HomeMy WebLinkAboutKing Cove Hydro Electric Feasibility Study Feb 1991U
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February 1991
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HDR Engineering, Inc.:
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AL4SKA ENERGY AUTHORITY
This study was prepared under the direction of the Alaska Energy Authority by:
HDR Engineering, Inc.
4446 Business Park Boulevard
Building B
Anchorage, Alaska 99503
The technical content of this report has been reviewed and is accepted.
Robert L.chwebel
Project Manager
G�y D. mith
Manager of Rural Projects
Date
,STy�- 7 /
Date
The conclusion of the benefit - cost analysis presented in the report is accepted.
Richard Emerman
Senior Economist
.1 ' zS /qv
Date '
This project is recommended for further development and review of financing
T
David Denig-Chakroff Dat
Director, Rural Programs
KNGCV2 DOC 2540-41
KING COVE HYDROELECTRIC PROJECT
FEASIBILITY STUDY
Prepared for:
Alaska Energy Authority
701 East Tudor Road
Anchorage, Alaska 99519
Prepared by:
HDR Engineering, Inc.
4446 Business Park Boulevard
Building B
Anchorage, Alaska 99503
February 1"]
TABLE OF CONTENTS
Pave
EXECUTIVE SUMMARY ...................................... 1
1.0 INTRODUCTION ......................................... 4
1.1 SCOPE OF THIS REPORT ....................... ..... 4
1.2 PROJECT HISTORY AND PREVIOUS STUDIES .... .... ...... 4
1.3 ACKNOWLEDGEMENTS 5
2.0 PROJECT AREA . ... .. ... ... ... .. . .. . .. . .. .. ....... ... ... 6
2.1 PROJECT LOCATION ................ .......... ..... 6
2.2 PROJECT AREA GEOLOGY ... _ .. ... ..... ....... .. ... 11
2.3 STREAM FLOW DATA ........... ............ .. ..... 12
2.4 PEAK DISCHARGES 16
3.0 HYDROELECTRIC PROJECT ALTERNATIVES ....................
18
3.1
INTRODUCTION.................... ..............
18
3.2
MOBILIZATION ....................... ...........
18
Options Considered .................................
18
Option Selected ...................................
18
Further Study .....................................
18
3.3
DIVERSION ...... ...... . ................... .....
19
Options Considered ................... ......... ....
19
Option Selected ...................................
20
Further Study .....................................
20
3.4
PENSTOCK .....................................
25
Options Considered ....... . ........ .. ...............
25
Option Selected .... ........... ....... .. ..... I .... 1
26
Further Study .. ...... ... ... .......................
27
3.5
POWERHOUSE ...................................
27
Options Considered .................................
27
Option Selected ...................................
29
3.6
TRANSMISSION LINE ... ... ................... .....
31
Options Considered .............. . ..................
31
Option Selected ............................. . .....
31
Further Study . ........ ...... ... ... ............ ....
32
4.0 PROJECT ENERGY PRODUCTION ............................ 33
5.0 PROJECT COST ........................................ 35
07073,003:N:8;D10
6.0 LOAD FORECAST ....................................... 36
6.1 EXISTING GENERATION CAPACITY .................... 36
6.2 ELECTRICAL DEMAND ...... ... ....... .. .. ......... 36
6.3 CURRENT ENERGY COSTS ........ .................. 38
6.4 FUTURE ELECTRICAL DEMAND ...................... 41
6.5 PETER PAN SEAFOODS ........................ I .... 41
7.0 ECONOMIC ANALYSIS ................................... 43
8.0 PROJECT IMPLEMENTATION ...............................
55
8A
REGULATORY REQUIREMENTS .... .. .................
55
Federal Energy Regulatory Commission (FERC) ...............
55
U.S. Army Corps of Engineers (COE) .....................
55
U.S. Environmental Protection Agency (EPA) .................
56
U.S. Fish and Wildlife Service (USF&WS) ..................
56
Alaska Department of Natural Resources (ADNR) ..............
56
Alaska Department of Conservation (ADEC) ..... _ _ ..........
56
Alaska Department of Fish and Game (ADF&G) ...............
57
Division of Governmental Coordination (DGC) ................
57
8.2
LOCAL REQUIREMENTS ............................
59
8.3
RIGHTS -OF -WAY .... ..... . ... ............ ...... ,
59
Federal .........................................
59
State..........................•...•...........
59
Local..........................................
59
Private .........................................
60
8.4
PROJECT SCHEDULE ..............................
60
9.0 RECOMMENDATIONS .................................... 62
10.0'BIBLIOGRAPHY....................................... 63
APPENDICES
APPENDIX 1 FLOW RECORD EVALUATION
APPENDIX 2 DETAILED COST ESTIMATE
07073.003:H:8:D10
FIGURE
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
LIST OF FIGURES
Page
COMMUNITY LOCATION .. .. .... .. ... .. .. ... ... .. . ... .. 7
KING COVE ......................................... 8
MT. DUTTON AND STUDY AREA .......................... 9
PROJECT AREA AND COMPONENTS ........................
10
DELTA CREEK FLOW DURATION CURVE .................... 13
DELTA CREEK AVERAGE MONTHLY FLOWS .................. 14
DELTA CREEK PEAK FLOW FREQUENCY CURVE ...... . ........ 17
DIVERSION LOCATION ..... ............................ 21
CLEARWATER TRIBUTARY DIVERSION ..... . ................ 22
GLACIAL TRIBUTARY DIVERSION PLAN AND PROFILE .......... 23
GLACIAL TRIBUTARY DIVERSION CROSS-SECTION 24
TYPICAL ACCESS ROAD AND PIPE BEDDING SECTION ..... . . .... 28
HYDROPOWER POTENTIAL AND MONTHLY LOAD DISTRIBUTION ... 40
KING COVE HYDROELECTRIC, CITY LOAD ONLY; SENSITIVITY
ANALYSIS OF 30 YEAR ECONOMIC ANALYSIS ................. 53
KING COVE HYDROELECTRIC, CITY AND PETER PAN LOADS;
SENSITIVITY ANALYSIS OF 30 YEAR ECONOMIC ANALYSIS ....... 54
07073.003:N:s:n10
LIST OF TABLES
TABLE
Pa.e
I PROJECT SUMMARY ................................... 3
2 PROJECT COMPONENTS ................................ 11
3 AVERAGE MONTHLY FLOWS AND ANNUAL FLOWS AT DELTA CREEK
GAUGING STATION .................................... 16
4 POTENTIAL ENERGY GENERATION FROM DELTA CREEK .... .. ... 30
5 MONTHLY ENERGY GENERATION POTENTIAL . ... .. ... .. .. ... 34
6 PROJECT COST SUMMARY . . .. ........................... 35
7 HYDROPOWER POTENTIAL AND MONTHLY LOAD DISTRIBUTION; CITY
LOAD ONLY, 700 kW PROJECT ................. _ .......... 37
8 HYDROPOWER POTENTIAL AND MONTHLY LOAD DISTRIBUTION; CITY
AND PETER PAN LOAD, 700 kW 'PROJECT .................... 39
9 SUMMARY OF EXISTING DIESEL ELECTRIC POWER PLANT COSTS FOR
CITY OF KING COVE .................... , ... ........... 41
10 KING COVE HYDROELECTRIC FEASIBILITY, ECONOMIC ANALYSIS; CITY
LOAD ONLY .......... I...I..I.............. I........ 44
11 KING COVE HYDROELECTRIC FEASIBILITY, ECONOMIC ANALYSIS; CITY
AND PETER PAN LOADS ................................ 47
07073.003:N :8 03 0
EXECUTIVE SUMMARY
INTRODUCTION
Previous studies have recommended development of Delta Creek near King Cove for
hydroelectric generation. This study reevaluates those studies and updates the feasibility of the
project using current construction costs, load forecasts, and economic parameters.
PROJECT AREA
Delta Creek is located on the south side of Mt. Dutton, five miles north of King Cove, Alaska.
A glacial branch and a clearwater branch of Delta Creek would be diverted to produce power.
Hydrologic analysis of the basin showed an average annual flow of 37 cubic feet per second.
HYDROELECTRIC PROJECT ALTERNATIVES
This study reevaluates and update previous hydroelectric development schemes for Delta Creek,
The selected development scenario is summarized in Table 1.
PROJECT ENERGY PRODUCTION
With the proposed development scenario, Delta Creek would be able to produce an estimated
3940 MWh per year through use of a 700 kW turbine and generator.
PROJECT COST
Development of Delta Creek for hydroelectric generation has an estimated total cost of
$5,700.000. This cost includes construction of items listed in Table 1 for design,
administration, and construction inspection. This cost does not include the costs associated with
obtaining the necessary permits, licensing under FERC, or performing any required mitigation
for effects the project might have on wetlands or fish habitat.
LOAD FORECAST
The City of King Cove has a present electrical demand of approximately 2,100 MWh per year.
The City demand is estimated to increase by 2.5 percent per year to an approximate demand of
3,800 MWh per year in 2014. The City demand could be met through this hydroelectric project,
with backup diesel generation used during for demand peaks, hydroelectric maintenance, and low
flow periods. If Peter Pan Seafoods' processing plant's electrical demands are included, the
entire electrical generation from Delta Creek could potentially be used at the present time.
07073.003:N :8 010
Actual use may vary, however, as hydroelectric generation peaks may not correspond to peaks
in the demands of the City and Peter pan.
ECONOMIC ANALYSTS
An economic analysis comparing the cost of diesel generation and the cost of hydroelectric plus
diesel backup generation over a 34-year period was performed for this project. With the
assumptions used for this study, the project has a base case cost to hydroelectric case cost of
1.02. Projects with cost -to -cost ratios greater than 1.0 are defined as feasible. This project is
defined as feasible,
PROJECT IMPLEMENTATION
Many permits will be required to construct and operate a hydroelectric project on Delta Creek.
These permits will have to be obtained prior to design of this project,
It is estimated that the permitting, design, construction process, and plant commissioning will
take approximately three years from the decision to build the project.
RECOMMENDATIONS
The project economic analysis indicates that a hydroelectric project is feasible in King Cove.
The next step should involve the thorough investigation of the environmental and permitting
issues through meetings with permitting agencies to discuss the project in detail. Once
regulatory issues are resolved, project design and implementation should begin.
07073.003:y:8:nia 2
TABLE 1
SUMMARY OF PROJECT FEATURES
Name of Project
King Cove Hydroelectric Project
Project Location
Delta Creek on the Alaska Peninsula approximately five miles north of King
Cove, Alaska
Intake
Clearwater Tributary - submerged manifold of stainless steel cylinder
screens connected behind a sheetpile dam.
Glacial Tributary - plate type screens with sheet pile diversion weir.
Reservoir
Small reservoir on Clearwater Tributary, none on Glacial Tributary
Elevation: 465 feet
Average Annual Basin Flow: 37 cubic feet per second (cfs)
Penstock
Total Length: Two at 250 feet joining one at 6,000 feet, buried with one
trestle stream crossing
Diameter: 250 feet of 24 and 30 inch, and 6,000 feet of 32 inches
Material: Steel
Flow Continuation
Open channel tailrace to Delta Creek
Powerhouse
Size: 35 feet by 50 feet or 35 feet by 35 feet
[Number of Units: one or two
Type of Turbine: Turgo
Flow: 50 cfs
Head:
Gross: 255 feet
Net: 225 feet
Power: 938 hp
Generator Ratino: Power 700 kW
Auxiliary Unit
Existing icing Cove Diesel Generators, two-300 kW and one-500 kW, with
future upgrades
Transmission Line
Voltage: 12.47 kV
Length: 5 miles
Type: Buried cable
Average Annual Energy
3940 MWh
Estimated Project Cost
$5,700,000 (3990 dollars)
07073.003:N:8:Dio
1.0 INTRODUCTION
1.1 SCOPE OF THIS REPORT
In October 1990 HDR Engineering, Inc. was contracted by the Alaska Energy Authority (AEA)
to review the existing reports and data concerning the King Cove hydroelectric project; to
summarize this information; and to determine project feasibility using current and projected
electrical load information and diesel fuel costs. No additional data collection was authorized.
A reconnaissance trip to King Cove was taken in November 1990 to examine the project area
and to discuss the project with City officials. The information collected at the time was also
used in preparation of this report. The numbered bibliography documents the sources used
during report preparation these sources are cross-referenced in the text. The findings of the
document review and feasibility analysis are in the Section 9.0, Recommendations, of this
report.
1.2 PROJECT HISTORY AND PREVIOUS STUDIES
Two potential hydropower sites near King Cove were evaluated in 1980 by EBASCO Services,
Inc. for the Alaska District Corps of Engineers. A site on Delta Creek was identified as the
most economical, with a benefit -cost ratio between 3.6 and 5.8, depending on the plant
utilization factor.
In July 1981, CH2M Hill completed a Reconnaissance Study of Energy Requirements and
Alternatives for King Cove. The study evaluated alternative sources for meeting the future
electricity requirements of King Cove, including wind, peat and coal combustion, small
hydropower, tidal and solar power, and continued use of centralized or decentralized diesel -
powered generators. The report also analyzed the potential for waste heat recovery from
generators for building heat. The reconnaissance study rejected wind, peat, coal, tidal and solar
power options based on economic, environmental and technical grounds. It dismissed waste heat
recovery due to a lack of buildings with significant heating requirements in the vicinity of the
power plant. The study recommended a more detailed investigation to determine the feasibility
of a hydro -project on Delta Creek, including a stream flow measurement program.
In response to the reconnaissance study, a King Cove hydroproject feasibility study began in
September 1981, followed by a stream flow monitoring program on Delta Creek in January
1982. The Feasibility Study for King Cove Hydroelectric Project, completed by DOWL
Engineers in June 1982, evaluated four potential hydropower sites in addition to the Delta Creek
site and concluded that upper Delta Creek was the best available hydroproject site in the vicinity
of King Cove. A conceptual design and economic analysis for the project were developed as
part of the study.
07M.003:V:8:D10 4
Based on the results of the 1982 study, the stream flow monitoring program was continued and
a number of environmental, geotechnical, and hydrologic investigations were initiated. Field
surveys were conducted in late 1982 and early 1983 to obtain fish counts, to update hydrologic
data, and to determine the proposed project's impact on fisheries. A geotechnical study of the
proposed diversion site conducted in 1984 by Alaska Department of Natural Resources, Division
of Geological and Geophysical Surveys (USGS) concluded seepage rates under the proposed
diversion would be acceptable, but adverse sediment transport conditions in Delta Creek would
have to be addressed in the design of the hydroelectric system.
In 1985, the Alaska Energy Authority (AEA) conducted a detailed assessment of the existing
electrical generation and distribution systems of both the City of King Cove and Peter Pan
Seafoods to determine interfacing requirements for the proposed hydroelectric system. They also
collected load data from both the City and Peter Pan. Design modifications to the earlier
feasibility study were initiated in 1986 to address 'sediment transport conditions, to meet existing
system interfacing requirements, and to size the project on updated flow data and load
projections. AEA used this new information to complete the King Cove Hydroelectric Study,
July 1988, which recommended alternate approaches to the project, depending on electricity
sales to the Peter Pan cannery. A smaller project was recommended to meet only the city's
needs and a larger project was developed to include possible sales to the cannery: The cost -to -
cost ratios developed (hydropower cost to base case costs) for either scenario ranged from 1.3
to 1.9, depending on cost assumptions and interest rates used:
1.3 ACKNOWLEDGEMENTS
This study was funded by the AEA, with Mr. Robert Schwebel as AEA Project Manager. HDR
Engineering, Inc. thanks the City of King Cove, Mr. Scott Thompson, Mr. Bob Dryden, Mr.
James Dryden, and others who provided comments during the preparation of this document.
07073.003:N;8:n10 5
2.0 PROJECT AREA
2.1 PROJECT LOCATION
The City of King Cove is located near the terminus of the Alaska Peninsula, approximately 625
miles southwest of Anchorage (Figure 1). King Cove (Figure 2 and report cover) was founded
in 1911 with the construction of a salmon cannery. Due to its location near the center of
commercial fishing grounds, the harbor and seafood processor now serve as a hub of North
Pacific fishing activity. The cannery, currently owned by Peter Pan Seafoods, employs over 300
people on a year-round basis and processes salmon, bottomfish, and crab.
King Cove has approximately 850 residents (19). These residents are employed in fishing
industry, government, and private sector jobs. The economy of King Cove is considered stable.
The City is served by regular barge service from Seattle and scheduled air carriers from Cold
Bay. The road system extends throughout the town and to the airport and Delta Creek near the
proposed hydroelectric powerhouse, approximately five miles north of town. There are no roads
connecting King Cove to other communities.
The proposed hydroelectric project is located near the airport on Delta Creek, approximately five
miles north of the City. Delta Creels drains the southwest slope of 4,884-foot Mt. Dutton
(Figure 3), a non -active volcano, whose glaciers on the upper slopes of Mt. Dutton feed Delta
Creek. These glaciers, along with limited vegetation cover on the upper mountain slopes, make
Delta Creek very turbid with a high sediment load.
