1F5.00C 23
e Identifying a realistic range of cost for each of the primary cost categories included in the
cost estimate
¢ Performing a simulation analysis of total costs based on the range of probable cost for the
primary cost categories.
The result of this analysis is a risk-adjusted or probabilistic range of the total cost for each given
alternative. This range represents the likely cost result of risks considered in our assessment.
However, not all risks can be identified and those that can are estimated on the basis of
experience and professional judgment. Therefore, actual costs can occur outside the ranges
shown in the risk analysis figures (Figures 1, 2, and 3). Risk analyses presented in this technical
memorandum are not meant as a guarantee as to the ultimate cost of any project.
Given the risk-adjusted range of probable costs, a cost estimate can be adopted on the basis of
one’s tolerance for potential budget overruns. For example, budgeting an amount that has only
a 20 percent chance to be at or above actual costs may be considered to be too risky, since there
is only one chance out of five of the project being below actual costs. On the other hand,
budgeting an amount that has more than an 80 percent chance to be at or above actual costs
may be considered to be too conservative, since there is less than a one in five chance of actual
costs being above this amount.
In addition to the direct impact of risk on project costs, the risk of impacting the project
schedule was also assessed and evaluated. This was done from the perspective of whether the
schedule included a reasonable allowance for time delays associated with each of the risks.
Copper Valley Intertie
Risk Assessment
In the risk assessment workshop, the risk assessment team identified 60 potential risks to
project cost and schedule. These risks were further discussed and then designated as potential
fatal flaws or as high, medium or low risks in terms of their potential impact. Extraordinary
(extremely low probability) events were not included, but events outside the control of the
owner/ project team were included. This process resulted in the identification of the following
risk factors for project construction:
e 2potential fatal flaws (major risks that might result in project termination),
e 2high risks (major risks with likely cost and schedule implications but not likely to result in
project termination),
¢ 20 medium risks (important but manageable risks), and
¢ 36 low risks (possibly important risks but with small likely impacts).
These risks are summarized in Table 12. Also included in this table is an indication (check
mark) as to whether the risk was integrated into the risk-adjusted cost estimate and notes on
potential mitigation for these risks.
SEA/1002C1F5.00¢
1/30/96 24
TABLE 12
Copper Valley Intertie Project
Project Risk Assessment Summary Worksheet
Category of Risk
Potential Cost Risk Description of Risk Issue FatalFlaw____Cost__ Schedule _ Adjustment Notes on Mitigation
A Management and Administration Issues Changing Goverment Regulations (State, Local Communities) Medium Medium y EIS and Public Involvement Govemmental Support FF Public Perspective (Natural Environment, Socioeconomics) High Medium a EIS and Public Involvement Site Acquisition (BLM, Native Corps., MatSu Borough) Medium Medium y EIS and Public Involvement Project Management Organization (CVEA) Low Low B. Finance Availabilty Issues Pre-Construction (CVEA Funding) Low Low Construction (State Grant) FF Copper Valley Feasibility Study Update Operations Cash-Flow (rate impacts and REA Terms) Low Low c Regulatory and Permitting Issues Permit Acquisition State DNR, Mental Health Lands Medium Medium v EIS and Public Involvement Federal (BLM and COE) Medium — Low v EIS MatSu Borough Medium Medium v EIS and Public Involvement Native Regional Corp. (CIRI, AHTNA) Medium Medium Y EIS and Public Involvement APUC (Power Sales) Low Low D. Environmental and Geotechnical Issues
Weather Conditions Medium Medium y Risk Adjusted Cost Estimate Environmental Restriction on Construction Medium — Medium v Risk Adjusted Cost Estimate Availability of Subgrade Testing to Date Medium — Low v Risk Adjusted Cost Estimate Archaeological and Historical Findings Low Low Y Cultural Resources Survey E. Engineering Planning and Design Issues
Design Approvals and Changes Low Low v Route Selection High High v EIS and Public Involvement Weather Design Criteria Medium — Low Y Risk Adjusted Cost Estimate System Performance Identity during Preliminary Engineering Communication System Low Low Integration (Need for SVC/Shunt Reactor) Medium — Low Final Electrical System Analysis Intertie to Fairbanks Low Low MEA Substation Low Low Construction Management Low Low v Project Team Continuity Low Low Packaging of Bids Low Low F. Contractor Issues Competitive Availability of Qualified Contractors Medium Low Timing of Project Construction Level of Specification Detail in Design Drawings Low Low Labor Negotiations/Stoppages (Union Contract Expiration) Low Low Management of Subcontracts Low Low Change Orders (e.g., Structure relocate, realignment) Medium — Low y Risk Adjusted Cost Estimate Worker Safety (Construction in dark) Low Low Vv MEA Line Tap - Safety Low Low Pump Station 11 Tie - Safety Low Low 6. Existing Structures and Equipment and Material Availability
Equipment Availability (Helicopters) Medium Medium v Timing of Project Construction
Materials Availability Low Low Rejects and Defects Low Low Equipment Malfunctions and Failures Low Low Condition of Existing Structures Low Low Material Cost Fluctuations Low Low ¥, H. Construction Logistics and Transportation Laydown Area Limitations Low Low Traffic Congestion during Construction Low Low Access to Site (Physical) Medium Medium v Risk Adjusted Cost Estimate
Access to Site (Right of Entry) Medium Medium v EIS and Public Involvement Equipment Delivery
Eastem Construction Zone Medium Medium Vv Risk Adjusted Cost Estimate Wester Construction Zone Low Low
Materials Delivery Low Low Maintenance of Service during Construction Low Low Mobilization (Crew Lodging) Medium — Low wl EIS and Public Involvement Demobilization Low Low B Start-Up and Commissioning Issues Final Inspection Low Low Substation-Sutton Low Low Substation-Glenallen Low Low J. Operating Company Issues Maintenance of Line/Access for Maintenance (Contract Services) Medium - EIS and Public Involvement Availability of Line (Outages) Medium : Final Electrical System Analysis Power Sales Agreements Low - Back Feed to Sutton Low : Spare Materials and Parts Low : Identity in Preliminary Engineering
Category of Risk: FF: Major Risk that Might Become a Fatal Flaw High: Major Risk with Likely Cost and Schedule Implication but Not Fatal Flaw Medium: Important but Manageable Risk
Low: Possibly Important but with Small Impact NA: ___Not Applicable
SEA/1002C1F5.00C
1/30/96 25
The two potential fatal flaws and 22 medium to high risks* are discussed below. This
discussion is organized according to the same risk categories as shown in Table 12 and
includes a description of risks, costs and schedule impacts, and suggested methods to mitigate
the risks. A discussion on potential schedule risk is also follows.
A. Management and Administration Issues. The following are three key management and
administration risk issues. The potential financial impact of these risk issues has been
incorporated into the assumed ranges of the risk-adjusted project cost estimate.
Risk A-1 Changing government regulation, particularly the potential for communities
along the transmission route to assert zoning control over the location of the
route represents a project risk. If the members of local communities stay
mobilized against the project, it is likely to cost more and take longer to
implement. (Medium Risk)
Risk A-2 The governmental support for this project is uncertain and is related to cost-
effectiveness of investment from the perspective of both resource use and
utility rates. Without broad local and state support, the intertie is not likely to
be implemented. (Potential Fatal Flaw)
Risk A-3 The public support for this project is currently mixed. Opposition to the
project is multi-faceted. (High Risk)
Risk A-4 Right-of-way acquisitions for transmission line corridors can be time
consuming. For this project there will need to be hundreds of easements and
rights-of-way acquired. (Medium Risk)
The risk assessment team concluded that the key natural environment and socioeconomic
impact issues identified by the public thus far will be addressed in an environmental impact
statement. Mitigation developed as part of that decision making process (particularly on
transmission line routing and construction mitigation) will contribute to obtaining public
support.
Right-of-way acquisition needs to be started as soon as a route has been selected and the project
has received permits for construction. A coordinator for acquisition is recommended due to the
potential difficulty in obtaining them in a timely manner.
B. Finance Availability Issues. One key finance availability risk issue was identified. The
potential financial impact of this risk issue has not been incorporated into the assumed ranges
of the risk-adjusted project cost estimate.
Risk B-1 The State of Alaska construction loan for the Copper Valley Intertie Project is
considered to be vital. Without the loan, this project is considered to be
highly unlikely: (Potential Fatal Flaw).
3 These 22 risks represent the team's recommended priority list for management action based on potential schedule and cost impacts to the project. The
medium risks can usually be managed by direct integration into typical preliminary engineering or environmental impact analysis. The potential fatal flaws and
high risks generally require more focused management, such as directed public involvement or newsletters.
SEA/1002C1F5.00C 26
C. Regulatory and Permitting Issues. The following are four key regulatory and permitting risk
issues. The potential financial impact of these risk issues has been incorporated into the
assumed ranges of the risk-adjusted project cost estimate.
Risk C-1 Permit acquisition from State of Alaska Department of Natural Resources, and
State Mental Health Lands is considered uncertain pending completion of the
environmental impact statement process. (Medium Risk)
Risk C-2 Permit acquisition from Federal Bureau of Land Management and Corps of
Engineers is considered uncertain pending completion of the environmental
impact statement process. (Medium Risk)
Risk C-3 Permit acquisition from the MatSu Borough is considered uncertain pending
completion of the environmental impact statement process. (Medium Risk)
Risk C-4 Permit acquisition from Native Regional Corporations (CIRI and AHTNA) are
considered uncertain pending completion of the environmental impact
statement process. (Medium Risk)
The risk assessment team believed that permit acquisition was a medium risk and that
completion of the environmental impact statement process would result in permits for the
project. The risk-adjusted project budget has been adjusted to reflect the costs of the
environmental impact process.
D. Environmental and Geotechnical Issues. The following are three key environmental and
geotechnical risk issues. The potential financial impact of these risk issues has been
incorporated into the assumed ranges of the risk-adjusted project cost estimate.
Risk D-1 Winter weather conditions along the transmission corridor will result in
reduced construction efficiency. The impact is uncertain, but a contract clause
allowing for some sharing of this risk between contractor and owner should
be evaluated as a means of reducing the contract bid price. (Medium Risk)
Risk D-2 Restrictions on construction due to maintenance of environmental
quality/limited stream crossings will lead to reduced construction efficiency.
This impact is somewhat uncertain at this time, since a final route has not
been selected. (Medium Risk)
Risk D-3 The foundation construction cost is uncertain at this time due to a lack of
information about subgrade conditions. This is typical at this stage of a
project and may not be fully addressed for each location until construction
begins. (Medium Risk)
The risk assessment team evaluated the existing cost estimates to verify that allowances for
severe winter weather conditions had been included in the crew productivity assumed in the
cost estimate. Range estimates were further increased to account for this risk.
E. Engineering Planning and Design Issues. The following are three key engineering planning
and design risk issues. The potential financial impact of these risk issues has been incorporated
into the assumed ranges of the risk-adjusted project cost estimate.
Risk E-1 The final route selection for the transmission line has not been made. The
routes evaluated to date have been compared on a construction cost basis and
SEA/1002C1F5.00C 27
the least expensive was selected. Pending the findings of the environmental
impact process, during which a final route selection should be made, these
costs may increase. An increased allowance for route selection is included in
the risk- adjusted cost estimate. (High Risk)
Risk E-2 The weather design criteria have not been finalized as yet and remain
somewhat uncertain. They need to be finalized during preliminary
engineering with the assistance of a meteorological survey; a contingency
allowance is added in the interim. (Medium Risk)
Risk E-3 Additional system performance evaluations (final electrical systems analysis)
are recommended to address the current questions about the need and benefit
for equipment currently not included in the project. Final decisions are
needed during preliminary engineering on whether to include
communications links and certain substation equipment (Static VAR
Compensator and Shunt Reactor) as part of this project. (Medium Risk)
The risk assessment team believed that the route selection would be made on the basis of
weighted criteria, including impact on natural and human environment. Since the final route
selection might result in a route that is not the least costly (as currently used in the cost
estimate), a specific adjustment was included in the risk-adjusted cost estimate to allow for this
uncertainty.