The Delta Creek drainage basin above the proposed diversions is approximately 3.63 square
miles and contains small glaciers on the south slope of Mt. Dutton. Two tributaries join at the
proposed diversion site; a smaller, clear -water tributary and a larger, glacial tributary. After
their confluence, Delta Creek is confined to a narrow, relatively steep, straight canyon until it
reaches the King Cove airport. Near the airport the creek develops a braided channel and has
formed an alluvial fan. The creek remains braided from the airport to its mouth in Lenard
Harbor.
The proposed diversions would be located near the confluence of the two previously mentioned
tributaries of Delta Creek, at an elevation of approximately 465 feet (Figure 4). The penstock
would extend from the diversions through the relatively steep portions of the creek to a
powerhouse located where the stream gradient flattens to the gentler valley slopes. The
powerhouse would be located at approximately 210 feet in elevation, one-half mile from the
airport. A transmission line would carry generated power from the powerhouse, down the
existing airport -to -City road, to the King Cove distribution system, a distance of approximately
five miles. Table 2 lists principal project components.
07073.003:x:8:n10 6
COMMUNITY LOCATION
FIGURE 1
LOOKING SOUTH --SOUTHWEST TOWARDS KING COVE
FROM THE AIRPORT ROAD.
FIGURE 2 Im,
LOOKING NORTH FROM AIRPORT TOWARDS MOUNT DUTTON
AND THE DELTA GREEK STUDY AREA.
FIGURE 3
im,
jk(Mount Dutton
aa
15
�,1•� ., JJowr F 1 � rlp J` ' ,`! 1 ~�✓Q , ,; 'r . h, f - � , '\S' � r�.
r' r Glacial Tributary -- 4,
_ F 1 l,'r'+'f! 1}' 'r 11 '� \•P J d- /ilti B \_..,•� I 4;{' If � y.
r3
Clearwater Tributary ` - �;'' r' ti
r&j
I s
"I+
DIversionsl Ir'r r`li! ny'Sgrffh• 1
c
-
r II •II�7 v�_•4f4 ,I "' - —=r �' .-`•�'. f i}���. - :rl.. '
,..- Penstock and Access Road " J
�, ✓' -
'4
�ZI Powerhouse and Tailrace f
f 17) ' Kitchen �C
An Cho .i.
New Powerhouse Access Road
?/ Jr
�J� . 1 ill , `i' •%-'y 5 1 �= � � r ` � � '-mac.. I *f f
tn
Slo
Burled Trn Line
, 'n— •ladies \+
J ►rs,a .
Go
f No
Airport Road
`
King Cove Power Plant
\6�1
i.•�\\\ ,\ ,�t, ,
4.
PROJECT AREA
'' ItI]���9z {r�r rN. \ and COMPONENTS
t FIGURE 4
P;gssgG
10
TABLE 2
PROJECT COMPONENTS
Location
Delta Creek on the. Alaska Peninsula approximately five miles north of
King Cove, Alaska
Diversion
Clearwater Tributary at 465 foot elevation. Sheetpiling dam with small
reservoir. Submerged stainless steel cylinder screen intakes with 250 feet
of 24-inch steel penstock to connection with main penstock.
Glacial Tributary at 465 foot elevation. Sheetpiling weir and plate screen
intake with a 30-inch steel penstock to connection with main penstock.
Penstock
250 feet of 24-inch steel, buried
250 feet of 30-inch steel, buried
6,000 feet of 32-inch steel, buried within access road to diversion site and
one trestle stream crossing
Powerhouse Elevation
210 feet
Gross Head
255 feet
Design Flow
50 efs
Generation Equipment
One 700 kW Turizo Turbine with synchronous generator or two 350 kW
Turgo Turbines with synchronous generators
Transmission Line
5 miles of 12,47 kV buried cable
Average Annual Energy
3,940 MWh
2.2 PROJECT AREA GEOLOGY
The surface features of this area have been formed by past glaciation, with most of the
unconsolidated sediment consisting of glacial drift. Bedrock in the Delta Creek project area lies
beneath a thick mantle of glacial till coverers with stream alluvium. The dense, well compacted
till deposits consist of unsorted cobbles, gravel, sand, and silt with very large boulders present.
The permeability of this material is variable but typically low. The till is estimated to be 170
feet thick beneath the proposed diversion area. Overlaying the till is an eight to twelve foot
layer of alluvium, which has been transported to this area by Delta Creek and which consists
of unsorted cobbles, gravel, sand, and some silt. This alluvium consist of less silt than the till,
and its boulders, although present, are smaller in size. Its permeability is variable due to the
unsorted nature of the material but is typically low. Both the till and alluvium have good
bearing strength for structures and, with proper design, have acceptably low permeabilities for
water impoundments. Numerous boulders would be encountered during trenching of the buried
penstock. However, the anticipated size of most boulders might be small enough for the
trenching equipment to move. Some blasting of larger boulders in the higher elevation areas
07073.003:N:8:DI0 I 1
might be required for removal. Boulders in the project area could also be used for riprap where
required (2).
2.3 STREAM FLOW DATA
There are no long-term stream flow records for Delta Creek. The closest long-term daily
records of drainage basins with similar characteristics are from Kodiak Island in the Gulf of
Alaska, with shorter periods of daily record available for Russell Creek near Cold Bay. Delta
Creek was gauged from January 1982 to April 1986 and discharge was recorded several times
a day. The gauge was located near the proposed powerhouse site, approximately one mile
downstream from the proposed diversion. The conversion of recorded Delta Creek stage data
to flow was based upon rating curves developed from several discharge measurements at the site.
These measurements provided a rating curve relationship between creek stage and flow only in
the range between 17 and 41 cfs. Higher and lower stage and discharge values were estimated
through extrapolation of the rating curve above and below the measured discharge. The
collected data is not continuous and gaps exist from equipment malfunction, ice formation, and
channel shifts.
The stream gauging site was not located at the proposed diversion, but at the more accessible
powerhouse location. The drainage basin above the gauging station was 4.03 square miles (9),
while the drainage basin above the proposed diversion is 3.63 square miles (14). To reflect
basin differences, the gauging station flows have been reduced by ten percent, an amount
proportional to the differential basin area. This reduction has been used to predict flows
available at the diversion elevation. The flow estimate should be conservative as the actual
contribution to the total flow at the gauging station from the increased basin area is probably less
than ten percent because the increased basin area is at lower elevation and does not include any
glaciers.
Through comparison of the Delta Creek basin with discharge records for similar basins and
climate patterns, a synthetic flow duration curve was developed (14). As part of this study, a
second flow duration curve was produced from the five years of Delta Creek stream flow data.
This curve was developed by reducing the gauged data to mean monthly flows and then
correcting these flows for basin area differences. Both curves are presented in Figure 5. These
two flow duration curves have similar shapes, but the corrected mean monthly flow for the five
year creek gauging records predicts larger flows than the synthetic flow duration curve. These
curves estimate the mean annual flow (defined as 33 percent exceedence or the percentage of
time flow will be greater than a specified value) to be 24 cfs (14) or 31 cfs (from HDR analysis
of stream flow data corrected for basin area). Although five years of stream flow data is not
a sufficient period of record to predict the long-term flow characteristics of Delta Creek, it is
sufficient to predict project feasibility.
Figure 6 presents the estimated average monthly flows for Delta Creek. The figure contains
two graphs: the previous studies' synthesized estimated flows (14) and the five years of gauged
data monthly averages (corrected for basin area differences). In general, the corrected gauged
07073.003:N:8:D J 0 12
150
140
130
120
110
100
U so
0 70
LL
60
50
40
30
20
10
rf, u
•
MEAN
(5 YEAR
ANNUAL
CORRECTED
FLOW
"VOE
31 eta
DATA)
MEAN ANNUAL
(SYNTHESIZED
FLOW
24
S1tTA)(
ets
14)
'
L
L
10 20 30 40 50 60 70 90 90 100
PERCENT (%) OF TIME FLOW EXCEEDED
DELTA CREEK
FLOW DURATION CURVE
FIGURE 5
im,
13
SO
0
60
U
�.. 40
O
LL
30
"l
SYNTHESIZED MONTHLY FLOW (14)
1 17 j 17 I 17
i
33
31 29
51
5 YEAR GAUGED DATA
55
0
\\\\f\\\\\\\Y\\\V\\\\1\Z\1Y\\\V��♦\�\��Y��i�Ll„ n�sv
J F M A M J J A S 0 N D.
MONTH
31 Cfs
0 SYNTHESIZED YEARLY AVERAGE 24 Cfs
FLOWS CORRECTED FOR BASIN AREA DIFFERENCES
DELTA CREEK
AVERAGE MONTHLY FLOWS
FIGURE 6
14
�Z
data flows are higher than earlier estimates. This is especially true during July and August when
gauged discharges were more than double the estimated discharges, possibly due to glacial
melting during summer months or unanticipated orographic effects. During May and June,
however, gauged flows were less than estimated. This difference could mean winter snowpack
melts at a slower, more even rate than predicted.
Average monthly flows computed from the creek gauging records are presented in Table 3. This
table also presents the predicted average monthly flows at the diversion, corrected for basin area
differences. The diversion flows were reduced by ten percent from gauged flows to account for
ten percent less basin area as stated earlier. The table shows peak flows occur from July
through December, and low flows occur from January through April. From the previous studies
it appears both tributaries of Delta Creek flow year-round at the proposed diversion. There have
been, however, no actual discharge measurements on the glacial or clearwater tributaries at the
proposed diversions during winter low flow periods. It is also unknown what proportion of the
flow may originate from the glacial versus the clearwater tributary. Prior to design, work
should be done to verify the flow contribution available at each proposed diversion. The cost
of this verification work was not included in total estimated project cost presented in Section 5.0.
A hydrologic analysis was done to compare Delta Creek gauge data to USGS gauge data at
Russell Creek near Cold Bay. Gauge records were concurrent at both sites for 12 months and
comparisons of these daily records showed that Delta Creek has 25 percent less runoff per
square mile than Russell Creek. Study of the basin characteristics for these creeks revealed no
obvious reason for this. On the contrary, it would be expected that Delta Creek should have a
greater runoff per square mile because_
1. Delta Creek has 85 percent of its drainage area above 1,000 feet elevation,
while Russell Creek has only 50 percent above 1,000 feet elevation. Typically
rainfall increases with elevation.
2. The Delta Creek Basin faces south. The Russell Creek Basin faces north. The
predominant rain bearing winds are out of the SSE.
These factors suggest that Delta Creek should have a runoff per square mile of drainage basin
at least equal to that of Russell Creek. Therefore, Russell Creek runoff volumes per square mile
were used to synthesize Delta Creek daily flows from Russell Creek data. The estimated
monthly flows are included in Table 3.
07073,003:V:8:1)10 15
TABLE 3
AVERAGE MONTHLY FLOWS AND ANNUAL FLOWS
DELTA CREEK GAUGING STATION
AVERAGE MONTHLY FLOWS (CFS)
YEAR
SOURCE
]AN
FEB
MAR
APR
MAY
JUN
JUL
AUG
SEP
OCT
NOV
DEC
AVERAGE
ANNUAL
FLOW
1982
9
15
13
19
32
53
32
60
94
46
26
30
22
37
1983
9
13
13
18
25
35
56
70
56
37
43
32
51
37
1984
10
21"
21
17*
G
23*
3.7
42
33
42
33
36
31
30*
1985
10, 11
25
19
16**
16
18
23*
G
G
G
44*
65
41
30*
1986
12
22*
29
25
66"
***
35*
5 year average
19
19
19
34
32
37
57
61
42
36
41
36
34
5 year average at
17
17
17
31
29
33
51
55
37
32
37
32
31
diversion corrected For
basin areas
Diversion flows
29
24
17
17
28
37
49
43
56
47
48
44
37
estimated from Russell
Creek data
* partial data
** 3 daily discharges of 8$, 217, and 114 cfs not included; it included nv4raga 28 cfs
*** Gauge removed April 1986
G Data gap
2.4 PEAK DISCHARGES
Estimates of the 2-year, and 100-year peak flows have been calculated for Delta Creek (13).
These calculations were based upon regression equations developed by Ott Water Engineers
"Water Resources Atlas for USDA Forest Service Region X, Juneau, Alaska", (Ott Water
Engineers, April 1979). Figure 7 presents the peak flow frequency with associated 90 percent
confidence intervals (13). This curve has not been updated with the five years of gauged data
nor have flood flows been predicted for the glacial or clearwater tributaries individually as these
were not part of the restudy. The gauging station recorded a maximum two hour discharge of
364 cfs on November 26, 1985 (11). Comparison of this flow to Figure 7 shows it corresponds
to approximately a two year recurrence interval event for this basin. Peak discharges should be
calculated for each tributary prior to design and be used for design of structures placed in or
near the creek channels.
07073.003:N,8:Dt0 16
21000
..s
500
w 200
a
a
s
U
=
EXCEEDENCE PROBABILITY
90 90 70 50 30 40 30 20 to S 2 t 0.5 0.1
. -
i
T
d..
-
:. 7
1
CONFIDENCE
1NTERMAZ.:
.
�.._.. : EST MATED FLOOD FREQUENCY
2 5 10 zo 60 100 IVVu
AVERAGE RETURN PERIOD IN YEARS
DELTA CREEK
PEAK FLOW FREQUENCY CURVE
( From 14)
FIGURE 7
fm�
17
3.0 HYDROELECTRIC PROJECT ALTERNATIVES
3.1 INTRODUCTION
Two previous indepth feasibility reports have been completed to assess the development of a
hydroelectric project at Delta Creek. The first was completed in 1982 by DOWL Engineers and
the second was completed by AEA in 1988. Both reports recommended run -of -the -river
hydroelectric projects. This section reevaluates these two studies and updates the feasibility of
the project.
3.2 MOBILIZATION
Options Considered
King Cove's location on the Alaska Peninsula complicates logistics. On one hand, rates and
schedules for barge service from Seattle are only slightly less favorable than these for
Anchorage; yet air transportation to and from king Cove is expensive, often delayed, and
potentially hazardous. Equipment and supplies are not all locally available, and weather can
often delay or hinder deliveries and work for days at a time. Mobilization for this project will
be a significant project cost, which could vary greatly, depending on local project support.
The first feasibility study assumed labor and equipment would not be available at King Cove,
and the project construction cost estimates reflected the cost of using equipment and materials
brought to the site by the contractor (14). The second study developed cost estimates assuming
"force account" construction by using labor and equipment from the City of King Cove and
bringing in contractors only for specialty work (3). This construction cost estimate method was
done in order to reduce project costs and provide employment opportunities for local labor.
Option Selected
This study_ assumes all labor, materials and equipment to build the project would need to be
brought in by a contractor. Material would be barged directly from Seattle to King Cove, then
trucked to the construction site. Workers would be transported into King Cove and
accommodated by the contractor. Some of the construction crew might be hired locally.
Further Study
Cooperative involvement of Peter Pan Seafoods could reduce mobilization fuel or lodging costs
during project construction.
07073.003;-NA W 18
3.3 DIVERSION
Options Considered
The 1982 feasibility study recommended a reinforced stream bed -level concrete apron with wing
walls and an earth dike. The weir itself would consist of five prefabricated steel diaphragm
modules bolted to the apron. The weir would impound water to about 4.5 feet above the top
of the apron. A prefabricated steel inlet structure located to the right of the diaphragm modules
would provide a cleaning sluiceway with a control gate, a trash rack, and a penstock with an
isolation gate. A prefabricated steel sediment basin located below the inlet structure would
prevent coarse sediment from entering the penstock. A bypass with sluice gates would be
provided for cleaning operations and periodic sediment removal (14).
The Division of Geological and Geophysical Surveys in 1984 calculated that the basin behind
the diversion would fill with sediment in approximately seven days under average flow
conditions (2). The sediment was predicted to come exclusively from the glacial tributary. This
was derived from information gained during a DGGS geotechnical survey of Delta Creek in
1984. Sedimentation, therefore, became a major design and feasibility issue for the glacial
tributary.
Due to the anticipated high cost of cleaning sediment from the above diversion, AEA proposed
an alternative diversion scheme in 1988 (3). In order to reduce sedimentation problems, increase
available project head, and provide for force account construction, the study proposed diversions
for both the Clearwater and glacial tributaries. These diversions were to be located about 500
feet above the 1982 proposed diversion at the confluence of the tributaries. A low timber and
steel post fence would be constructed across each tributary. The posts would be set in concrete
in the stream and canyon bottom. This weir would fill in on the upstream side with either
sediment, in the glacial tributary, or water, in the clearwater tributary. A lower section of the
weir would act as a spillway where an intake box could be located. Rocks and sediment would
be washed over the intake box during high flows, small diameter bed load would be rejected by
a Johnson screen on top of the box. The intakes for both the clearwater and glacial tributaries
would feed into a wood stave tank designed to combine both flows to a common penstock and
provide some final sediment removal. The exact locations for these diversion weirs, penstocks,
or pressure tanks were not noted in the report.
Both of these proposed diversion designs, as well as other diversion options, were reviewed
during this study. Diversion selection criteria included Iow maintenance, minimizing icing
potential, and sediment accumulation (especially for the glacial tributary). As the site is remote
and access during winter months is poor, site maintenance activities needed to be minimized,
especially removal of accumulated sediment. Intake icing was addressed through submerging
intake screens in a pool of water or maintaining water over screens. The selected option present
below is considered to be a good solution to these problems. Other solutions may exist and
should be investigated during design.
07073,003:n;8;Dla 19
O ti on Selected
The proposed diversion consists of two darns, one on each tributary, and a single penstocks from
each dam, which join to form a common penstock to the powerhouse (see Figure 8). A different
type of intake structure is proposed for each tributary.
The Clearwater tributary diversion (Figure 9) wouId consist of a sheet piling dam approximately
six feet tall. The sheet piles would be dug into place, with a concrete footing and a riprap
covering on both sides for erosion protection. A spillway would be constructed approximately
one to two feet lower than the maximum dam height. Cylinder screen intakes would be located
near the bottom of the dam and would be connected to a 24-inch steel penstock. A sluice gate
would be constructed on the eastern side of the dam in order to drain the reservoir for cleaning
and intake maintenance. This diversion method was selected because the clearwater tributary
has little or no sediment load (2), and a submerged intake would reduce or eliminate intake icing
problems.
The glacial tributary diversion would be similar to the type proposed in 1988 and would consist
of a low weir structure across the full width of the glacial tributary (Figure 10). The weir would
channel low and average flows over a screened intake box, and would be constructed from dug -
in sheet piling with a concrete footing to avoid river scour of the weir foundation. The upstream
side of the weir would be filled to the weir top with creek gravels. The downstream side would
be partially filled with boulders in order to eliminate scour from the cascading water (Figure
11). An iron boulder deflector would -need to be installed upstream to deflect boulders away
from the intake box during flood flows. The intake box would be screened to remove sediment,
and would have a sluice gate for periodic cleaning. A 30-inch penstock would connect this
intake to the 24-inch clearwater tributary penstock. Sediment would be swept over the weir and
intake box by high flows. Twice yearly weir maintenance is assumed to be needed to remove
excess sediment and boulder accumulation and to clean the intake box. Screen icing might be
controlled by keeping the screens slightly submerged (112 to 1-inch) in the intake box through
the hydraulic connection to the clearwater tributary diversion pool. The small depth of water
would help reduce icing while still allowing sediment to be washed over the intake screen.
Submerging.the screen deeper may allow excess sediment accumulation on the screen.
Further Stud
The proposed diversion location was not surveyed during this or previous studies. The
diversions were located through interpretation aerial photographs and extrapolation from the
1981 topographic mapping (7). A survey of the diversion areas should be done prior to design.
This survey may also locate diversion locations at higher elevations which would increase
hydropower generation through increased availability of head.
As noted in Section 2.3, existing gauging records were collected at the proposed powerhouse
location; no gauging was done at the proposed diversion area. Through inspection of
photographs of the two tributaries and wort: done by DGGS (2), it is assumed that the clearwater
07073.003:N:8:DIO 20
CLEARWATER TRIBUTARY
DAM WS EL.-465± (SPILLWAY EL.)
SHEET PILE DAM and
BARREL INTAKE SCREENS
(See Fig. 9) /
I 32' STL. PENSTOCK WITH
ROAD TO POWERHOUSE
PENSTOCK and CREEK FORD
24' STL.
PENSTOCK
GLACIAL TRIBUTARY
DIVERSION WS EL.=465±
SHEET PILE DAM WITH
INTAKE BOX
(See Fig, 10)
97a
4sp+
440-
���� ¢3O
440 \\ a
q�b o
470
CONTOURS ESTIMATED FROM CONTOURS BY DOWL,1982
AERIAL PHOTOS
DIVERSION LOCATION
NTS
FIGURE 8
FiDR Enpr►eerr�p, H"IR.
21
SLUICE GATE
WEIR EL. 465=
SHEETPILE DAM
t
PENSTOCK
i CONCRETE FOOTING
�f
BARREL SCREEN INTAKES
CLEARWATER TRIBUTARY DIVERSION
NTS
FIGURE 9
22
BOULDER RACK
SHEETPILING
I
+ � I
Lu
L-------------
I
I �
I I
1------------- _____�__-----------------------------------___-----------h
-------------
so'= 20' so'=
GLACIAL TRIBUTARY DIVERSION PROFILE
LOOKING UPSTREAM NTS
NATIVE GRAVEL and COBBLES
FILLED TO TOP OF SHEETPILE
iTygical)
SLUICE Jl1}JyJ}��
E
10
r I\{\
r------ - - -------------
------------ ---- ---- - E ------ ---- L�
s�rl! l
LARGE NATIVE BOULDERS
PLACED FOR SCOUR PROTECTION
ACROSS FACE (Typical)
BOULDER RACK
SHEETPILING
r----------------------;
I
----------------------------
INTAKE SCREEN (Not Shown)
GLACIAL TRIBUTARY DIVERSION PLAN
NTS
INTAKE STRUCTURE
STL. PENSTOCK
FIGURE 10
23
HDR �,�..►t,a r�
BOULDER RACK
1 a'
77
g'�
Flow
SHEETPILING
cc
cc
'H' PILING
a'
INTAKE SCREEN
Elev. 465'=
r
,
6' '
I � nC?n -. ap OfiY': "-8(J--.vUOffa o
j - 30' DIAMETER PENSTOCK
i
i
r
0 .
ire TO POWERHOUSE
GLACIAL TRIBUTARY DIVERSION CROSS-SECTION
A
NTS
FIGURE 11
HaR 6Qrti.rtl� IM4
24
tributary flows year round, at approximately 25 percent of the glacial tributary flows. This
should be verified prior to design. Costs to do this were not included in total project costs. -
The anticipated sediment loads of both tributaries were estimated from the DGGS 1984 report.
As the report estimates sediment transport with only one water sample, additional investigations
into sediment loads should be done prior to design. Costs to do this work were not included in
total project costs.
The diversions proposed in this report rely on limited existing information. Better and less
expensive intake structure designs may be applicable after the diversion area has been surveyed,
sediment loading evaluated, and the actual diversion locations identified.
The glacial tributary diversion proposed in this report should be refined during design. Coanda
type screens with a taller weir were investigated during the preparation of this report and are
workable alternative to the intake proposed that should be further investigated.
3.4 PENSTOCK
Options Considered
The remoteness of the King Cove site required the assessment of numerous penstock designs.
Cost, weight, construction approach, constructability, and mobilization all affected each choice
of pipe and pipe route in different ways.
Materials
The 1982 feasibility study had recommended a buried 36-inch fiberglass pipe combined with
steel pipe for above -ground sections (14). The 1988 study recommended aboveground and
buried, 36-inch 10-gauge bell and spigot steel pipe to be held in place with earth anchors in
above -ground sections (3).
For this report, these materials were again evaluated, along with high density polyethylene
(HDPE) and ductile iron. Hydropower Evaluation Program (HEP) modeling of gauged stream
flow data analysis showed that 32-inches would be the preferred diameter (Appendix 1).
Fiberglass pipe was dismissed due to its poor resistance to scour by abrasive water, which this
project will have, and susceptibility to "bruising" during installation, which creates weak areas
in the pipe. HDPE pipe was eliminated because it offers no costs or weight savings for the
diameter required using HPDE would require an oversized pipe to meet inside diameter
requirements that it would need to be specially manufactured to meet pressure requirements.
Steel and ductile iron pipe were found to be applicable penstock materials for this site. Both
would withstand potential erosion and corrosion over the lifetime of the project. Both could
be buried in the till and alluvium materials present with minimal imported bedding. Ductile iron
with bell and spigot has greater joint flexibility than steel bell and spigot. Steel pipe for this
07073.003:N:8: D 10 ? 5
application would probably weigh 30 percent less than ductile iron, depending on wall thickness
required to rneet operating and surge pressures. Ductile iron has greater bedding and backfill
material tolerances. Steel is less expensive than ductile iron for the size required.
Route
The 1982 report investigated three possible penstock routes: a route in the west rim of the creek
canyon, one to the east rim of the creek canyon, and one on the creek floodplain (3). Each
route included a road from the powerhouse to the diversion for maintenance purposes. For cost
and constructability, the preferred route of the 1982 report was on the creek floodplain. This
route included a stream crossing by the penstock on a trestle and long sections of riprap over
the pipe to protect it from creek erosion. The total penstock length would be 5,300 feet. The
access road would have only been passable during creek low flow as it had areas where it
bordered and crossed the creek.
AEA's 1988 study proposed an overland penstock route on the east side of the creek. As the
diversions were at higher elevations, the route would leave the creek floodplain above the 1982
proposed diversion and travel along the bench on the east side of the creek. The total penstock
length would be 7,080 feet. AEA did not recommend a road be built from the powerhouse to
the diversion. The intent of the design was for low maintenance and no cleaning of debris, so
infrequent inspections and maintenance were to be accomplished via a temporary access road
built during construction and via foot access to the diversions (3).
Option Selected
Materials
An above ground pipeline was evaluated. The logistics of attempting to anchor the pipe for
thrust and thermal considerations, the need to eliminate siphons and adverse slope in the pipe,
and freezing considerations for an above -ground pipeline make burial the preferred choice.
Either ductile iron or steel pipe are recommended for, this project. For this study, steel pipe
with bell and spigot appears to be the better option due to its lower weight and lower cost. The
penstock should not have any interior coating as it would wear away with the abrasive water.
To help prevent corrosion of the pipeline in the soil, the pipe should be coated on the outside
or wrapped in polethylene wrap. The appropriate method should be chosen during design. The
pipeline should be buried. Burying the pipe would provide the best support and protection from
freezing, and would allow the pipe to be placed with a continuous downhill slope. The constant
slope would eliminate the need for air -vac valves and would allow the pipe to be completely
drained, if required .
Above the confluence of the glacial and clearwater tributaries, the penstock sizes should be 250
feet of 24-inch pipe for the clearwater tributary and 250 feet 30-inch pipe for the glacial
tributary. The final sizing and length of these pipes will depend on the actual percentage of the
07073.003:N:8:I)10 26
total flow in each creek and the actual diversion location. The tributary penstocks will join at
a simple 'Y' connection. No settling tank will be installed as sediment removal will be
accomplished at the intakes.
After the two tributary penstocks join, the 32-inch penstock will be placed on a trestle to cross
the Clearwater tributary. The trestle should be of steel construction with concrete footings
holding the pipe above estimated flood levels. The steel penstock can span 40 feet unsupported,
which should be adequate to bridge the clearwater tributary at this point. Only two supports
are anticipated. Concrete anchor blocks will be required where the penstock leaves and enters
the ground.
Route
The preferred alignment would be on the bench adjacent to the east side of the creek, as
recommended by the 1988 study. This route would protect the penstock from creek erosion.
The glacial tributary diversion penstock would connect to the clearwater tributary penstock just
above the confluence of these tributaries (Figure 8). A Iimited access road should be constructed
over the penstock from the powerhouse to both diversions. A ford should be constructed across
the clearwater tributary below the diversion dam to access the glacial tributary diversion. A
typical road section is shown in Figure 12. If the road surface above the pipe is graded to match
the existing ground, no culverts would be needed to route drainage across the road surface.
Some sections of the penstock might be placed on very steep slopes and the roadway might have
to be constructed on an alternate nearby route. From inspection of available information and
aerial photographs, two sections approximately 1,000 and 2,000 feet from the powerhouse might
require the access road and the penstock routes to diverge due to excessive grades.
Further Study
Options of ductile iron and steel pipes, as well as reinforced concrete cylinder pipe, should be
further evaluated during design of the project. A route survey must be done prior to design, as
no field reconnaissance or survey of the penstock route was done as part of this study. Also,
the exact location and extent of the divergence of the access road and penstock route should be
determined during design.
3.5 POWERHOUSE
Options Considered
A turbine and generator are needed to generate electricity from water. The turbine converts the
power in the water to mechanical power, and the generator converts the mechanical power to
electrical power. Turbines fall into two main categories: reaction and impulse.
Propeller -type reaction turbine use is confined primarily to high flow, low head situations and
would not be applicable at this site. The most common high -head reaction turbine is the Francis
07073.003:N:8:nin 27
B' FIBERGLASS ROAD MAKER
@ EDGE OF ROAD
12' MIN.
TOP WIDTH
Ili SLOPE TO MATCH
COMPACTED 6' MINUS -
ROAD SURFACE MATERIAL
12' MIN. THICKNESS
BEDDING MATERIAL
ROADSURFACE
ORIGINAL GROUND
NATIVE TRENCH BACKFILL
(LARGE STONES REMOVED)
32" STL. PENSTOCK
TYPICAL ACCESS ROAD and PIPE
BEDDING SECTION
NTS
FIGURE 12
Em,
mm
which converts the water's energy to mechanical energy by forcing the water through gates to
a vaned rotating runner. Francis type turbines could be used for the head and flow conditions
at this site, but, for this application would require surge tanks or relief valves. These tanks or
valves reduce pressure surges in the penstock when the turbine has to shut down quickly. These
devices usually cost about ten percent the price of the turbine unit (14).
Impulse turbines, the most common types being Pelton or Turgo, convert water energy to
mechanical energy by shooting a jet or jets of water into buckets on the perimeter of the runner.
This process takes place in a case open to atmospheric pressure. An emergency shutdown is
accomplished by deflecting the water jet from the runner and then slowly_ closing the valve on
the penstock. No relief valves or surge tanks are required.
Generators connected to turbines can be either induction or synchronous types. induction types
are usually less costly, easier to maintain, and require less peripheral equipment (14). They do
not, however, produce synchronous power (power at a set frequency). To do so, they require
excitation from outside power sources. Synchronous generators produce power at an established
frequency. This type of generator is more costly and does require more sophisticated ancillary
equipment.
Through analysis of the cost difference between turbine types and single and multiple turbines,
the 1982 study recommended a single turbine sized for the 15 percent exceedence flow. The
impulse turbine was also recommended, and the type selected for the available head and
predicted flows was a single 575 kW unit with a synchronous generator (14).
The 1988 study reviewed the gauged flow data and the geologic and sediment data during the
reevaluation of this project. Since the diversions were at higher elevations, more head was
available to the project, as well as more flow being predicted by the gauged data (the gauged
data was not corrected for basin area difference). The study, therefore, recommended a plant
capacity of 1,000 kW in single 1,000 kW unit or one 600 kW plus one 400 kW unit using either
impulse turbines or Francis turbines and synchronous generators. This was a preliminary
recommendation and the report suggested "bid documents should allow contractors to propose
the least costly units that meet project specification (3)".
Both previous feasibility studies recommended a prefabricated building with a concrete floor for
the powerhouse. AEA recommended a larger building (35 feet x 50 feet v.s. 35 feet x 35 feet)
if two turbine generator sets were used. Both studies recommended the electrical transformer
be located in a fenced area next to but outside of the powerhouse and an open channel tailrace
be constructed from the powerhouse to Delta Creek.
Option Selected
An impulse turbine would work best for this project, due to the head and flow characteristics
of the site, and the lower costs for the turbine. A Turgo type turbine may be better than a
Pelton type, but the actual turbine used should be decided during design. Table 4 presents the
07073.003AI: D10 79
projected power generation capacities from HEP modeling at a plant efficiency of 80 percent.
These estimates may change as the actual available head may be greater if a final diversion site
is located at a different elevation other than 465 feet or if plant efficiencies are other than 80
percent. It is also assumed 100 percent of the creek's minimum flows can be diverted for
generation.
The calculations show a range of generation capacity from 283 to 721 kW. This large difference
in maximum and minimum capacities suggests one or two generation units could be used. A
twin jet horizontal turbine would result in a increased turbine speed, which would reduce the size
of the turbine runner, case and generator. Twin jet impulse units of the recommended type can
run down to 20 percent of their maximum rated capacity. Synchronous generators are
recommended so that power can be delivered at an established frequency.
TABLE 4
POTENTIAL ENERGY GENERATION
FROM DELTA CREEK FROM HEP MODELING
FLOW REGIME
FLAW (CFS)
HEAD (FT)
CAPACITY (kW)
20 percent exceedence
50
201
721
Mean Annul
37
227
533
80 percent exceedence
18
248
283
Analysis of King Cove power requirements (presented in Section 6.0) shows the current peak
demand is about 350 kW, approximately one-half 20 percent exceedence hydropower capacity.