The project as currently envisioned does not include certain features that are sometimes
included in similar projects. The benefits of including them need further evaluation. It is
important that these evaluations should take place early in the preliminary engineering phase
of the project to assure integration into design features if needed.
F. Contractor Issues. The following are two key contractor risk issues. The potential financial
impact of these risk issues has only partially been incorporated into the assumed ranges of the
risk-adjusted project cost estimate.
Risk F-1 The availability of a number of qualified contractors to bid on this project is
uncertain at this time. Construction is not currently envisioned earlier than 3
years from now, and competing projects may result in a low number of bids
received. This risk may result in higher than anticipated bids. (Medium Risk)
Risk F-2 Change orders due to field conditions not being reflected in design drawings
are to be expected. A specific allowance for extra work, separate from project
contingency, is included in the risk-adjusted cost estimate. (Medium Risk)
The risk assessment team was concerned about the potential conflict of other Alaska
construction projects with this transmission line project. No budget allowance was, however,
included to reflect the potential of non-competitive bids. Alternative project delivery methods
(such as negotiated design-build) should, if necessary, be considered during preliminary
engineering as an alternative to traditional low bid award.
G. Existing Condition of Structures and Facilities and Equipment and Material Availability Issues.
The following key risk issue was identified for this category. The potential financial impact of
this risk issue has only partially been incorporated into the assumed ranges of the risk-adjusted
project cost estimate.
SEA/1002C1F5.00C 28
Risk G-1 The availability of a number of different types of helicopters needed for
material, crew, and equipment delivery has been assumed in the cost estimate.
The actual availability at the time of the construction is conjectural at this
time, and an allowance for alternative delivery methods will be left to the
contractors. (Medium Risk)
The key equipment needs for this project include different types of helicopters. Each has
different uses and capacities, and the costs vary greatly. The availability of the least cost
options is unknown (unknowable) at this time. This risk issue is considered in the contractor’s
domain and did not affect project budget.
H. Construction Logistics and Transportation Issues. The following are four key construction
logistics and transportation risk issues. The potential financial impact of these risk issues has
been incorporated into the assumed ranges of the risk-adjusted project cost estimate.
Risk H-1 The physical access to the transmission line site presents certain constraints
that need to be reflected in the project implementation plan and cost estimate.
The uncertainty of the route leads to uncertainty in physical access options.
An allowance for this uncertainty is recommended to be included in the cost
estimate until a final route is selected. (Medium Risk)
Risk H-2 In addition to physical constraints, the right of entry and reasonable access to
the site may be limited by the mitigation conditions of the permits. Since they
are unknown at this time, an allowance for additional access costs included in
the risk-adjusted project cost estimate. (Medium Risk)
Risk H-3 Equipment delivery to the eastern construction zone in the summer months
may be more difficult than currently envisioned (wetland issues.) An
allowance for this uncertainty and further evaluation during preliminary
engineering is included in the risk-adjusted cost estimate. (Medium Risk)
Risk H-4 The lodging for transmission line construction crews is assumed to be in
motels along the construction route. The implications of this assumption
(reality of supply/demand and impact on tourism) will be addressed during
the environmental impact statement process. Separate worker lodging
facilities (camps) are not anticipated to be needed as currently envisioned.
(Medium Risk)
The risk assessment team was concerned about the likely site access restrictions to be placed on
the construction work. A range of costs has been included in the cost estimate to reflect this
potential cost uncertainty, which will not be fully understood until final permits are obtained.
Schedule. The risk issues discussed above have both potential project cost and project schedule
impacts. The current schedule for project planning is up to 36 months, followed by a 24- to
31-month construction schedule. After reviewing each schedule risk, the team determined that
this schedule adequately reflected the potential risks identified.
SEA/1002C1F5.D0C 29
Risk Analysis
A construction cost risk analysis conducted for the Copper Valley Intertie included:
¢ Integrating the results of the risk assessment workshop into the cost estimates,
¢ Identifying a realistic range of costs for each of the major expenditures for the project based
on level of design detail, and
e Performing a simulation analysis of the range-based cost estimate.
The results of the risk analysis are shown in Table 13 and Figure 1. Table 13 presents the cost
estimate as originally estimated and as a risk-adjusted cost estimate. As shown at the bottom of
the table, the risk analysis for each cost component replaces the provision of a general
contingency like that included in the original estimate.
The risk-adjusted cost estimate shows the expected value of the estimate based on the
recommended cost percent ranges shown. For example, for Structures the original cost estimate
was $7.7 million and the risk-adjusted estimate is $8.1 million. The $8.1 million estimate is the
expected value of the range between $6.9 million (which is calculated from $7.7 million times
90%) and $9.3 million (which is calculated from $7.7 million times 121%).
Two types of distributions were used in the analysis. A triangular 10/90 distribution is
basically a triangular distribution between the 10th and 90th percentile, with the peak of the
triangle being the most likely estimate. This distribution is commonly used as a means of
avoiding the need to include events with very little probability of occurring. Another
distribution type used was the uniform distribution, which is a distribution evenly divided
between two values. This type of distribution is preferred when very little is known about the
potential shape of the distribution but the end points are fairly well known.
As shown in Figure 1, the risk-adjusted cost estimate ranges from $45.4 to $49.8 million for
probabilities of 20 to 80 percent. The high end of this range can largely be traced to four factors:
e The new inclusion of an alternate route allowance, which is a mitigation for the risk that
the least costly construction route will not be the final route selected through the
environmental impact statement process.
e The increased allowance for owners’ costs, which will be needed to secure public support
for the project.
e The increased expected value estimate for foundations, which reflects the wide cost range
and uncertainty about this cost estimate.
e The increased expected value estimate for conductors, which also reflects the wide cost
range and uncertainty about this cost estimate.