Since it is not known if power generated in excess of the City's demand can be sold at this time,
installing two generation units may be the best alternative. If two 350 kW units are installed,
one could be installed now to meet current demand and a second one installed when demand,
either City or cannery, warranted it. Two units could be used over a slightly wider range of
flows than a single generation unit, and might be able to better use daily flow variation. Two
identical units would provide system redundancy and allow for use of identical parts. A single
turbine and generator would, however, be less expensive to purchase and install and would
provide less equipment for operators to maintain. Electrical switching would also be simpler
for a single unit. The penstock, building, electrical switching, and transmission line should be
sized for future capacity in any case, even if only half the generation capacity is initially
installed. This is recommended because the major cost for these items is labor and mobilization,
not materials. This study will, therefore, develop project costs based on a single turbine with
synchronous generator sized for the 20 percent exceedence flow and two identical turbines and
synchronous generators sized for one-half this flow in order to allow for design flexibility.
These scenarios would be one 700 kW unit or two 350 kW units.
07073.003:N:8:D 10 30
The AEA's recommended building configuration for two turbine generator units, a 35' x 50'
building with an outdoor transformer area, will be used for two unit estimation purposes. A
smaller 35' x 35' building will be used for single unit estimation. Either building would be
located at the site recommended by both previous studies. The building should be placed well
above flood water elevations,
3.6 TRANSMISSION LINE
Options Considered
The 1982 feasibility study recommended a five mile 12.47 kV overhead transmission line
following the road from the hydroelectric power plant to the airport and on to the existing, City
of King Cove diesel generators (14). However, all the electrical distribution for the City of
King Cove is buried cable. The area weather conditions might also cause frequent damage to
an overhead transmission line system. In order to address these concerns the 1988 study
recommended a 3.7 mile, 12.47 kV, three phase, buried cable, with tie-in cabinets for future
services every 2,500 feet, to be located next to the airport road. Also recommended was an
additional telemetry cable be laid to allow for monitoring of the hydroelectric powerhouse'in
King Cove (3). The shorter, buried cable was to tie into the existing King Cove system at Dear
Island subdivision, although the exact location of this tie-in was not clear in the report.
The decision whether to use overhead or underground transmission cable is dependent on many
factors, including initial construction and maintenance costs, system reliability, ease of future
service tie-ins, and system life. A buried cable system is normally installed with final
transmission capacity, as any additional capacity is very costly to install later. Overhead
transmission line capacity can be increased at a lower cost with the addition of new transmission
cable. Construction of overhead lines can be less expensive than buried cables especially if the
cable is to be buried in bedrock areas which involves blasting and special bedding. Overhead
transmission lines are more susceptible to environmental damage and power outages than buried
cable, but overhead system breaks are easier to find and repair.
Option Selected
Buried cable, rather than overhead transmission lines, is recommended for this system. Because
the generation capacity is limited by Delta Creek discharge and the turbine size selected, the
ultimate electrical transmission capacity is known, and buried cable should be sized accordingly.
In anticipation of development which may occur along the airport road, service cabinets could
be installed at prime development locations as well as every 2,500 feet. Due to the possible
frequent and severe damage to overhead lines, a buried cable system should be more reliable.
The transmission line route should follow the road to the airport, as recommended by both the
1982 and the 1988 studies. The buried cable should be installed on the west side of the airport
road to avoid unnecessary road crossing (see Figure 4). The Deer Island subdivision, 1.5 miles
south of town, is not a good location to tie into the electrical system. Presently, the
07073.001A r8. U 10 31
northernmost extension of the electrical distribution system is a subdivision approximately 0.75
miles north of town on the west shore of King Cove Lagoon. This subdivision is across the
lagoon from the airport road, and connection into the system would require crossing the lagoon.
Therefore following the airport road to a connection into the present electrical distribution
system at the King Cove power plant, as recommended by the 1982 study, seems the most
feasible. This would also allow consolidation of controls and switch gear in one area and would
not require the construction of new buildings. Like the recommended overhead line, the
transmission line connecting the hydroelectric powerhouse to the existing diesel generator
powerhouse would be approximately five miles long.
Through aerial photograph interpretation, bedrock depth has been estimated along the proposed
cable route. It appears that bedrock is present only in a section of the road approximately one-
half mile long at the low pass near the airport. As a result, bedrock excavation should be
limited.
Further Study
The cable alignment needs to be surveyed, and depth to bedrock verified by a geologist along
the proposed route.
Transmission cable could be laid underwater in King Cove Lagoon, thereby avoiding burial costs
for 1.5 miles of the route. With little or no boat traffic'on the lagoon, the cable could be sunk
to the lagoon bottom instead of buried. This option should be investigated.
07M-003:n:8:D10 32
4.0 PROJECT ENERGY PRODUCTION
For this project, two turbine options were considered based upon the alternatives of community -
only versus community -plus -Peter Pan power sales. For the first option, two 350 kW turbines
would be used. Each turbine has a predicted range of 5 to 25 cfs and thus cannot use all of the
water available from the creek. The second option would use one 700 kW turbine with a flow
range of 5 to 50 cfs and, again, could not use all the water available from the creek.
With both options, the use of a 32-inch penstock would be required for efficient power
production and to allow for future increases in power generation. The use of 32-inch pipe is
predicted to result in 12 percent ]lead loss at maximum flow, an arnount typical for this type of
project.
Delta Creek is capable of producing up to 700 kW with the proposed development, based on a
20 percent exceedence discharge of 50 cfs and gross head of 255 feet. Table 5 summarizes the
average monthly energy available for each hydropower option based on HEP modeling. The
months of lowest energy production would be January through March. Where the monthly
average exceeded the maximum turbine design flow, the maximum turbine design flow was used
for the calculations. Both previous feasibility studies based energy production potential on mean
monthly flow values. This study bases energy production on estimated mean daily flow. The
energy potential in Table 5 will be used in Section 7.0, Economic Analysis, in this study. The
plant factor is a comparison of actual power production to the retinal power that could be
produced if the generators were run at the rated flow for the entire year.
It should be noted that average monthly flows lead to an overestimation the power potential of
a creek as single day peak discharges heavily influences monthly average (see Table 1, March
1985 flow). Also, monthly averages incorporate daily peaks that are above the turbine's
maximum usable flow again causing over -estimation energy potential. Therefore, daily flows
were estimated and used to predict energy potential as these better represent the usable discharge
of the creek.
07073.003:N:8:1) 10 33
TABLE 5
MONTHLY ENERGY GENERATION POTENTIAL
MONTH
AVERAGE
FLOW cfs
USABLE
FLOW els
MEGAWATT
HOURS/MONTH
AVERAGE
kW
JAN
29
29
296.8
399
FEB
24
24
199.2
296
MAR
17
17
196.0
263
APR
17
17
197 . l
260
MAY
28
28
288.1
387
JUNE
37
37
380.3
528
JULY
49
49
432,0
568
AUG
43
43
413.8
556
SEPT
56
50
400.4
556
OCT
47
47
372.5
500
NOV
48
48
390.9
542
DEC
44
44
381.6
513
TOTAL 3938.7
Total potential energy it' turbine(s) operated
continuously at rated flow
6017.6
Plant factor (actual production/potential production)
69%
07073.003:,',':8: D 10 34
5.0 PROJECT COST
Costs for the proposed hydroelectric project options are summarized below in Table b.
Complete cost estimate spreadsheets are included in Appendix 2. These costs include
construction, design, administration, and construction management, which in Table b were added
together to yield the total project cost_ Design, administration, and construction management
costs are calculated as a percentage of construction costs. The costs do not include the
additional recommended studies (where noted in the text) or permitting costs, both of which
should be assumed before design.
TABLE 6
PROJECT COST SUMMARY
ALTERNATIVE
DESCRIPTION
CFS
NIA\ kW
NtWh PER YR.
COST
NUMBER
1
Two 350 kW
10-50
700
3,940
$5,687,000
turbinel�enerators
2
700 kW
Ttounrheine/E!enerator
10-50
7D0
3,940
$5,370,000
The cost estimates represent the project cost if a contractor were selected through the
competitive bidding process to construct the entire project and deliver it completed to the City
of King Cove. This is the same approach that was used by the 1982 study. This "method was
determined to be more realistic in this case because of the nature and location of the project"
(14). Project costs estimated for force account construction as employed by the 1988 study were
not used. The cost estimates developed with force account construction often do not include
administrative costs and may underestimate the total funds required. Force account construction
might not be appropriate due to the complexity of the project, the size and type of equipment
required for construction, and the availability of local labor. Because of these uncertainties, this
study assumed contract construction.
When the actual creek discharge is less than the design capacity of the hydroelectric project, the
entire creek flow would be diverted to generate energy. This would dewater the creek from the
diversions to the tailrace outfall into the creek, approximately 6,000 feet. Dewatering of the
creek could occur up to 80 percent of the time. It is not known at this time if ADF&G would
allow creek dewatering, and any minimum in stream flow requirements would have to be
deducted from the total flow available to the project. As was done in the previous studies, this
report will assume dewatering of this reach of the creek would be acceptable to ADF&G or that
mitigation for dewatering would be a minor cost. This assumption should be verified prior to
design and any mitigation costs should be included in total project cost. Determination of
mitigation cost was not included as part of this contract.
07073.00:t:8:n10 35
6.0 LOAD FORECAST
6.1 EXISTING GENERATION CAPACITY
The City of King Cove and Peter Pan Cannery currently produce electricity with diesel
generators. The City operates two 300 kW and one 500 kW diesel generators. The 300 kW
generators are older and one has been recently overhauled. The 500 kW generator is new. The
Peter Pan Cannery operates up to five diesel generators with a generation capacity of 2,340 kW.
The cannery generators include 480 kW and 1,500 kW main generators and older 450 kW, 750
kW, and 1,000 kW backup generators.
6.2 ELECTRICAL DEMAND
Recent electric generation logs from the City of King Cove were reviewed to assess electric
demand. These records indicated that from November 1989 to October 1990 the City generated
approximately 2,176 MWh or an average of 181 MWh per month. This required 178,000
gallons of diesel fuel, or an average of 15,000 gallons per month. The yearly average kilowatt
hours produced per gallon of fuel was 12.2 for this period of record.
Peter Pan cannery power needs vary with the seafood being processed. During the salmon
season the cannery has a 1,900 kW load, during crab season, a 1,300 kW load, and during
bottomfish season, a 1,500 kW load. No fuel consumption or generation records were reviewed
in order to determine the cannery system efficiency. An analysis of a similar seafood processor
at Akutan was used to estimate efficiency. Peter Pan does plan to expand their operation in the
next five years with a planned increase in generation capacity of 1,000 to 3,000 kW. The exact
year and amount of this expansion is unknown at this time.
Electrical demand data for the City of King Cove was combined with hydroelectric generation
potential from Table 5 to estimate the monthly electrical load distribution between hydroelectric
generation and diesel generation. Two scenarios were evaluated: City load requirements served
by a 700 kW hydroelectric project (Table 7) and the City and Peter Pan loads served by a
similar hydroelectric project (Table 8). City loads represent the actual generation by King Cove
for the months noted. Peter Pan loads represent load data gathered by AEA in 1985 (3). The
Peter Pan loads have not been- updated for this study, although substantial improvements to the
cannery generation system have been made and power requirements have increased.
Table 7 allocates the total output from the hydroelectric project to the City of King Cove loads.
The table shows the City may not have to supplement hydroelectric generation with diesel
generation to satisfy present demands. This table does not, however, estimate diesel generation
requirements for peak demands, daily low flows, equipment maintenance, or emergencies.
Standby diesel generation will be required to meet peak demands and daily demands during
07073.001:N:8:D10 36
Table 7
HYDROPOWER POTENTIAL AND MONTHLY LOAD DISTRIBUTION
700 kW Project, 1990 City Load Only
ENERGY REOUIREMENTS
CITY LOAD {Most Recent Data}
Jan-'.*
Feh-90
Mar-90
Apr-90
May-90
Jun-90
Jul-%
Aug-90
Sep-9u
Oct-90
Nov-89
Dec-89
Year
Total
1 Average Dcmand(kW)
26.1
265
261
251
266
229
229
22-5
231
250
242
264
Z16
2 Peak Demand (kW)
527
536
522
503
532
459
459
451
461
500
484
528
3 Total Lad {kWh)
4 Percenl of Tolal Annual
196,080
178,320
194.400
181.200
198.000
165,360
170,880
168,000
166,800
186,240
174.240
196.560
2,176,n00
9.0`3.
R2%
8.9%
8.3%
9.1%
7.6%
7.9%
7.-PT
7.71s
8,6%
&0%
9,ny'o
100.[Y"r
DELTA CREEK I rYDROPOWER P1YITNTIAL (See Tahle 5 )
DISCHARGE SUMMARY
5 Average Flow (cfs)
29,0
24A
17.0
17.0
28.0
37.0
49.0
41,0
16.0
47.0
48,0
44.0
36.9
6 Usable Flow {cfs)
29.0
21.0
17.0
17.0
28.0
37.0
49.0
4.3.0
50-0
47.0
48,0
44.0
ENERGY POTENTIAL
7 Average Capacity(kW)
399
296
263
260
391
3Z8
568
556
456
5M
542
513
447
8 Hydroproject Ibtenlial (kWh)
j9h,R0n
190,200
196SM
187MI'll
28F1100
380.3011
437—MO
4DA 0
400,4611
37451M1
390,9M1
381,6t10
1,93$700
I IYDRGPRO.IF(7 r.N1.Rf1Y wsrntl1311'IION
HYDROELECTRIC GENERATION (kWh)
9 City Load
10 Excess Hydro Generation {&o)
196-080
106,720
178,320
104.400
191,200
10KOW
165,360
17000
168f100
166.800
186,240
174,240
196.560
2,176,080
2000
1.600
5,910
90,11k1
214,940
241,120
245,800
Z11fal
IK260
216.660
1g5,a1n
1,762,620
DIESEL GENERATION (kWh)
11 City Load
0
n
U
U
0
0
0
0
0
0
0
0
0
FUEL REQU[RED (Gallons)
11 city Load
n
0
0
n
0
n
0
0
n
n
u
hydroelectric plant maintenance shutdown or low flow periods. Table 7 does show that the City
demands could be met for twelve months of the year for the year chosen, with excess
hydroelectric generation available for sale. As demands increase, however, the need for diesel
generation will increase. The timing of this excess generation corresponds, in part, to a Peter
Pan processing demand peak. If a 350 kW hydroelectric project is constructed for City loads
only, the City will have to use diesel generation made up the difference. A 700 kW project will,
however, provide excess hydroelectric capacity during higher flow periods.
Table 8 distributes hydroelectric generation between both in the City and Peter Pan from a 700
kW hydroelectric project. The City loads are met first by the project (Table 8, line 17) and the
excess is applied to Peter Pan loads (Pane 18). With the load assumptions used for November
and December, the table shows the total electrical load for both the City and Peter Pan can be
met with hydroelectric generation. This may not be realistic as Peter Pan loads are from 1985
and have increased. This table does show a 700 kW project electrical output can be totally used
by the City and Peter Pan. The project output may not, however, correspond to the timing of
City or Peter Pan demands. Demand timing and project output should be carefully evaluated
prior to design. Again for low flow periods, droughts, and demand peaks, the City and Peter
Pan electrical needs will have to be met with diesel generation.
Figure 13 presents graphically the City and Peter Pan loads (Table 8, lines 3 and 7) and the
hydroelectric generation potential (Table 8, line 16).
6.3 CURRENT ENERGY COSTS
The City purchases diesel fuel to power their electrical generator system. The diesel fuel is
purchased in bulk from Peter Pan on a semi-annual basis and stored in tanks near the generator
plant. The most recent purchase of fuel was approximately November, 1990, when 80,000
gallons was purchased at $1.40 per gallon. The previous purchase was $0.78 per gallon.
Before the most recent fuel purchase, power costs were $0.20 kWh. The more expensive fuel
purchase may increase the cost of power generation, Recent King Cove power generation costs
are summarized in Table 9.
Data for Table 9 was taken from power cost equalization (PCE) records submitted by the City
of King Cove to the AEA. Over the three base years of FY 1988 to FY 1990, the City showed
a 7.4 percent increase in electrical use. Power generation costs or fuel consumption data were
not reviewed for Peter Pan Cannery.