The risk-adjusted expected value of project costs is $47.4 million (1993 dollars). It is only a
coincidence that this is the same number as the original cost estimate.
$EA/1002C1F5.00C 30
TABLE 13
Copper Valley Intertie Project
Risk Adjusted Cost Estimate
(1993 Dollar Values)
Risk-Adjusted Ranges
Original Risk-Adjusted ——as % of Original Cost Estimate) _
Cost Category Cost Estimate Cost Estimate Low Most Likely High Risk Distribution Type
A. Transmission Line Construction
‘Structures: 7,717,699 8,073,801 90% 102% 121% Triangular (10th, 90th Percentile)
Foundations 7,598,190 8,915,972 90% 100% 150% Triangular (10th, 90th Percentile) Guys and Anchors 1,226,521 1,252,856 80% 100% Triangular (10th, 90th Percentile)
Framing 2,642,195 2,642,195 90% 100% 110% Triangular (10th, 90th Percentile)
Conductor 6,503,487 7,631,398 84% 110% 154% Triangular (10th, 90th Percentile) Right-of-Way Clearing 2,792,960 2,992,586 90% 105% 125% Triangular (10th, 90th Percentile)
Mobilization 1,284,405 1,367,420 90% 100% 125% Triangular (10th, 90th Percentile)
Extra Work Allowance 1,000,000 914,033, 50% 100% 130% Triangular (10th, 90th Percentile)
Alternate Route Allowance 0 900,000 400,000 2,000,000 Uniform (between values shown)
Subtotal Transmission Line Construction 30,765,457 34,690,262
B. Substation Construction
New Sutton Substation 1,824,316 1,824,316 80% 100% 120% Triangular (10th, 90th Percentile)
Bump Station No. 11 Substation 1,793,903 1,793,903 80% 100% 120% Triangular (10th, 90th Percentile)
Extra Work Allowance 180,911 180,911
Subtotal Substation Construction 3,799,130 3,799,130
C. Engineering Services/Construction Management Engineering Services 3,337,900 3,288,184 85% 105% 110% Triangular (10th, 90th Percentile) Construction Management 2,159,352 2,116,917 5% 6% Uniform (as a % of Construction)
‘Subtotal Engineering and Const. Mgmt. 5,497,252 5,405,100
D. Environmental Services & Permitting 1,405,000 1,314,428 60% 100% 125% Triangular (10th, 90th Percentile)
E. Right of Way Acquisition 713,000 784,300 95% 125% Uniform (between % shown)
F. Owners Costs —1360.392 1,609,763 2% 5% Uniform (as a % of Total Costs)
Total Project Cost (w/o contingency) 43,540,231
Project Contingency Allowance —4.064.125,
Total Project Cost 47,604,356
Total Project Cost: Expected Value From Risk Analysis 47,602,983
Extra Risk Allowance 2.231.017
Total Porject Cost: At 80th Percentile of Risk 49,834,000
SEA/1002C1F5.00C 31
117526.C0.10 + Risk Simulation 1/23/96 * GM <A-C--wrwovv <A-T--wrwonvv
@RISK Simulation Sampling= Monte Carlo
PROJECT COST #Trials=1000
20% Probability | ‘ | 50% Probability $ 45.4 Million —>| <—— $47.4 Million
|
C0 ee L ;
6% poo coso = = = = eeeeees
5% TT i o-oo > --G
O% :
55 37.5 40 42:5 45 47:5 50 52:5 S55 S75 60
Values in Millions
@RISK Simulation Sampling= Monte Carlo
PROJECT COST #Trials=1000
LOO Win min nen Th ane i on
BOZ4d a mh Ti ao iA i ne dnt
COATT Ti ro i |
40% Wii it tii il i ite a ei IC ea
|
| 20% ama rae Tl |
|
O% He T t I I 1 1 +
52 S7.5 40 42:5 45 47.5 50 52:55 55 57:5 60
Values in Millions
Figure 1
Copper Valley Intertie
Project Cost Simulation
All Diesel Alternative
Risk Assessment
As shown in Table 14, the risk assessment team identified 34 potential risks to project cost
(including operations cost) and schedule. These risks were further discussed and then
designated as potential fatal flaws, high, medium or low risks in terms of their potential impact.
As in risk assessments for other power supply alternatives, extraordinary (extremely low
probability) events were not included. This process resulted in the identification of:
¢ No potential fatal flaws (major risks that might result in project termination),
¢ No high risks (major risks with likely cost and schedule implication but not likely to result
in project termination),
e 17 medium risks (important but manageable risks), and
e 16 low risks (possibly important risks but with small likely impacts).
Also included in Table 14 is an indication (check mark) of whether the cost estimate was
adjusted to account for a particular risk, and notes on potential mitigation.
The 17 medium project risks are discussed below.
A. Management and Administration Issues. No key management and administration risk issues
were identified.
B. Finance Availability Issues. No key finance availability risk issues were identified.
C. Regulatory and Permitting Issues. One key regulatory and permitting risk issue was
identified. The potential financial impact of this risk issue has been incorporated into the
assumed ranges of the risk-adjusted project cost estimate.
Risk C-1 State Air Quality Permit acquisition from State of Alaska is considered
uncertain at this time due to the current non-attainment classification of the
airshed at Valdez. The risk is that considerable modeling would be required
for the permit with increased time and cost. (Medium Risk)
D. Environmental and Geotechnical Issues. No key environmental and geotechnical risk issues
were identified.
E. Engineering Planning and Design Issues. One key engineering planning and design risk issue
was identified. The potential financial impact of this risk issue has been incorporated into the
assumed ranges of the risk-adjusted project cost estimate.
Risk E-1 The existing electrical system quality (transmission and distribution) is
uncertain and needs to better understood as part of the preliminary engi-
neering activities. The purpose would be to include all needed system
upgrades at the same time as new diesel units are installed. (Medium Risk)
The risk assessment team believed that an electrical relay protection study and a switchyard
upgrade study would be appropriate during preliminary engineering.