07073.003.N:8:n10 38
Table 8
HYDROPOWER POTENTIAL
AND MONTHLY LOAD
DISTRIBUTION
700 KW Project, City and Peter Pan loads
ENERGY RF_OUIREMENTS
Year
Jan•90
Feb-"
Mar-90
Apr-90
May-90
Jun-90
Jul-90
Aug-90
Sep-09
Oct-00
Nov-99
Dec-89
Total
CITY LOAD (Mast Recent Data)
1 Average Demand (kW)
263
265
Z61
251
266
229
229
as
23t
250
242
264
248
2 Peak Demand (kW)
527
536
522
50.1
532
459
459
451
463
500
484
528
3 Total Load (kWh)
196,080
17"2A
194,400
181,200
108,000
165.360
171),BW
16800
166,8W
186.240
174.240
t%560
2,176,080
4 Percent of Total Annual
3.2%
2.91m
3.17,
2-9%
3.2%
27%
7 8%
2.7%
2,7^/
3.0%
28' ,
3.2%
35.2171
PETER PAN SEAFOODS LOAD (1985 Data)
5 Average Demand (kW)
378
371
308
357
449
735
875
833
421)
329
280
Z18
464
6 Peak Demand (kW)
540
530
440
510
640
1,050
I'M
1,190
600
470
400
340
7 Total Load (kWh)
2M.2-12
24%312
229,132
257,040
333,312
529,200
651,000
6[9,752
30Z400
244.776
201,600
177,072
4,073.948
8 Percent of Total annual
4.5%
4.0%
17 %
4.Z
5.4%
8-6%
111.5%
10.070
4.9%
4-0%a
3.3%
299E
65.9%
AREA TOTAL (City and Cannery)
0 Average Demand (kW) (1+5)
619
621
540
597
689
964
1,093
t,1166
661
576
536
494
7n5
10 Peak Demand (kW) (2+6)
540
536
522
510
640
1.050
I,L50
1,190
6M
S00
484
528
11 Total Load (kWh) (3+7)
460,536
417,312
101.761)
420,840
512616
604,080
814,680
704,592
475,020
428,544
395.920
167.536
6.]&4,336
12 Percent or-Tnlnl Annual
7.•Y7,
6.7%
6,5 %,
71"
R..1-
112n
112M
1191:
7,7 %
6.0%
6.2%
5,917
1001Y."n
DIRLTA CRFEK I I YDROPOWER POTFN'I1AL (See
Table 5)
W
DISCI IARGESUMMARY
13 Averagc Flow (cfs)
20.0
24.0
37.0
17.0
28.0
37 0
49.0
43.0
5&0
47.0
48.0
44.0
36,9
1.1 Usable Flow (cfs)
29.0
Z.I.n
17,n
17A
2R.0
37.11
44.n
43.0
50.0
47.0
4R.0
44,0
ENERGY POTENTIAL
15 Average Capacity (kW)
3"
2%
263
260
.187
528
568
556
556
500
542
513
447
16 Hydroproject Potential (kWh)
2%,800
199,200
196,000
137.100
288,1IX)
380,3rx)
43Z000
413,80)
4M,401
372,500
390,91X1
3Rl.6M1
3,938,701
I IYDROPROJECT FNERGY D[S1Rl(iU'1'ION
I i YDROELECTRIC GENERATION (kWh)
17 City Load
196.060
178,320
194,400
t81.200
198.000
165,160
170.880
168.000
166,800
I.K240
174,240
1%,560
2176,080
18 Petcr Pan Load
101,720
20,880
1,600
5,901
00,ion
214,940
261,120
245,8W
Z33.600
186.260
216,660
185.040
1,762,620
19Totnl
2%RM
199,200
196,000
187,100
2R$101
380,300
43VW
413,81V
400,30)
37ZSW
390,900
391.600
3,938.701
DIESEL GEN FRA11ON (kWh)
20 City Load
0
0
0
0
0
0
0
0
0
0
0
0
0
ZI Peter Pan Load
180,512
228,432
227,552
251.140
243.212
314,260
389,880
373.952
68.800
A516
0
0
2313,228
22Total
180,512
228.432
227.552
251,140
243,212
314,260
389,FR0
373.952
M.800
581516
0
0
2336,256
FUEL. REOUIRED (Gallons)
D City Load
0
0
0
0
0
0
0
0
0
0
0
0
0
24 Peter Part Load
14,796
A724
18,652
2A585
19.035
2-5,759
311957
30.652
5,639
4,796
0
0
141,496
75Total
14,796
18,724
18,652
2%585
K935
25,759
31,951
30,652
5.639
4.796
0
0
191,496
4
y
z
a
a
700
60
500
o
1400
300
200
100
1,M)
a Ol D(St 1 DI ii
700 kW Project, City and Peter Pan Dads
aen---UU M"U Mar-YU Apr-WU M,a"U JUn-9U dui-90 M --90 Sep-90 Od-90 Nov-69 Dw-89
Month
-�' City Iced Pekes Pan In®d - )K- Hyft Poteutiel
Figure 13
TABLE 9
SUMMARY OF EXISTING DIESEL ELECTRIC POWER PLANT COSTS
FOR CITY OF KING COVE
FY 1988
FY 1989
FY 1990
Three -Year
Average
Percent Change
1998 to 1990
Total Fuel Consumed (gallons)
162,903
164,440
173,601
166,991
3.8
Total Fuel Cost
S 110,094
S 145,187
S 142,357
S 132,546
22.7
Power Cost Per Gallon
S 0.73
s 0.88
S 0.75
S 0.79
2.7
Power Generated (kW)
1,966,920
1,918,920
2,099,560
1,995,100
6.3
Average kWh Pear Gallon
12.1
11.7
12.1
12.8
17.7
Power Sold (kWh) (a)
1,663,846*
1,590,971
1,796244
1,683,687
7.4
System Loss (kWh)
303,074
327,849
303,316
311,413
0.1
System Efficiency Production to Sales
84.6%
82.9
85.5%
84,3%
1.0
Fuel Expense
S 101,094
S 145,187
S 142,357
S 129,540
22.7
Operating Expense
S 202,927
s 272,134
S 161 ,928
S 212,329
-25.3
TOTAL EXPENSES (b)
S 304,021
S 417,321
S 304,285
S 341,875
0.1
Cost Per kWh Calculated (b=a)
S 0.183
S 0.262
S 0.169
S 0.204
- 7.6
Cost Per kWh Customer Charge (19)
S 0.20
5 0.20
$ 0.20
S 0.20
0.0
* Estimate
Taken from State of Alaska Power Cost Equalization Program (PCE) filings for 1988, 1989, and 1990.
FY = State Fiscal Year, July 1 to June 30, ending in year noted.
6.4 FUTURE ELECTRICAL DEMAND
Future load projections for the City of King Cove were based on a 2.5 percent growth rate for
the planning period. This value will be used in the economic analysis. Dock expansion, fish
processing expansion ill tile C0111111L1111ty, and the community expansion could all substantially
impact the electrical load, but are too undefined at this stage to factor into future loads. Prior
studies projected the City of King Cove peak load for 1990 at 253 kW (14), while the actual
peak was over 350 M.
6.5 PETER PAN SEAFOODS
There was little base data related to operating cost available from Peter Pan. The estimates of
production costs were derived from studies done with similar fish processing facilities at Akutan
(18). Load data was derived from projected demands furnished by Peter Pan and the 1988 AEA
07073.003:N:8:p10 41
study (3). During 1990, Peter Pan Seafoods peaked at between 1,300 and 1,900 kW. Energy
use data was not available, but at a 70 percent load factor this would represent 12,000,000 kWh
per year. For this study, Peter Pan load data from the AEA 1988 study was used as more recent
data was not available. Also uncertainties in the growth of the seafood industry preclude
accurate assessment of Peter Pan load growth.
For purposes of this study, Peter Pan and the City of King Cove together represent an infinite
load which could absorb all of the energy produced by the Delta Creek hydropower project.
07073.003:N :S:D t 0 42
7.0 ECONOMIC ANALYSIS
The economic analysis presented in this section compares the net present value of diesel
generation with the net present value of hydroelectric generation. The analysis period begins
in 1991, assumes hydroelectric power will be available beginning in 1994, and continues for the
next 20 years unt l~lfor a total analysis period of4,ears.
An economic analysis spreadsheet was developed to analyze the cost -to -cost ratio of the project.
The spreadsheet was modeled after one used by AEA in 1988. Two scenarios were modeled:
1) installation of a two 350 kW unit hydroelectric project to meet the City of King Cove's
electrical needs; and 2) a single 700 kW hydroelectric project to meet the City and Peter Pan
electrical needs. The spreadsheets are presented in Table 10 and 11.
The net present values of each case, diesel generation only and hydroelectric with diesel
generation, is found by calculating the yearly capital, fuel, and operation and maintenance
(O&M) costs for each, discounting these to current dollars and summarizing them for the
analysis period. The base case net present value is then divided by the hydroelectric net present
value to yield the cast -to -cost ratio. Cost -to -cast ratios greater than 1.0 indicate that
hydroelectric is less expensive over the project analysis period than diesel generation. Ratios
less than 1.0 indicate continued diesel generation would be the more economic option.
The economic analysis was based on the following assumptions:
• The City of King Cove load growth will be at an annual rate of 2.5 percent based on
PCE records (see Table 9).
• The annual interest rate will be 8.0 percent, nominal ynterest rate will be 3.0 percent,
and annual inflation will be 5.0 percent. �fues reflect recent trends in long-
term rate trends.
• Diesel fuel will be escalated at 1.35 percent above annual inflation. This value was
ssigned for use in this project by the AEA project manager and reflects the trend in
energy costs increasing faster then costs in general.
+ The 1990 fuel price of $0.90 per gallon was assigned for use in this project by the
AEA project manager.
• The City's diesel generation efficiency of 12 kWh per gallon is based on recent
generation records. Peter Pan efficiency of 12 kWh per gallon is based on an analysis
of a similar seafood processor in Akutan (17).
07073,003.N:8010 43
Table 10
KING COVE HYDROELECTRIC FEASIBILITY
Economic Analysis
City Lead Only-
Umd Foreenst Acsumptiom
Diesel Sesfcml Aasumpli"ns
Hydroprnjeel Assumptions
SUMMARY
('in• Load Factor
Sn.O n
Fuel Escalation Rate
1.35^
Total Cost
$J.marwXl
Rssse (.nsc Ncl l'resenl Vsthle =
$15,372,212
Community Lead Grouch
L511
I"PAyg. Fuel price
S(I.00 1pal
Funding Life
24 Yeats
1 Eydrllprnjeel Nei Present V.-iWe =
$15,137,175
Cry F,frMeney
12 kWh/gal
Annual Debt Service
$65510q
I•nsl/Cost Hallo =
I.42
Flontrmic Paramelers
/
Econnmic la(c
10 years
Unit 1
350 kW
Nnminal Interest Rale
RIP,
Replacement Cost
$Inn /kWh
Unit 2
350
Annual Inflation Rate
431
City 0 R M C'nct
$ft I I Aft
Installed Capacity
71m) kW
Rc:d Discnunr Rate
3.tr:
Head
255 ft
Erriciencv
SO'
O a M C'nsl
Stl.(R (kWh
CITY ONLY
ECONQMI( ANALYSIS
1mN1
I(I'll I'M 1003
"m 11N)S
r'Mlr, I(ml
Imw I'm 21XIr)
21011 2(N12
201`13
ENER(SY RE(•1111RC.NIF.N l5 fkwhl
I Ci1vinad
2,OK060
7152111.1 22115,850 2,2eAk o
2,317,521 237S, 157
113.IAP, 2,41A,711
2,S5fk1111 2.622,t163 2,6R7.611
1751,RI(5 2.823,675
!"Q1.267
DIFSFL FUEL RATLS
2 Annual brninlion Ratc
3 Fu0I1ncc1P"mI5�dl
0JV;r• CAST ANAI NSIS
Cite Svslem
1 Firm C:IpacilyikWI
S ('np:w4v Addui,m.(kWi
6 (',IpaeilVRepl.—niem,IOVI
7 D1, M l`us4 l lsa l};Jh'n I
R Capital l'"cls l l'1'x15I
9 Fucl ('ns13 11'1'N151
In () C MC-1,(I'rxIS}
I I •ri,cd ci„-rl,a� I rwx, $r
S1YDR(1pR(1?C ("I' ANAS.Y51S
12 Firm Capacim(kW1
13 Diesel C'apacily Additions (kWl
14 Cnpncky Replacements (kW)
15 Hydroelectric Gcneration(kWh)
16 Diesel Generate m (kWh1
17 Diesel Fuel I Ise (galh,ns)
M Capital Costs 119" S)
19 1 iydro Capital Costs
20 Fuel cnstb 119" S)
21 0 A M Costs (191X1 S1
22 Total Annual CmLs (1" $
L4 , 1.4% Llr4 LIS'% I.Ar" I.11_+ IA-1 1,4� I.-n 1. n 1. 1, I, 1.1 1.X",
R,xl hQl 11.92 It'll Rns 1111x pub n.IIu 1,1w1 IO2 1.113 Lul 1(11, I.0i'1
Rf X]
81N1
I,IMMI
1,e041
I,Iwxl
LINXI
1_fx Nl
1.IxNr
I!Mw]
I,1XX1
I'm)
I.IXMI
LIkXI
LIXkI
II
It
to
11
II
11
to
tl
It
11
(1
0
11
I(NI
It
II
5rXl
to
It
11
t1
11
Sm
11
0
11
SIXI
to
l 1.,k,3
IAI,?11
183,R21
IRR. 110.
110, 1 ! I
I'f)"M
liz"t11
24]1.']An
20. 17r,
21R.5115
1211Al
22?1567
235.34w,
211.3A'?
$11
$tl
$35ammo
$11
5n
SII
$tl
SII
$156joI n
$11
SIl
S(1
S35rknntl
S7n.IN11!
5157,If.1
S163,S83
S14,9.1r36
SIM.531i
S183142
Sl'11.5II
S19'1,'llt
$11i.fAml
$213.585
S221.981i
S230,lw
S139,4.W
521C719
$2SS..IIII
111,952
$236, 121
$'I_!.(, 11
S_'I,l•. 1111
S35 k921
S2r.1.101
S26 J. `:13
Ste 021,
$_R1.3Q2
S28F, IN
S29V138
S31U,n211
531VIII
Sl l IL 364
WR,-11`f
$.IINI,U61
S7Q.S14
$.125?15
$118.311)
$ISI,RrS
S465114,
t18(p.1211
5811.1]T7
S5IR V7
$526,135
$542.•17R
51Nhf.343
S616,179
800
RIN)
1j]nn
I.1wo
1•1110
1.RXII
1.74n
1.7491
L7nn
1.711A
1,71)(1
1.7110
1,700
1.700
n
n
n
n
11
11
1f
ff
u
o
n
n
n
Q
It
u
Snll
n
0
n
It
It
0
0
0
0
0
Soo
2,317,521
2�J75,459
2.a3a,R>•.
2.495,717
Z558.110
262L1163
2.(A7,614
z754,W
2.22?.675
2,8Q4,267
V"C1,56(1
2,152,049
2205,85n
2.260,9%
F1,401
8.2on
$d(I5
t1,6IS
8.831
1051
9,278
9,509
9.747
9,9'll
174,963
1710337
183,821
1M,116
ml
e83
71X1
'119
"136
'151
773
74J2
812
$33
so
$0
$3503100
$a
$o
A
$II
$n
$n
$n
$o
$o
So
$350,0111
$0
$1)
$0
$n
SM5121k1
S625,716
$Sn'7,55't
557r1,6r,9
$5.11,969
S520,4(A
$497,a13
V14,676
$153,316
$13?,917
S157,467
5163.583
S169,936
$176.536
$03
S65R
$NR3
$7111
$737
$766
$796
$827
58-59
S892
$L30,952
$236,71_5
524?rol4
S248,710
SYNA57
S214.60.1
S22n11r1
5225,562
S23L2n1
$2.16,081
S212,(WA
$2-2,Q78
$M,2+13
S261.583
S3811,419
S4n,3W
5762570
S,w,245
S86S,200
Sr411,067
$S18.303
$71M,931
$776,927
S75R,21I
$74n,745
S724,48I
S7M.377
S1,045,392
Table 10
CITY ONLY
ECONOMIC ANALYSIS
ENERGY RFOl11RFMENIS (kWhl
I Ci1v I-crld
DIESEL FUEL RATES
2 AnmuaF F*calalion Rate
3 l,ucl I'rire ( I mlS/Far)
BASF CASI-- ANALYSIS
Oily lyvsicm
U,
I Firm f'ap:,cin•(kWl
5 Cnpacily AdditVa nt fkWI
6 Cap:u-in' Replaccmcnls (k W I
! Oic+CI fntd I Ise IgAlom)
R (;Ipi131 frisk (I'M S)
9 fuel (:-15 (1 Wilt S)
III f144MC-I$(1'1xI$I
11 Telll C•itr C,wis (Sf„1II S)
M01.1102 031xf IMAK A WKIZ!