SEA/1002C1F5.00¢ 33
Table 14
Copper Valley All Diesel Altemative
Project Risk Assessment Summary Worksheet Category of Risk
Potential Cost Risk Description of Risk Issue Fatal Flaw __Cost__ Schedule _ Adjustment Notes on Mitigation A. ‘Management and Administration Issues Changing Govemment Regulations (State Air Quality) Low Low 7 Title 5 Compliance Changes Govemmental Support Low Low v
Public Perspective (Natural Environment, Socioeconomics) Low Low v Site Acquisition NA NA Project Management Organization (CVEA) NA NA.
8B. Finance Availability Issues Pre-Construction (CVEA Funding) Low Construction (RUS Loan/Rates) Low NA Operations Cash-Flow (rate impacts and RUS Terms) Low NA
c. Regulatory and Permitting Issues Permit Acquisition (State Air Permit) Medium — Medium 2 Permit Acquisition (Federal REA) Low Low 2
D. Environmental and Geotechnical Issues Weather Conditions NA Low Environmental Restriction on Construction NA NA
Availability of Subgrade Testing to Date Low Low a Archaeological and Historical Findings NA NA
eB Engineering Planning and Design Issues : Design Approvals and Changes Low Low Site Availability and Suitability Low Low Site at Valdez is Questionable Existing System Performance (Electrical Trans. and Dist.) Medium — Medium v Elec. Relay Protection/Switchyard Upgrade Construction Management NA NA Project Team Continuity NA NA Packaging of Bids NA NA
F. Contractor Issues Competitive Availability of Qualified/Skilled Contractors Medium — Medium Level of Specification Detail in Design Drawings Low Low Labor Negotiations/Stoppages (Union Contract Expiration) NA NA
Management of Subcontracts NA NA Change Orders NA NA
Worker Safety NA NA
6. Existing Condition of Structures and Electrical Systems
Condition of Existing Structure/Foundation Low Medium ¢ Usability of Existing Structure Medium Medium v Condition of Existing Fuel Storage Medium — Medium 7 Condition of Existing Diese! Generators Medium — Medium 7 Condition of Existing Electrical Systems. Medium Medium x
H. Equipment and Material Availability Construction Equipment Availability NA NA Diesel Engine Availability Medium — Medium ¥ Long (6 month) Lead Time Needed
Diesel Engine Cost Fluctuation Low NA ¥
Rejects and Defects NA NA
I Construction Logistics and Transportation Laydown Area Limitations-Diesel Engines Medium — Medium v Sequencing of Materials/Covered Storage Laydown Area Limitations-Electrical Equipment Medium — Medium w Covered Storage
Access to Site (Physical and Right of Way) NA NA Mobilization of Material Low Low
Maintenance of Service during Construction Medium — Medium ¥ Demolition/Salvage of Existing Diesel Engines Low Low 2 High Salvage Value Expected Demobilization/Salvage of Existing Electrical Systems Medium Medium 7 Scrap Value Expected
li Start-Up and Commissioning Issues Final Inspection NA NA
K. Operating Company Issues Operating Labor Needed Medium = NA Availability of Diesels (Existing and New) Medium NA Mechanical Age of Existing Diesels Fuel Costs Low NA Range Included in Base Analysis Spare Parts and Labor Support Service (Existing Diesels) Medium NA Poor Manufacturer Support Currently Spare Parts and Labor Support Service (New Diesels) Low NA Good Manufacturer Support Envisioned Maintenance of Diesels (Existing and New) Medium ___NA Mechanical Age of Existing Diesels/High Cost Category of Risk: FF: Major Risk that Might Become a Fatal Flaw High: — Major Risk with Likely Cost and Schedule Implication but Not Fatal Flaw Medium: Important but Manageable Risk Low: Possibly Important but with Small Impact NA: Not Applicable
SEA/1002C1F5.D0C 34
F. Contractor Issues. One key contractor risk issue was identified. The potential financial
impact of this risk issue was not incorporated into the assumed ranges of the risk-adjusted
project cost estimate.
Risk F-1 The availability of a number of qualified/skilled contractors to bid on this
project is uncertain at this time. Construction is not currently envisioned
earlier than 3 years from now, and competing projects may result in a low
number of bids received. This risk may result in higher than anticipated bids.
(Medium Risk)
The risk assessment team was concerned about the potential conflict of other Alaska con-
struction projects. The need for a qualified and experienced contractor is high to ensure project
success. No budget allowance was, however, included to reflect the potential of non-
competitive bids. Alternative project delivery methods (such as negotiated contracts) should, if
necessary, be considered during preliminary engineering as an alternative to traditional low
bid award.
G. Existing Condition of Structures and Facilities. Five key risk issues were identified for this
category. The potential financial impact of these risk issues has been incorporated into the
assumed ranges of the risk-adjusted project cost estimate.
Risk G-1 The condition of the existing structure and foundation is currently uncertain
and needs to be ascertained as part of preliminary engineering. (Medium
Risk)
Risk G-2 The usability of the existing structure to house additional generation units is
currently uncertain and needs to be ascertained during preliminary
engineering. (Medium Risk)
Risk G-3 The condition of the existing fuel storage system is currently uncertain and
needs to be ascertained as part of preliminary engineering. (Medium Risk)
Risk G-4 The condition of the existing diesel generators is currently uncertain and
needs to be ascertained as part of preliminary engineering. (Medium Risk)
Risk G-5 The condition of the existing electrical system is currently uncertain and
needs to be ascertained as part of preliminary engineering. (Medium Risk)
H. Equipment and Material Availability. One key equipment and material availability risk issue
was identified. The potential financial impact of this risk issue was not incorporated into the
assumed ranges of the risk-adjusted project cost estimate.
Risk H-1 The diesel generators need to be delivered over a period of 5 years and
consistency in design/replacement parts need to be reasonably assured. Also a
reasonably long lead time is needed for ordering the diesel generators (6
months). (Medium Risk)
The risk assessment team was concerned about the potential for ordering a number of gen-
erators over an extended period of time (5 years.) Maintenance and operational ease will be
based on having similar units available when needed.
$EA/1002C1F5.D0C 35
|. Construction Logistics and Transportation Issues. The following are four key construction
logistics and transportation risk issues. The potential financial impact of these risk issues has
been incorporated into the assumed ranges of the risk-adjusted project cost estimate.
Risk I-1 The availability and usability of a laydown area for the diesel generators is
currently uncertain but can be ascertained during preliminary engineering
investigations. Covered storage will be needed. (Medium Risk)
Risk I-2 The availability and usability of a laydown area for the new electrical
equipment is currently uncertain but can be ascertained during preliminary
engineering investigations. Covered storage will be needed and adequate
space for sequencing of materials will be needed. (Medium Risk)
Risk I-3 The maintenance of service during construction is essential and a plan will
need to be developed during engineering. (Medium Risk)
Risk I-4 Demolition and salvage of existing electrical equipment is currently uncer-
tain. It is likely that the equipment can be sold for scrap value without
disposal cost but this will need to be verified. All allowance for this risk has
been included in the risk-adjusted cost estimate. (Medium Risk)
The risk assessment team was concerned that the current site is fully used and that suitable
staging /laydown areas might be difficult to find. Similarly, disposal /salvage of existing
generators and equipment is typically not an issue, but because of the location, may pose a risk.
A range of costs have been included in the cost estimate to reflect this potential cost uncertainty
which will not be fully understood until preliminary engineering.
J. Start-Up and Commissioning Issues. No key start-up and commissioning issues were
identified.
K. Operating Issues. Five key operating company issues were identified. Recommendations
for risk-adjusted operating costs have been included.
Risk K-1 The number of workers required to operate and maintain the system is
somewhat uncertain at this time. The emergency response requirement for the
diesels may require a larger number of staff than would otherwise be
required. (Medium Risk)
Risk K-2 The availability (reliability) of the existing diesel generators is currently
uncertain due to their age. This information will be more easily estimated
once a condition survey is completed. (Medium Risk)
Risk K-3 The uncertainty of future fuel costs is considered a risk for this project. The
current range of forecasts are used in a scenario planning process as a means
of estimating their effect. Although no risk-adjusted fuel cost estimate is
used, the risk is acknowledged. (Medium Risk)
Risk K-4 The future spare parts availability for the existing diesel generators is cur-
renily uncertain due to their age. This information will be more easily
estimated once a condition survey is completed. (Medium Risk)
SEA/1002C1F5.D0C 36
Risk K-5 The future maintenance needs for the existing diesel generators is currently
uncertain due to their age. This information will be more easily estimated
once a condition survey is completed. (Medium Risk)
Schedule. The risk issues discussed above have both potential project cost and project schedule
impacts. The project schedule was evaluated from the perspective of whether it included a
reasonable allowance for the time delays associated with each of the risks. The current
schedule for project planning is 9 to 12 months, followed by a7 to9 month construction
schedule (for the first generating units). After reviewing each schedule risk, the team
determined that this schedule adequately reflected the potential risks identified.
Risk Analysis
The results of the risk analysis are shown in Table 15 and Figure 2. Table 15 presents the cost
estimate as originally estimated and as a risk-adjusted cost estimate. As shown in Figure 2, the
risk-adjusted project cost ranges from $10.0 to $11.7 million. This range is generally lower than
the $11.6 million estimated by R.W. Beck and the $12.1 million estimated by CH2M HILL. The
difference can be largely traced to two factors:
e The new inclusion of salvage value of the replaced diesel generators and electric equipment.
e Ahigh original estimate for permitting and engineering.
The distribution of the project cost range is shown in Figure 2. As shown on this figure, a range
between $9.96 million and $11.70 million represents our recommended risk-adjusted budget for
conditions likely to occur.
SEA/1002C1F5.00C 37
TABLE 15
All Diesel Alternative
Risk Adjusted Cost Estimate
(1993 Dollar Value)
Risk-Adjusted Ranges
(as % of Original Cost imate)
Original Risk- Cost Category Cost Estimate Adjusted __ Difference Low _MostLikely High _Risk Distribution Type
Contractor Costs Structures and Improvements 2,000,000 2,172,603 172,603 90% 100% 130% Triangular (10th, 90th Percentile) Engine Generator & Accessories 6,214,000 6,214,000 0 80% 100% 120% Triangular (10th, 90th Percentile) Substation & Transmission 550,000 621,199 71,199 85% 100% 145% Triangular (10th, 90th
Percentile) Delivery 186,000 186,000 0 90% 100% 110% Triangular (10th, 90th Percentile)
Subtotal Contractor Costs 8,950,000 9,193,801 243,801
Demolition and Salvage Existing Diesels and Electrical Equipment 0 (413,951) (413,951) (700,0 (500,000) (100,0 Triangular (10th, 90th 00) 00) Percentile)
Permitting 500,000 400,000 (100,000) 60% 100% Uniform(as a % of Original
Cost) Engineering, Design, & Construction Management 1,491,000 1,267,350 (223,650) 70% 100% Uniform(as a % of Original Cost) Owners Costs 0 365,652 365,652 2% 5% Uniform(as a % of Total Cost)
Subtotal Project Cost (w/o contingency) 10,941,000 10,812,852 (128,148)
Project Contingency 1,184,000 0 Project Risk Allowance (See Note 1) 0 888,148 (295,852)
Total Project Cost 12,125,000 11,701,000 (424,000)
SEA/1002C1F5.D0C
117526.C0.10 + Risk Simulation Fig.2 + 1/30/96 « GM <iA---wrwowvv <AT-TFT-wWrwmwonvv
@RISK Simulation Sampling= Monte Carlo
PROJECT COST #Trials=1000
15% ~
12% *
9.00%
20% Probability $ 9.96 Million
5 6 7 8 9
Values in Millions
1007
80%"
10
|. 50% Probability <— $10.84 Million
| < 80% Probability
| $ 11.70 Million
'
' ,
'
/
11 12 13 14 15
@RISK Simulation Sampling= Monte Carlo
PROJECT COST
60% P-- >"
40%-
20%"
#Trials=1000
O%
11 12 13 14 15
Values in Millions
Figure 2
All Diesel Alternative
Project Cost Simulation
Silver Lake Option C
Risk Assessment
In the risk assessment workshop, the risk assessment team identified 31 potential risks to
project cost and schedule. These risks were further discussed and then designated as potential
fatal flaws or as high, medium or low risks in terms of their potential impact. Extraordinary
(extremely low probability) events were not included. This process resulted in the identifica-
tion of the following risk factors for project construction:
¢ 2potential fatal flaws (major risks that might result in project termination),
e 11 medium risks (important but manageable risks), and
¢ 18 low risks (possibly important risks but with small likely impacts).