12 Firm Capacity (kWI
13 Diesel Capacity Additions (kW)
14 Capacity Replacements (kW)
IS Hydroelectric Gencralion (kWh)
16 Diesel Generatinn (kWh)
17 Diesel Fuel Use (gallr+rts)
18 Capital Costs (10" S)
19 Hydro Capital Costs
20 Fuel Costs (low$)
21 O 8t M Cmis (1990 S)
22 Total Annual Costs (IQ90S)
KING COVE HYDROELECTRIC FEASIBILITY Economic Analysis City Load Only
20111 2fx15 20" 21M11 21" 2(m 2014) 201t 2n12 2013 2014 21115 2016 2017 2018 2010
'r066.633 3,("11.789 3,116.8(19 3,191.729 3,271.507 3,356,462 3,44n,37-i 3.526.383 3,61I,s•12 3,704.906 3.797,5Z9 IOWAfi7 3.989.774) 4.118(I,52-3 4.191.7151 4.296.555
1.4i'n 1.•I;x- 1.446 JAI; 1.41 1, 1-, JA% 1,4"7 1-•l^ t,4x 1.4e4 1.44:1-4!, 14, 1.1^1 1.,1
LII'1 1,10 1.12 I.I3 1.15 1.16 11IR 1.I" 1.21 1.2.1 1 N 1.2r. 1 is 1.21) 1-31 L33
I,II(xl
1.INO
1.1"1
1,501
1,5411
I.SIIQ
I.SIMI
1,SIM1
I,ffxl
1.5fln
1,5011
IN*
1,7f91
1.701
1,7tM)
1,74111
n
It
0
5111
II
4
4
1`1
4
0
1)
It
21M1
it
n
0
If
4)
4
11
fix$
It
0
II
SIN)
n
it
11
0
59.11
54111
0
211_21'1
25t-3+r1
*c9,f,t.l
Z6rc221
12,x.K7
11-1.0111
284,,a.IR
2'r3,R65
1111.212
MA. 74Z
31fsIf, 1
321.312
331IR2
311010
319.313
35831i6
$0
$0
so
S350,Ix11
$350,l 1
$u
Sn
$n
S351)3xxl
$0
S0
$0
Sl+t(Xk)
s3sow)
$3509g)
$0
SNA,446
527R871
$289,702
S31w)i3
P12.e.12
W—I.-I84
$337,341R
SwI.Sol
$36.1,1111
$378.255
SY12,946
S108.2n7
S-12Rtw)
S449.510
SI571639
S475AIZ
$324024
$331, 187
$342,849
$351. 124
S3W.21xk
$36'g2tt
S378,411
S181,942
S141,61111
$407,540
$417,7M
S129. 171
$43$R76
$-11't,BSx
5161.01
$•172.4,21
S591,1'11
$4.1:058
5634551
tI.(XIL373
51,021811
S6rt31M15
3715.839
$738-•103
11,11),713
1781095
MAIM
5836,378
SIJP2.136
51,210,377
SI,2(A733
S%lP,1133
1,700
1.700
1.700
1.7"1
1,7fln
1.101)
L7110
1. MI
1.7(41
1700
1.700
1,100
13M
i,700
1.7t10
1,700
0
0
0
0
n
o
0
n
n
0
a
0
0
0
0
n
0
0
0
500
n
0
0
0
0
0
0
0
0
0
500
4
2,966,623
3,04Q789
1116,809
3.194.729
3174,597
3,356,1162
3:140,374
3.526,383
3,614,542
3,704,906
3,797,529
3,892,467
3,938,700
3,938,700
3,938,700
3,93$701I
10,241
10,497
14,759
11,02$
1I.MM
11,586
11.876
1�'173
17477
IL789
U.109
11.4.47
51,079
150,923
253.061
357,855
653
875
897
910
412
666
'MNl
LOl4
i,(sl0
1.%6
1,ft92
1,t2n
4.257
12.569
ZISM
29,6'_[
$0
SO
$0
S350,000
Sit
SO
so
SO
$0
SO
S L000,000
SO
$0
$0
$350,(xl0
SO
$41.1,435
S394,831
S377,063
S360,0%
$343,891
$32&416
$3t3,637
S299,524
S286,015
5273.173
5260,880
$249,141
S237,929
$227,223
S216.998
SO
$927
S%3
S1,OW
$1,019
S1.079
$1.121
$1,165
S1110
S1,257
S1,306
$1.356
$1.409
$5.429
$16147
S27,628
S3A597
S268.123
$274.926
S281.696
S288.739
5295,a57
VIM'356
S310,940
$318,713
S326,681
$334,848
S3.13220
$351.8W
S360,102
S37i,074
S38-320
$393,847
$682,485
$670,619
3650,760
$999,87,1
$640,928
5OUQ3
$625.742
$619.447
S613,983
$609,3Z7
11.605,456
$607350
S6113,460
$614.54.1
1976,945
$433,444
Table 10 KING COVE HYDROELECTRIC FPASIBILITY Economic Analysis City Load Only
CITY ONLY
ECONOMIC ANALYSIS
:n1n
2n21
zn2'+
2n23
NT.I
I;NER(;Y RI°Q111RFMI-MIS (kWh)
I 01e Lt�ad
iAf13.%,i
014.(w,g
I.Q( 020
414Y 503
40-1,158
imsCL ruEL RA•n:5
_' Annual F.�calalian Ratc
I:i'7
L4^%
Ld
1.4f'i
1.1':.
3
1.35
1.36
L38
1. trl
1.12
13ASr (_ASI: ANALYSIS
City SVIICm
CT
4 Firm Cer:lt•ity l kW)
I_IIN7
1.711)
l"IM
1.7tkt
I. 71x1
5( igwily Ad&hms (kW)
a
it
0
n
u
n Capacity Rc13larerncn1%(kWI
1)
0
Simi
It
01
7 Diesel l$tcl t fsc(gallons)
Nx,,at7
31fi,172
,385,577
375,216
IW.IMin
8 Capital Coos (1", $1
$II
$9
S3150_01,110
SO
Sit
0 Fuel Colts(lwatSI
$403,876
$50,057
S532083
S553,7&3
S575.Nh
Iu 0.k M Costs (1-41 S)
S1,e1,437
51,16,518
S5f1fi.461
iS21j-f,5
S531.121
II Twal011•Coa1s(anfglj}
$n19,113
S100k6n5
$1,301,0.1.1
S1.075tr,13
M.1trt.61I
I I YOROPROJIF('1• ANALYSIS
12 Firm Capacity' (kW)
1,71n1
1.Ina
1,700
1,71M)
1.71)0
13 DFescl Capacity Additions 1kW)
0
0
0
0
0
14 Capacity Replacements 1kW)
0
0
500
q
0
15 Hvdr lcctric Generation (kWh)
3938,700
3,038,7r10
3.439,700
3,938.71JQ
3,938.7110
16 Diesel Generation (kWh)
-165,269
575.368
6KZ20
803,893
022,458
(7 DicsdFuclllscigalloni)
38,772
•17.9.17
57.352
66.901
74.871
18 capital Costs (1900 $)
$0
SO
$350,(ft
SO
SO
19 Hydro Capital Costs
SO
$0
So
$0
$0
10 Fuel Costs (1999S)
S54177
565,305
$79,277
$93.852
$109.118
21 0 & M C0515 (IQ"$)
$405,663
S417,774
$430,187
S442.911
$455.953
22 Tot -it Annual Costs (19%S)
S457,A39
S483,166
S859,464
$536,163
1565,101
4-
v
Table 11
KING COVE HYDROELECTRIC FEASIBILITY
Economic Analysis
City plus Peter Pan Loads
Load Forecast
Assumptions
Diesel System Assumptions
Hydroproject
Assumptions
SUMMARY
City Load Factor
50.0%
Fuel Escalation Rate
1.35%
Total Cost
$7j,16,000
Base Case Nei Present Value =
$35,442,646
Peter Pan Load Factor
M.0m
1990 Avg Fuel Price
S0.90
)gal
Funding Life
24 years
llydroproject Nei Present Value =
$35,431,881
Community Load Growth
2.5 T
City Efficiency
12
kWhlgal
Annual Debt
Service
S616,000
Cost/Cost Ratio =
1.00
Petet Pan Efficiency
12
kWhlgal
Unit 1
700 kW
Economic Parameters
Economic Life
10
years
Unit 2
Nominal Interest Rate
&0:
Repfacemem. Cost
S700
AW
Installed Capacity
700 kW
Annual lnn.nion
Rate
4.5%.
City 0 & M Cost
$0.11
/kWh
Head
Z55 ft
Reat Discount
Rate
3.0%
Xclet Pan O & M Cost
SO04
/kWh
Efficiency
80%.
O & M Cast
$R.p9 lkWh
ECONOMIC ANALYSIS
14%
1991
111'12
1993
lml•1
1995
199h M7
1998
1999
2000
2001
2002
2003
1:Ni;R(:Y RFOUIRFMEN'1S (kWh)
I City Ioad
2,099,560
2,152,049
2.205.851)
2,260,996
1,31-1,521
2,375,459
-434,8-16 2,495,717
2,558.110
2,622,063
2,687,614
2,754,805
2821.675
2,89.1,267
2 Peter PartLo4d(1990)
1,075.&18
4,177,744
4,282,188
•1,399,243
4.498.074
4,611.448
4.T_6.73.1 4.84.1,902
4,966.025
5,090,176
5.217,430
5,347,866
5,481,562
5,616,(101
3 Total Community Low
6,175AW
6,329,793
6,488,038
6,650,239
4816,495
6,986,907
7,1615811 7,340,620
7.52.1,135
7,71Z?,38
7,90.1144
8,102,670
&305,237
8,S14868
DIESEL FUEL RATES
4 Annual Escalation Rate
1.4 %
1,4 %
1.4%
1.4%
1.4%.
1.4:0 1.4'"0
1.4%
1.4%
1.4%
1.4%
1.4%
1.4%
5 Fuel Price (I"O $1gai)
D.90
0.91
0.92
0.94
Allis
0.96
0.98 0.99
1,00
1.02
1.03
1.&1
1.06
1,07
RASH CASE ANALYSIS
(Disesi Generation only)
City System
,
6 Firm Capacity (kW)
OOII
so
1,(Nol
1,000
1,40ml
l'otm
I,tXkl 1.00t)
1.000
1,000
I,01H)
1,000
000
I.(01
7 Capacity Additions (kWl
0
f1
A
0
41
0
0 A
0
0
0
0
0
0
8 Capacity Replacements4kW)
0
0
500
0
0
0
0 0
S00
0
0
0
500
0
9 Diesel Fuel Use(p4ons)
17.1,1163
179.337
183,821
IM416
19-1,121
197,955
20z,)w 2417.9-16
20,176
218,505
223.968
229,567
215.306
241.189
10 Capital Costs (1990S)
SO
s0
S350010
SO
$D
S0
s0 SO
S350,000
$0
SO
SO
$350,000
s0
11 Fuel Costs (1990S)
$157.467
S163,583
S169,936
S176,536
$183.392
Sl%,514
$397,913 S20.5,600
$213,585
S221,880
$230,497
S239,449
$24&749
$258.410
12 O & M Casts (1991)$)
SZM.952
5236,725
$242,644
S248,710
$254,927
$261.301
S267,833 $274,529
$281 392
$288,427
SZ95.638
1303,029
$310,604
S3M369
13 Total City Costs (1990 S)
$368,419
S400,308
E414579
$425.245
VX319
$451.615
S465,746 $480,129
$494.977
$510,307
$526,135
1544478
S559,353
S576,779
Peter Pan System (1985 Data)
14 Firm Capacity (kW)
2,344
2,340
2,3.10
21340
Z,340
3,340
3,340 3,340
3,340
3,340
3,340
4.340
4,340
4,340
15 Capacity Additions (M)
0
0
0
0
0
1,D00
0 0
0
0
0
1,000
0
0
16 Capacity Replacements (kW)
0
0
0
0
0
0
0 0
0
2,000
0
0
0
0
17 Diesel Fuel Use (gallons)
339.654
348,145
356,849
365,770
374,914
384,287
393,895 403,74Z
413,835
424,181
434,786
445,655
456,797
468,217
18 Capital Costs (1990 S)
$0
SO
SQ
$0
$0
$700,000
SO S0
$0
$1,400,000
SO
$700,000
s0
SO
19 Fuel Costs (1990 $)
S305,6%
$317,561
$329,894
$342,706
$356,016
S369,843
$394,207 $399,128
$414.629
$430,733
$447,461
$464,&40
$482,893
$501.647
20 O & M Costs (19%$)
S163,034
$167,110
$171,288
S175,570
$i79,959
$164,458
$199,069 $193,796
$1%.641
$203,607
$208.697
$213,915
$219.262
$224.744
21 Total Peter Pon Costs (1990 $)
S468,723
$484.671
$501.182
SSIK276
$535,975
SL254,301
$573,276 $592924
$613.270
$ZO34,340
S656,158
$1,378,754
$702,155
$726,391
Z2 Total Annual Costs (1990s)
$W7,141
SB84,979
S913,761
$943,521
$974,294
S1.706,U6
S1,039,023 Si,073,053
$1,108,247
SZ544,647
$1,182,293
$1,921,232
S1,261,508
$1,303,170
HYDROPRO3ECT ANALYSIS
23 Finn Capacity (kW)
3,140
3,140
3,340
3,340
4.040
4,540
040 4,540
4,540
4,540
4.540
5,550
3.550
5,550
24 Diesel Capacity Additions (kW)
0
D
0
0
0
500
0 0
0
0
0
0
LOW
0
25 Capacity Replacements (kW)
0
0
500
0
D
0
0 0
0
0
0
0
21000
0
26 Hydroelectric Generation (kWh)
3,938,700
3.938,700
3,938,7D0 3,938,700
3,938,100
3,938,700
3,938,700
3,938,700
3,938;700
3,938,700
27 Dim] Generation (kWh)
6,175,408
6,3Z9,793
6,488,038
6,650,239
z877,795
3,049.207
3,222,880 3,401,920
3,595,435
3,773,338
3,966,344
4.t63,970
4,366,5V
4.574,168
Z8 Diesel Fact Use (Batton)
514.617
527,483
540,670
554,187
239,816
254,017
268,573 283,493
298,786
314,462
330,529
346,998
363.879
381,191
29 Capital Costs (1990S)
SQ
SO
$350,000
SO
SO
$350,000
SR $0
s0
SO
SO
$0
$4100.000
SO
30 Hydro Capital Cost
SO
$0
SO
SO
$6t6,00D
558&280
$561.807 $53026
$512,382
S489,325
$467,306
$446,277
S426,194
$407.016
31 Fuel Costs (1990 S)
$463,156
$481,143
S499,830
S519,242
$227,729
S244,469
S261„968 S280,254
$299,360
$319,318
$340,165
$361,935
$384,666
5408,397
32 O & M Casts (1990 $)
$247.016
SZ53,192
$259,522
$266,010
$469,595
$476,411
$483.398 $490,560
$497,900
$505,425
S513,137
$521.042
S529,144
$537.450
33 Total Annual Costs (1990 S)
S710,)72
$734,335
$1.109,351
$785.252
$1.313,323
$1,659,161
$1,307.173 $1,307,340
$1,309,642
S1,314,N8
S1,320,607
$1,329,753
$3,440,OD5
$1,352,B62
Table 1 I
ECONOMIC ANALYSIS
ENERGY REQUIREMFN-IS (kWh)
1 City Load
2 Peter Pan toad (10 0)
3 Total Community Load
DIESEL FUEL RATES
4 Annual Escalation Rate
5 Fuel Price (1990 Slgal)
BASE CASE ANALYSIS
(Disesl Generation only)
City System
6 Firm Capacity (kW)
7 Capacity Additions4kW)
8 Capacity Replacements (kW)
a Diesel Fuel Use (pa Ions)
10 Capital Costs (19%S)
I l Fuel Costs (1990 S)
12 O & M Costs (1990 $)
13 Total City Costs (1990 S)
Peter Pan System (1985 Data)
14 Firm Capacity (kW)
15 Capacity Additions (kW)
16 Capacity Replacements (kW)
17 Diesel Fuel Use (gallons)
18 Capital Costs (1990 $)
19 Fuel Costs (1990 S)
20 O J1 M Casts (1990 S)
21 Total Peter Pan Costs (19%$)
22 Total Annual Costs (1990 S)
HYDROPRO3ECT ANALYSIS
23 Firm Capacity (kW)
24 Diesel Capacity Additions (kW)
25 Capacity Replacements (kW)
26 Hydroelectric Generation (kWh)
27 Diesel Genetton (kWh)
28 Diesel Fuel Use (gallons)
29 Capital Costs (19905)
30 Hydra Capital Cast
31 FutiCosts(1990S)
32 0&MC0s1s(1990$)
KING COVE HYDROELECTRIC FEASIBILITY Economic Analysis City plus Peter Pan Loads
2004
2005
2006
Z007
24)(18
2009
2010
2011
2012
2013
2014
2W.S
2016
2017
Z018
2019
496N623
3,044089
3,116,809
3,194,729
3,174,591
3,356,462
3,440,374
3,526,383
3.614,542
3,704,9U6
3,797,529
3,892,467
3.989,779
4,089,523
4,191,761
4,296,555
5,759.067
5,903,043
6.050,619
6201,885
05032
6,515.855
6,678,752
6,845,720
7,016,863
7,19ZZ85
7,37ZO92
7,556,394
7,745,304
7.938.937
8,07,410
8,340,845
8,7L5,690
8,943,832
9,167.428
9.396.61.1
9,631.529
9,87Z317
10,H9,i25
10,372JW
10,631,406
10.697,191
11,160.621
11.448.861
11,735,M
12,028,460
14329,171
17,637,401
1.4%
1.4%
L4%
1.4%
1.4%
1.4%a
1.4%
1.4%
IA%
1.4%
1.4%
1.4'7
1.4%
1.4%
1.4%
1.4%
1.09
1.10
1.12
1.13
1.15
1.16
1.18
1.19
1.21
1. Z3
1.24
1.2 6
1.24
1.29
1.31
1.33
I,(00
1,0111t
MW
1.5W
1,51111
1.500
41544)
I,SW
11519)
1500
1.51N1
1,5u)
1.W
1.700
13W
1,700
0
0
0
5(141
It
0
0
0
0
4)
0
0
?(8t
0
0
0
0
0
0
0
S110
0
0
0
500
0
0
0
0
500
SO0
0
247.239
233,399
259,714
266,227
272A3
279,705
MOM
293,865
301,212
308,742
316.461
124.372
332AS2
340.794
149,313
35$046
$0
$0
SO
$350,(XM
$350,OM)
s0
s0
s0
E350,000
s0
$0
SO
$140,0W
S350,000
$350,000
SO
S268,446
$Z78,871
$289.702
S300,953
WZ642
$324,784
$337,39B
$350,501
$36-1,114
S318,255
$392,946
$408.207
$42-1,060
$440,530
$457.639
S475,412
5326,329
$334,497
$342,&19
$351,420
$360,206
$369,211
$378,441
S387,902
$397,6IX1
$407.540
$417,728
WS.171
S438;876
$449,848
S461.O94
$47Z621
$594,774
$613,3j8
$632,551
W2.373
S672,847
$693.995
$715,839
$738,403
S761,713
$785,795
$910.674
$836,378
$862,936
SBK377
$911033
$948,033
4,340
4,340
4,340
4,340
4,340
4,340
4.340
4,340
4.340
4,340
4,340
4,340
4,340
4,340
4.340
4,340
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
a
0
1,000
0
0
0
ZaaO
0
1,000
0
0
0
1,000
0
0
0
Z000
479,922
491,920
504,213
516,824
529,744
547,988
556,563
570,477
584,739
599,357
614,341
629,700
645.442
661.578
678,118
695,070
$0
S700,000
$0
SO
$0
$1,400,000
$0
$700,000
s0
SO
$0
S700,000
s0
s0
so
S1,400,000
S521,130
$541,369
S561395
$584,137
S606,927
S63%498
$654,985
M,4Z3
$706.849
$734,302
S76ZS20
$792,446
$823,223
Sass,195
$888,408
$922-912
S230,363
$236,122
SZ42,02S
S248,075
s254,271
S260,634
$267,150
$273.829
$280,675
$287,691
S294,884
$304256
S309,812
$317,557
$325,496
$333,634
$751,492
$1,477,491
M.419
S832,312
S861.204
SZ291,133
$922,155
S1,654,L52
$987,524
S1,021,993
S1,057,704
$1,794,702
$1,135,035
$1,174752
$1.213,905
$2,656,546
$1,346,2.67 $ZO90,849 S1,436,970 $1,484,685 $1.534,051 SZ985,121 111,631,974 $439Z656 $1,74%237 $1,807,788 11,868,377 S2,631,080 $1,995,971 SZO63,129 $2.132,637 S3,604,579
5,550
5,550
5,550
5,850
5,850
5,850
5,850
5,850
5,850
5,850
5,950
5,950
6,050
6,050
6,050
6,050
0
0
0
300
0
0
0
0
0
0
0
0
200
a
0
0
500
0
0
low
500
0
Z00o
0
I,o00
0
0
0
1,000
0
500
2,000
3,938,700
3,938,700
3,938,700
3.938,700
3,9A700
3,938,700
3.938,700
3,938,700
3,938,700
3,938,700
3,938,700
3,938,700
3,938,700
3,939,700
3.938,700
3.938,700
4,786,990
5,005,132
5,228,728