These risks are summarized in Table 16. Also included in this table is an indication (check
mark) as to whether the risk was integrated into the risk-adjusted cost estimate and notes on
potential mitigation for these risks.
The two potential fatal flaws and 11 medium to high risks are discussed below. This discussion
is organized according to the same risk categories as shown in Table 13 and includes a
description of risks, costs and schedule impacts, and suggested methods to mitigate the risks.
A discussion on potential schedule risk is also follows.
A. Management and Administration Issues. The following are three key management and
administration risk issues. The potential financial impact of these risk issues has been
incorporated into the assumed ranges of the risk-adjusted project cost estimate.
Risk A-1 The public perspective on developing the project will be expressed primarily
through the FERC licensing process and the Chugach Native Corporation’s
ownership of the principal project lands. No known project opposition
currently exists, but could develop as planning proceeds. (Medium Risk)
Risk A-2 Site acquisition of the required land rights from the Chugach Native
Corporation are vital to the development of the project. Chugach has
apparently expressed an interest to negotiate on this matter. (Medium Risk)
Risk A-3 This project alternative has assumed that Whitewater Engineering
Corporation will be responsible for full development. If a public agency were
to assume this responsible additional costs and scheduling delays could occur.
(Medium Risk)
B. Finance Availability Issues. One key finance availability risk issue was identified. The
potential financial impact of this risk issue has not been incorporated into the assumed ranges
of the risk-adjusted project cost estimate.
Risk B-1 The project developer may have difficulty in acquiring sufficient financing to
carry the project through the FERC licensing process. The most likely risk
will be project delays when the required financing is being pursued.
(Medium Risk)
SEA/1002C1F5.D0C 40
TABLE 16
Silver Lake Option-C Project
Project Risk Assessment Summary Worksheet.
Category of Risk
Potential Cost Risk
Description of Risk Issue Fatal Flaw Cost Schedule Adjustment Notes on Mitigation
A. Management and Administration Issues
Changing Goverment Regulations Low Low
Government Support Low Low
Public Perspective (Natural Environment, Medium Medium Vv Chugach Native Corporation, FERC
Socioeconomics)
Site Acquisition (Chugach Native Corp.) Medium Low Vv Negotiate with Native Corporation
Project Management Organization (Whitewater Medium Medium v Cost if Publicly Developed
Development)
B. Finance Availability Issues
Pre-Construction (Developer Funding) Low Medium v Initial Capital Needed
Construction (Developer Funding) Low Low Available if Project Proceeds
C. Regulatory and Permitting Issues
Permit Acquisition
Federal (FERC License Process) FF Stream Flows
Archaeological and Historical Findings Low Low
D.
Weather Conditions (During Construction) Medium Medium Vv Two Months to Build Dam
Environmental Restriction on Construction Low Low
Availability of Subgrade Testing to Date Medium Medium Vv Risk Adjusted Cost Estimate
£. — Engineering Planning and Design Issues
Route Selection Low Low Options Available
Weather Design Criteria Medium Medium v Weather-Sensitive Materials
System Performance FF Overstated Energy
Construction Management (Developer) Medium Medium Vv Risk Adjusted Cost Estimate
F. Contractor Issues
Competitive Availability of Qualified Contractors Low Low
Level of Specification Detail in Design Drawings Low Low FERC to Review Design
G. _ Existing Structures and Equipment and Material
Availability
Equipment Availability Low Low
Materials Availability (Concrete Aggregates) Medium Medium Vv Import Materials/Redesign
Equipment Malfunctions and Failures Low Low
Material Cost Fluctuations Low Low
H. Construction Logistics and Transportation
Laydown Area Limitations Low Low
Access to Site (Blasting Requirements) Medium Medium Vv Risk Adjusted Cost Estimate
Materials Delivery Low Low
Maintenance of Service during Construction Low Low
Mobilization Low Low
Demobilization Low Low
rE, Start-Up and Commissioning Issues
Final Inspection Low Low
J. Operating Company Issues
Maintenance of Facilities Low Low
Power Sales Agreements Medium Medium v Risk Adjusted Cost Estimate
Category of Risk:
FF: Major Risk that Might Become a Fatal Flaw
High: Major Risk with Likely Cost and Schedule Implication but Not Fatal Flaw
Medium: Important but Manageable Risk
Low: Possibly Important but with Small Impact
SEA/1002C1F5.D0C 4
C. Regulatory and Permitting Issues. One permitting issue was identified; it is a potential fatal
flow for this project alternative.
Risk C-1 The FERC licensing process will establish both the amount of flow that will
need to be maintained in the diverted reach of Duck Creek and the seasonal
flow patterns to be maintained in the reach of Duck Creek below the
proposed powerhouse site. Adverse rulings on either issue, particularly the
latter, could restrict power generation to point that the project becomes
economically infeasible (Potential Fatal Flaw)
D. Environmental and Geotechnical Issues. The following are two key environmental and
geotechnical risk issues. The potential financial impact of these risk issues has been
incorporated into the assumed ranges of the risk-adjusted project cost estimate.
Risk D-1 Typically there is only about two months of predictably dry weather at the
site, late spring, which is suitable for construction of the proposed roller
compacted concrete dam. While this amount of time should normally be
sufficient, unexpected rains could add significant delays and costs to the
project.. (Medium Risk)
Risk D-2 Reportedly, little subsurface site investigation has been done to date. These
studies are critical to establishing the local availability of suitable aggregates
for constructing the dam and the amount of rock blasting that will be required
for constructing the access road and pipeline.. (Medium Risk)
E. Engineering Planning and Design Issues. The following are three key engineering planning
and design risk issues. One of these is a potential fatal flaw. The potential financial impact of
the other two risk issues has been incorporated into the assumed ranges of the risk-adjusted
project cost estimate.
Risk E-1 Site weather conditions and the availability of low weather-sensitive
aggregates for construction of the dam are critical to this project alternative.
The availability of suitable aggregates can be determined during the early
explorations phases of project development. (Medium Risk)
Risk E-2 The projects feasibility is extremely sensitive to the amount of annual flows
entering Silver Lake. To date, accurate flow gaging data is virtually non-
existent. If the actual flows that have been assumed have been overstated by
10 to 15 percent, this project could be unfeasible. (Potential Fatal Flaw)
Risk E-3 The entities that will actually construct the project, manage the construction
and ultimately own the facility have not been fully identified yet. (Medium
Risk)
G. Existing Condition of Structures and Facilities and Equipment and Material Availability Issues.
The following key risk issue was identified for this category. The potential financial impact of
this risk issue has only partially been incorporated into the assumed ranges of the risk-adjusted
project cost estimate.
SEA/1002C1F5.D0C 42
Risk G-1 The availability of suitable local aggregates is critical to the construction of
the roller-compacted concrete dam. If the materials have to be hauled any
appreciable distance or just aren’t readily available, both the cost and
schedule will be adversely impacted. (Medium Risk)
H. Construction Logistics and Transportation Issues. The following key construction logistics
and transportation risk issues was identified. The potential financial impact of this risk issue
has been incorporated into the assumed ranges of the risk-adjusted project cost estimate.
Risk H-1 The amount of blasting that will be required for construction of the project
access road and installation of the buried piping is generally unknown at this
time. Some blasting has been assumed. It has also been generally assumed
that the excess excavation materials can be readily disposed of on site. Both
assumptions could effect project cost and schedule. (Medium Risk)
J. Operating Issues. The following key risk issue was identified for this category. The potential
financial impact of this risk issue has only partially been incorporated into the assumed ranges
of the risk-adjusted project cost estimate.
Risk J-1 The final power sales agreement for the project will include the power
purchaser’s requirements for the design, construction, and the ultimate
operation of the project. This will probably have some effect on the design
and construction of the project. (Medium Risk)
Schedule. The risk issues discussed above have both potential project cost and project schedule
impacts. The current schedule for project planning is up to 36 months, followed by a 24- to
31-month construction schedule. After reviewing each schedule risk, the team determined that
this schedule adequately reflected the potential risks identified.
Risk Analysis
A construction cost risk analysis conducted for Silver Lake Option C. The results of this risk
analysis are shown in Table 17 and Figure 3. Table 17 presents the cost estimate as originally
estimated and as a risk-adjusted cost estimate.
The distribution of the project cost range is shown in Figure 1. As shown on this figure, a range
between $34.1 million and $37.4 million represents the risk adjusted cost estimate for conditions
likely to occur.
SEA/1002C1F5.00C 43
TABLE 17
Whitewater Silver Lake Hydropower Alternative C
Risk Adjusted Cost Estimate
(1993 Dollars)
Risk-Adjusted
(as a % of Original Cost Estimate)
Original Risk-Adjusted
Cost Category Cost Estimate Cost Estimate Low Most-Likely High Risk Distribution Type
Land and Land Rights 1,215,000 1,615,000 1,215,000 1,415,000 2,215,000 Triangular
Structures and Improvements 1,512,500 1,577,574 90% 100% 120% Triangular (10th, 90th Percentile)
Reservoir, Dams, and Waterways 14,059,000 15,063,548 94% 110% 136% Triangular (10th, 90th Percentile)
Turbines and Generators 3,900,000 4,067,795 90% 100% 120% Triangular (10th, 90th Percentile)
Accessory Electrical Equipment 910,000 949,152 90% 100% 120% Triangular (10th, 90th Percentile)
Miscellaneous Mechanical Equipment 50,000 52,151 90% 100% 120% Triangular (10th, 90th Percentile)
Structures and Improvements (Trans. Facilities) 68,000 70,926 90% 100% 120% Triangular (10th, 90th Percentile)
Substation Equipment and Structures 325,000 338,983 90% 100% 120% Triangular (10th, 90th Percentile)
Fixtures, Conductors, and Devices 6,440,000 6,716,697 80% 100% 130% Triangular (10th, 90th Percentile)
Mobilization 2.000.000 —1.827.202 60% 100% 120% Triangular (10th, 90th Percentile)
Direct Construction Cost (Include. Land Rights) 30,479,500 32,279,729
FERC and Other Licensing Cost 800,000 1,266,667 800,000 1,000,000 2,000,000 _— Triangular
Design Engineering 750,000 750,000 90% 100% 110% Triangular (10th, 90th Percentile)
Construction Management 1,000,000 1,000,000 90% 100% 110% Triangular (10th, 90th Percentile)
Owners Cost Allowance Saal —352.964 1% Percent of Project Cost
Subtotal Project Cost (w/o Contingency) 33,029,500
Contingency (20%) 6,605,900
Total Project Cost 39,635,400
Total Project Cost: Expected Value From Risk 35,649,360 Analysis
Extra Risk Allowance 1,786,540
Total Project Cost at 80th Percentile of Risk 37,435,980
seal1002C1F5.doc
SEA/1002C1F5.00C
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PROJECT COST
20% Probability |
$ 34.05 Million >
23 26 29 32
Values
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| 50% Probability
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@RISK Simulation Sampling= Monte Carlo
PROJECT COST 1007
80%
60% 7°77 >
40%7
20%
20 23 26 29 32
35
Values in Millions
38 41 +44 «47° 50
Figure 3
Silver Lake Option C
Project Cost Simulation