5,457,914
5,69ZB29
5.933,617
6,180,475
6,433,403
6.692,706
C958,491
7,Z30,9Z1
7.510,161
7,796,383
8,080,760
8,390,471
8,698,701
398,916
417,094
435,727
454,826
474,402
494,468
SIS,035
536,117
557,725
579,874
602,$77
625,947
649,699
674,147
699,206
724,892
$350.000
SO
$0
S910,000
$350,000
$0
$1,400,000
$0
S700,000
s0
$1.000,000
SO
S840,OW
SO
$350,DW
$1,400,000
$388,700
$371,208
$354,504
$338,551
$323,317
$30F1,767
$294,973
$281.603
$M931
$256.829
$Z45,272
S234,235
$723,694
$211,628
S204,015
SO
$433.169
$459,012
$486,001
S514,152
S543,522
$574,159
$606.114
S639,442
S674,195
$710,432
$746,212
S787,598
IM652
S871,441
$9KO36
$962,508
$545,963
$554.688
$563,632
$57ZB00
S5841%
S591,828
S601,700
S611,819
S624191
$632 8W
$643,770
$654,899
1666,339
$678,073
S690,102
$702,431
33 Total Annual Costs (1990 S)
$1,7t7,830 $1,384;918 S1,404,137 $Z335,503 11,799.034 $1,474,754 S4901687 €1,532,t164 SZ265,318 SJAW.084 $2,637,204 $1,676,722 %2558,684 $1.763,141 $2,160,153 S3,064;939
Table 1 I KING COVE HYDROELECTRIC FEASIBILITY Economic Analysis City Plus Peter Pan
I:Ct INOMIC ANALYSIS
zeo
2021
2022
z923
2W 1
ENERGY REOUIREMI:MIS (kWh)
I Ciryl. .d
1,403.WO
1,51-1,968
•1,626,92n
1,712.593
1.861.158
2 Peter Pan Ln:,d (I'Pttl)
8,549,367
8,763,101
8,982,i78
9,206,733
9,436,901
3 Total Community load
12,953,336
13,2Tf,169
13,ri09,098
13,949,326
1.1.296,059
DIESE1, FUEL RATFS
4 Annual Escalation Rate
1.4%
1.4-.
1.11T
1.4%
1.4%
5 Fuel Price (19W SIga4)
1.33
1.36
1.38
1.40
1.42
BASE CAST: ANALYSIS
{Dieeel Generation only)
City Systcm
6 Firm Capacity (MW
1,7t111
).7011
1,71M1
1,740
1,709
7 Capacity Additions (kW)
q
0
11
0
0
8 Capacity Replacements (kW(
Il
0
500
0
0
9 Diesel Fuel Use (gallons)
3wW7
376,172
385,571
3951216
405,096
10 Capital Costs (1990 S)
so
SO
$3500)(1
so
SO
11 Fuel Costs (19905)
$493,876
$513,051
$532,993
S553,683
$575.186
12 0 & M Costs (1990 S)
�
S484,437
5496,548
S508,961
5521.685
$534.727
13 Total City Costs (1990$)
S978,313
S1,009,605
$1.011,944
S1,075,366
S1,109,914
Peter Pan System (1995 Data)
1-t Finn Capacity (kW)
4.340
4,340
4.340
4,340
4,340
15 CapaevyAdditions (M)
0
0
0
0
0
16 Capacity Replacements (kW)
0
1,0t10
0
0
0
17 Diesel Fuel Use (gallons)
712,447
730,258
748,515
767,228
786.408
18 Capital Casts (1990 S)
s0
S7001(00
$O
$O
s0
19 Fuel Costs (1990S)
$958,755
$995,991
$1,034,673
S1,074,857
S1,116,602
20 0 & M Cnsts 09%$)
S341,975
S350,524
$359,287
$368.269
$377,476
21 Total Peter Pan Costs (1990 $1
S1,300,730
S2,01015
$1.393,960
$1.443.126
S1,494,078
22 Total Annual Costs (1990 S) $2,279,043 $3,056,120 $2,43S,904 $2,518,494 $2,603,991
HYDROPR03ECT ANALYSIS
23 Film Capacity (kW)
(i,050
6.050
6,050
6,00
6,050
24 Diesel Capacity Additions (kW)
0
0
0
0
0
25 Capacity Replacements {kW)
0
1,000
800
0
0
26 Hydroelectric Generation (kWh)
3,938,700
3,938,700
3.938,700
3,938,700
3,938.700
27 Diesel Gcnemiion (kWh)
9,014,636
9,3X469
9,670,396
10,010,626
10,359.359
28 Diescl Fuel Use (gallons)
751,220
778,206
805,867
834.219
863,280
29 Capital Costs (1990 S)
SO
$700.000
$560,000
s0
so
30 Hydro Capital Cost
s0
so
so
SO
s0
31 Fur€ Costa (1990 S)
$1,010,932
$1,061.386
$1,113,950
$1,16&709
$1,225,750
32 0 & M Costs (19905)
S715,068
S728,022
S741,299
S754,908
$766,857
33 Total Annual Costs (1990 S) S1,726,001 S2,489,408 $2,415,249 $1,923.617 S1,994,607
+ The analysis period is 30 years to reflect an anticipated project life of 50 years._
Where the City of King Cove monthly hydroelectric is less than demandLgztp•Gt, a
minimum diesel generation (line 16, Table 10) has been assigned to account for diesel
generation required to meet low flow periods. This minimum was derived by
comparing of estimated daily hydroelectric generation (for 1982 flow data) to 1990
City of King Cove daily electrical usage. This minimum load requirement value is
increased at the same rate as electrical load growth from the base year of 1994.
• Replacement cost for diesel generators will be $700 per kW with a generation life of
ten years for full-time diesel generation and 15 years for backup diesel generation.
This cost represents the cost of installing a new unit in King Cove powerhouse and was
developed from previous studies (3) and for a similar project in Akutan (18) and recent
supplier's price quotes for new generators.
• The City of King Cove diesel generation O&M costs will be .$0.11 ,per kWh. This
value represents the cost to maintain the generators and distribution --system. This value
is derived from PCE records by dividing the most recent three years average operating
expense ($212,329) by the most recent three years average power generated (1,995,100
kWh) to yield this value. This value does not include diesel fuel costs.
• Peter Pan O&M costs will be $0.04 per kWh to reflect values from an analysis of a
similar seafood processor in Akutan (17).
• Total project costs include estimated construction costs ( Section 5) and financing costs.
Construction costs include design, administration, and construction of the project.
Financing costs include banding costs, construction costs and a debt reserve fund.
Financing costs were assigned for this project by the AEA project manager.
• Annual debt service will be equal annual payments of the project spread over a 24 year
payback period at 8.0 percent interest.
• Hydroelectric generation assumptions have been developed in earlier section of this;
report and are used in this analysis.
• A $1,00,000 cost to replace the transmission cable from the power plant to the city is
added to year 2014 and represents the cost to replace the cable after its design life of
20 years. '
• Hydroelectric project O&M costs will be 0L,0-0?er kWh and represent the cost to
maintain the hydroelectric project, the bacels, and the distribution system.
07073.003:N:S:Di0 50
For this analysis, costs for all years are computed in inflation free 1990 dollars. The model
does not increase costs by inflation but calculates present value of future costs by using a
discount rate equal to the nominal interest minus inflation. This is the same method that was
used by AEA in 1988 (3).
The base year of economic analysis is 1990 as actual City generation data was available for that
year. The electric load and generation data of Peter Pan collected and used by AEA in 1985
(3) are used for this analysis. This data represents the most recent data collected for the seafood
processor. Peter Pan was contacted to discuss their generation system and any changes to that
system since 1985. These changes have been incorporated into this analysis.
Table 10 presents the economic analysis for a two 350 kW unit hydroelectric project serving
only the City of King Cove. The project is assumed to be delivering power by 1994. The base
case analysis assumes increasing the 800 kW present firm capacity through generation
replacements to 1,000 kW for capacity in 1992 and increasing capacity to 1,300 kW in 2002.
Firm capacity represents the required generation capacity to meet electric demand including
generator down time for repairs. Firm capacity is maintained through replacement of existing
generators in the years noted. The two existing old 300 kW City units would be replaced in
1992 with a single 500 kW unit under both cases. Other generation equipment replacements and
additions are shown. Some diesel generation will be required during each year because of low
creek flows. This is reflected as minimum diesel generation requirement in line 16. The
minimum was derived as noted in the previous assumptions. Electricity generated in excess of
the City needs and generator waste heat was assumed to have no value. No costs were included
for construction of new generator buildings.
Table 1 I presents a similar analysis of the Delta Creek hydroelectric project with the assumption
of one 700 kW hydroelectric generation unit installed to serve the City and Peter Pan by 1994.
Again replacement and increases in diesel generation capacity were developed from the
conversations with Peter Pan and as previously noted for Table 10. Electricity generated in
excess of the City and Peter Pan needs and generator waste heat was assumed to have no value.
It was assumed that Peter Pan and the City represent an infinite load and all hydroelectric
generation can be used. This assumption may not be valid because peak hydroelectric generation
may not correspond to peak electrical demands. Because this is a run -of -the -river project and
generation depends on flow in Delta Creek, a daily generation capacity should be estimated prior
to sale of electricity negotiations.
Table 10 shows the base case present value to be $15,372,000 and the hydroelectric present
value to be $15,137,000, with the 34 year cost -to -cost ratio 1.02. The project is defined as
feasible.
Table 11 shows the base case present value to be $35,442,000 and the hydroelectric present
value to be $35,431,000 with 34 year cost -to -cost ratio 1.00. The project is defined as feasible.
47073.003.N:8:DI0 51
A sensitivity analysis was conducted to determine the effect on the economic analysis of
changing the values of various assumptions. Figure 14 illustrates the sensitivity of hydroproject
assumptions and economic parameters for the project serving the City of King Cove demands
only (cross reference Tables 7 and 10). Figure 15 is the same analysis for the City and Peter Pan
loads (cross reference Tables S and 11). Each of the five assumptions shown in Figures 14 and
15 was tested by deviating their values, in 25 percent increments, up to plus and minus 50
percent of their original estimated value, and recording the effect of these changes on the project
cost -to -cost ratio. For example, note construction cost estimate line of Figure 14. At the
estimated construction cost of $7,602,000, the cost -to -cost ratio is 1.02. if, however, the cost
is underestimated by 50 percent, or if there is a 50 percent cost overrun on the project, then the
cost -to -cost ratio would be 0.84. If, on the other hand, the cost were to come in under budget
by 50 percent, then the cost -to -cast ratio would be 1.32. In both Figures14 and 15 none of the
eight assumptions, when varied independently by plus or minus 50 percent, caused the cost -to -
cost ratio to drop below 0.90 (defined as the lower limit of marginally feasible by AEA), except
a 50 percent decrease in initial fuel costand a 50 percent incerase in total project cost. Even
these factors caused the cost -to -cost ratio to be only slightly below 0.90. A combination of
factors, however, such as a large cost overrun accompanied by a drop in oil prices, could
conceivably cause the project cost -to -cost ratio to go below 0.90, and therefore, define the
project as not feasible.
07073.003:1:8:nin 52
1.4
1.3
1.2
0
1.1
0
U
0.9
0.8
ling Cove Hydroelectric, City Load Only
Sensitivity Analysis of 30 Year Economic Analysis
1...........
....... ..........
........ ... ....................
al. . ......... ....
1 .... ......
--Ou —40 u 25 50
Variation
-W Total Project Cost -4— Initial Fuel Prue -E- Real Dm mnt Rate
$ Comm Ioad Growth ->E Fw Fsr- Rate
Figure 14
LA
1.15
1.1
1.05
�3 1
0.95
0.9
0.85
King Cove Hydroelectric, City and Peter Pan Loads
Sensitivity Analysis of 30 Year Economic Analysis
-bu --"Z5 0 25 50
% Var Uon
f- TbW Prn Jed Goat --+-- TaiW keel Prig -CIE- Real D wowt Rate
-F3- Cmm. lad Grath -X- Fuel H,-- Rate
b5gute 15
8.0 PROJECT IMPLEMENTATION
8.1 REGULATORY REQUIREMENTS
The following is an overview of permitting and agency requirements that need to be addressed
prior to the design and construction of this project. This review, which was not requested as
part of this study, is not intended to be a definitive list and was developed by HDR's in-house
permitting and regulatory staff from previous hydroelectric project experience and review of
previous King Cove hydroelectric feasibility studies. No agencies were contacted as part of this
study. HDR recommends that all agencies be contacted prior to project implementation.
Federal Energy Re ulato Commission FERC
FERC normally does not claim licensing authority over hydropower projects that meet the
following criteria: (1) generate less than 1.5 megawatts (MW); (2) are not on navigable streams;
(3) will not affect interstate commerce by distributing power to areas served by the interstate
electric grid; and (4) and are not on federal lands (18 CFR). However, there is no prescribed
extent of FERC authority. FERC makes an independent determination of its authority for each
proposed hydropower project, and bases its determination on a project description and location
map submitted by the client. AEA requested a determination during previous hydropower
feasibility studies designed for Delta Creek, but there is no record of a determination being
made.
According to HDR Regulatory Specialist Neil McDonald, the proposed project stands a better
chance of a favorable (i.e. non -jurisdictional) determination if the impoundment only impounds
sufficient water to stop air entrainment in the penstock. This project appears to meet this
criterion, but that determination must be made by FERC. FERC licensing could be costly,
upwards of several hund4A thousphd dollars, if required. Therefore a determination by FERC
or locating the previous determination in AEA's files would be important before begining design
of the project. No FERC licensing costs have been included in project costs.
U.S. Army Corps of Engineers (COE)
The creek at the proposed site is not on the COE 1990 list of navigable creek or rivers;
therefore, the project would not require a Section 10 Permit from COE (for structures or work
affecting navigable waters of the United States).
The project would need an Individual Section 404 Permit from COE (for discharge of dredged
07073.003:N:8:D10 55
or fill material into waters of the United States) for construction of the diversion, penstock, and
powerhouse where these structures affect wetland areas. The buried transmission cable could
fall under a Nationwide Permit Number 12 (utility line placement in waters in the United States).
However, if the cable is stink in King Cove Lagoon, a Section 10 permit would be required
because this work would be below mean high tide and therefore in navigable water.
U.S. Environmental Protection Agency (EPA)
Because this project may degrade water quality due to diversion cleaning, a National Pollutant
Discharge Elimination System (NPDES) permit may be needed.
U.S. Fish and Wildlife Service USF&WS
The Fish and Wildlife Coordination Act requires federal agencies who are proposing to control
or modify a body of water to first consult with USF&WS and the National Marine Fisheries
Service (NMFS). For this project, the COE would seek comments from USF&WS and NMFS
during the COE permit application process. USF&WS and NMFS do not issue any permits
independently.
Alaska Department of Natural Resources ADNR
ADNR issues Dam Safety Permits to dams over ten feet tall that impound more than 50 acre-feet
of water. The proposed project does not exceed either threshold limit. ADNR also requires
permits to darns of any size whose failure under non -storm conditions would damage life or
property downstream. The areas downstream from both proposed sites are uninhabited but are
developed. There would be a potential minor threat to the raceway and the powerhouse from a
clearwater tributary dam failure.
Earlier studies noted that there are no known archaeological or historical sites in the proposed
project area (14). The State Historic Preservation Office in the Division of Parks and Outdoor
Recreation may require a pre -construction archaeological survey of the area.
"A Water Rights Permit is required from the Director of the Division of Land and Water
Management, Alaska Department of Natural Resources, for any person who desires to
appropriate waters of the State of Alaska. However, this does not secure rights to the water.
When the permit holder has commenced to use the appropriated water, he should notify the
director, who will issue a Certificate of Appropriation that secures the holder's rights to the
water." (14)
Alaska Department of Conservation (ADEC)
If the power generating process does not add chemicals or waste heat to the creek water, nor
discharge domestic sewage or gray water, nor require operation of heavy equipment on site after
construction, the project should be in compliance with ADEC water quality requirements. The
07073.001:N:8:1)1(1 56
project might result in the discharge of silt into the water during diversion cleaning which may
require a permit from ADEC (14).
ADEC would review any applications to the COE, FERC, and the Alaska Department of Fish
and Game if the project falls under the regulatory purview of those agencies.
Alaska Department of Fish and Game (ADF&G)
Delta Creek is an anadromous fish stream, as catalogued by ADF&G. Three species of salmon
(pink, chum, and coho) all spawn in the creek. Delta Creek also has a population of resident
Doily Varden trout. Upstream of the powerhouse, only about 500 feet of the creek is usable fish
habitat (9). The proposed project is anticipated to reduce the flow between the proposed intakes
and the powerhouse all months of the year and would possibly eliminate 90 percent or more of
the flow within this section of the creek for approximately nine months out of the year. This
section might not be dewatered, however, because there are several small tributaries entering
the creek between the diversion and the powerlouse.
Reducing or eliminating the creek flow would have a direct effect on the usable fisheries habitat
above the powerhouse. This habitat modification might require mitigation. Previous studies
have included work with ADF&G to address mitigation for this project. In 1984, discussions
took place between AEA and ADF&G concerning mitigation for habitat modification above the
powerhouse. These meetings resulted in a consensus agreement that appropriate mitigation
might be the elimination of the "road" crossings or fords of Delta Creek between the airport and
Lenard Harbor.
Investigations into this mitigation performed by HDR in November, 1990, revealed that there
is no "road" between the airport and Lenard Harbor. The "road" is an undefined 4-wheeler trail
along the creek. The trail takes the easiest route to Lenard Harbor and happens to cross Delta
Creek and its tributaries in numerous spots. Work to modify this trail may not be appropriate
because the trail changes as the infrequent users find easier routes along the creek.
It should also be noted that a powerhouse tailrace channel would be constructed. In order to
ensure that the powerhouse would not be impacted by potential flood, it should be located 200
feet or more from the existing Delta Creek channel. The tailrace will be low gradient in order
to use as much of the available head as possible for power generation. This low gradient
constant water supply channel could be constructed for fish habitat as mitigation for
modifications to Delta Creek.
Division_ of Governmental Coordination (DGC)
If the project requires a federal permit or permits from more than one state agency, the Division
of Governmental Coordination will oversee coastal consistency review process to determine
whether the project complies with the State and District Coastal Management Programs.
07073.0o3:N:8:D10 57
For this analysis of the proposed hydroelectric project, no costs for mitigation are included.
These costs are undetermined because the type and extent of mitigation is not known.
07073.003:1:8;I)lo 58
8.2 LOCAL REQUCREMENTS
The Aleutians East Borough (AEB) Coastal District Coordinator must determine whether the
proposed project is consistent with the Borough's federally -approved Coastal Management Plan.
The proposed project appears consistent with the AEB Coastal Management Plan; it does not
affect the historic or optimal productivity of fish and wildlife populations important for
commercial and subsistence use, limit other industrial or infrastructure development, limit
recreation, or affect any known cultural resources. Moreover, the proposed project appears to
meet the AEB goal of developing cost-effective renewable energy systems that do not adversely
affect fish and wildlife populations and habitats (Aleutians East Coastal Resource Service Area
Conceptually Approved Coastal Management Plan, July 1985).
8.3 RIGHTS -OF -WAY
Federal
"Any party wishing to use land or facilities of any National Wildlife Refuge for purposes other
than those designated by the manager -in -charge and published in the Federal Register must
obtain a Special Use Permit from the U.S. Fish and Wildlife Service. This permit may
authorize such activities as right-of-ways; easements for pipelines, roads, utilities, structures,
and research projects; and entry for geological reconnaissance or similar projects, filming and
so forth. Note that all lands that were part of a National Wildlife Refuge before the passage of
the Alaska Native Claims Settlement Act and have since been selected and conveyed to a Native
corporation will remain under the rules and regulations of the refuge (13)". It is not clear what !
permits or right-of-way may be required because of the wildlife refuge jurisdiction over these }
creeks.
State ,
The proposed project would require a right-of-way from the Alaska Department of Natural
Resources (ADNR) for placement of the transmission cable across state tidelands and submerged
lands if it were placed in or across King Cove Lagoon.
Trenching of the buried transmission line within Alaska Department of Transportation and Public
Facilities road right-of-way will require a permit from that agency to do so.
Local
The transmission cable route from the power house to the power distribution point in town might
require a right-of-way from the City.
07073.003:N:8:v10 59
Private
"The proposed dam and penstock sites are on lands owned by King Cove Native Corporation.
The diversion weir, borrow site, and penstock locations at Delta Creek and the road proposed
for construction from the airport to the powerhouse and on up to the diversion weirs are entirely
on lands conveyed to the King Cove Village Corporation as part of their entitlement under the
Alaska Native Claims Settlement Act (ANCSA), Public Law 92-203. The existing road from
the airport to King Cove and the proposed transmission line to King Cove are also within the
King Cove Village Corporation property boundary. The subsurface estate has been interim
conveyed to the regional Native corporation, Aleut Corporation, for all of the lands in the
project area for which King Cove Village Corporation has the surface rights." (13). The
project would be on Corporation lands and would require rights -of -way from the Corporation.
Costs associated with these right-of-way and permits, if any, have not been incorporated into
project costs.
If routed across private lands, the transmission cable will require rights -of -way. The cable could
cross the parcel occupied by Peter Pan Seafoods or the adjoining tidelands, both privately owned
or leased. In town, the cable may have to cross private lands, including residential lots,
depending on the selected route.
8.4 PROJECT SCHEDULE
After a decision to construct, the following would be required to bring this project on-line:
1) obtain required permits and licenses;
2) design power project;
3) award contract and construct project; and,
4) commission and debug hydroelectric plant.
The permitting process would take several months to a year to complete, as agency meetings
would be required. This process could run concurrently with project design and construction.
Turbines for hydroelectric projects are typically individually manufactured for a specific project.
Conversations with turbine manufacturers as part of this study and information gathered as part
of previous studies (13) indicated that manufacture and delivery to Seattle of a selected turbine
and generator would take approximately one year. An additional six months would be required
for development of turbine specifications, bidding, and award of contracts. The turbine could
be purchased by the City of King Cove or AEA to decrease project development time by several
months. The equipment could be supplied to the contractor constructing the project. Although
this is frequently done, the City of King Cove or AEA could be liable for change orders if
delivery is delayed, or if the system is nonfunctional. The liability issue should be addresses
prior to making the decision to prepurchase a turbine.
07073.003:N:8,n10 60
Design and preparation of bidding documents for this project should take approximately ten
months. Bidding and award of the construction contract should take approximately four
additional months.
In estimating construction time it is assumed the contractor would begin work at Delta Creek
in early summer; May or June. In order to do this the contractor would need to order materials
(except the turbine, see above) in February or early March. Therefore, contracts should be
awarded in January. if construction could begin in May or early June, the major items of
construction should be completed by October, if there are no unexpected delays. The entire
process from award to finish of construction would take approximately one year.
Hydroelectric projects need a commissioning and debugging period, as do all major mechanical
construction projects, before they can supply firm power. This process has been estimated to
take three months (13).
Assuming the permitting and design process begins in June, 1991, and the turbine is supplied
by the construction contractor, firm power could be available from the project by mid -March,
1994.
07073.003A:8:niu 61
9.0 RECOMMENDATIONS
Recommendation of a project depends greatly upon the load option selected, This is a political -
economic decision that is outside the scope of this report. On a technical basis, Delta Creek
hydroelectric has many advantages.
At the present time, the City of King Cove, by itself, does have a large enough load to make
a hydroelectric project feasible. When the load increases, or the price of fuel rises, a City -only
hydroelectric project would become more feasible. Diesel electric generation will always be
required, because the City load is nearly constant over the year while hydroelectric generation
varies with flow regime, During low flow periods (January to April at least) supplemental
electrical generation would be required. A project constructed with guaranteed power sales to
Peter Pan Seafoods might decrease costs of power for the City and Peter Pan. Peter Pan might
only wish to buy power for specific processing seasons, such as salmon. In other seasons, Peter
Pan might wish to rely on their diesel powe,rplant. The guarantee of potential power sales to
Peter Pan during specific times where excess hydroelectric generation is available should be
investigated.
The construction costs and power generation potential estimated in this report are believed to be
conservative. Construction costs could be reduced by several factors, which have been presented
in previous sections.
The economic analysis shows a 700 kW hydroelectric project serving the City only or the City
and Peter Pan is feasible at this time. Both options would have diesel versus hydroelectric cost -
to -cost ratios greater than one (1.0). For either option the City and Peter Pan would have to
maintain standby and peaking diesel capacity. Hydroelectric generation could, for the economic
analysis period, provide nearly all the City's demands and substantial amounts of Peter Pan's
demands.
As the project economic analysis indicates, a hydroelectric project is feasible, This study
recommends the environmental and permitting issues noted in Section S be thoroughly
investigated through meeting with permitting agencies and discussing the project in detail, Once
these issues are resolved, project design and implementation should begin.
07073.003AA.D 10 62
10.0 BIBLIOGRAPHY
1. Alaska Department of Community and Regional Affairs, Division of Bottomfishing, City of King
Cove Community Comprehensive Plan, January 1981. Prepared for the citizens of King Cove.
2. Alaska Department of Natural Resources, Division of Geological and Geophysical Surveys, A
Geotechnical Investigation of the Proposed King Cove Hydroelectric Weir Site on Delta Creek,
Alaska, September 1984. Final report to the State of Alaska Power Authority and Department
of Commerce and Economic Development.
3. Alaska Power Authority, King Cove Hydroelectric Feasibility Study, July 1988.
4. CH2M Hill, Preliminary Technology Profiles Reconnaissance of Energy Requirements and
Energy Alternatives for Kodiak Island Villages and Sand Point and King Cove, December 1980.
5. CH2M Hill, Reconnaissance Study of Energy Requirements and Alternatives for Akhiok Kin
Cove, Larsen Bay, Old Harbor, Ouzinkie, Sand Point, June 1981. Prepared for the Alaska
Power Authority_
6. CH2M Hill, Summary Reconnaissance Study of Energy Requirements and Alternatives for King
Cove, July 1981. Prepared for the Alaska Power Authority.
7. DOWL Engineers, King Cove Hydro Project, Miscellaneous Topographic Mapping, 1981.
8. DOWL Engineers, King Cove Hydroelectric Project Feasibility Study, January 1983. "A Report
on Continuous Field investigations of Delta Creek Relative to Aquatic Biology and Hydrology".
Prepared for the Alaska Power Authority.
9. DOWL Engineers, King Cove Hydroelectric Project Feasibility Study, Continuous Field
Investigations of Delta Creek Aquatic Biology and Hydr&gy, May 1984. Prepared for the
Alaska Power Authority,
10. DOWL Engineers, Feasibility Study for King Cove Hydroelectric Project Supplemental Data
Report:_ Hydrology, May 1985..Prepared for Alaska Power Authority.
11. DOWL Engineers, Preliminary Stream Flow Records October 1985 Through January 1986,
February 1986, Prepared for the Alaska Power Authority.
12. DOWL Engineers, Stream Flow Records January 1986 through April 1986, Delta Creek Near
King Cove, September 1986.
07073,003:NA: U 10 63
13. DOWL Engineers, in association with Tudor Engineering Company and Dryden and LaRue,
Financial Analysis for King Cove H, dry oelectric Project, May 1984. Prepared for the Alaska
Power Authority.
14, DOWL Engineers, in association with Tudor Engineering Company and Dryden and LaRue,
Feasibility Study for King Cove Hydroelectric Project, Volume II Draft Report, February 1982.
Prepare for the Alaska Power Authority.
15. Ebasco Services Incorporated, Regional Inventory and Reconnaissance Stud,for Small
Hydropower Project, Aleutian Islands, Alaska Peninsula, Kodiak Island, Alaska, Volume II
Community Hydropower Reports, October I980, Prepared for the U.S. Army Corps of
Engineers, Alaska District.
16. Fryer/Pressely Engineering, Inc., Gambell Waste Heat Recovery Report and Concept Design,
May 1, 1990. Prepared for the Alaska Energy Authority.
17. Gemperline, Eugene, J., M. ASCE, Considerations in the Design and Operation of Hydro
Power Intakes Cold Re ions Hydrology and Hydraulics, 1990, pgs. 157-556. A State of the
Practice prepared by the Technical Council on Cold Regions Engineering of the American
Society of Civil Engincers. Edited by William L. Ryan and Randy D. Crissman.
18. HDR/OTT Engineering, Inc, in association with Dryden and LaRue, Inc, Akutan Hydroelectric
I~easibilitkStudy, June 1990.
19. Henningh, Gary, King Cove Manager, Personal Communication, 1990.
20. King Cove, Alaska, Discharge Measurements, Jame 1985 field trip.
21. Ott Water Engineers, Inc., Hydropower Design Manual, January 1983.
22. Reconnaissance Study of Energy Requirements and Alternatives for Akhiok, King Cove, Larsen
Bay, Old Harbor, Ouzinkie, Sand Point: Findings and Recommendations, May 1981.
23. R.W. Retherford Associates International Engineering Company, Inc., Ram Creek Potential at
King Cove for Alaska Power Authority, March 1980.
APPENDICES
Table 1 lists the total yearly production, maximum capacity, and power factor for 32-inch, 34-
inch, and 36-inch steel pipe and 5 to 50 cfs turbine range.
TABLE A-1
PENSTOCK SIZE SELECTION
Pipe Size
(inches)
Total Yearly
Production
(MEGAWATT-HRS)
Maximum
Capacity
(kW)
Plant Factor
Average Head Loss
32
3 940
72I
0.69
12 %
34
4100
775
0.64
8 %
36
4210
812
0.65
6 %
Selection of pipe size will be based upon the economic of power loss vs- pipe cost. Typically
ten percent is considered a reasonable trade off.
APPENDIX 2
DETAILED COST ESTIMATE
GENERAL
This appendix presents the method and assumptions used to estimate the construction costs of
the selected hydropower options. Following this methodology are tables itemizing the major
costs. These tables are arranged with a summary sheet at the beginning, showing the cost of
each major task, followed by supporting tables itemizing those task costs. All costs are based
on 1990 dollars.
METHODOLOGY
In order to produce accurate cost estimates, a structured cost estimating method was established.
The development of this method was based on a task breakdown of the total project_
Mobilization &. Logistics, Diversion Structures, Penstock, etc. (see summary sheet). A
supporting table for each task was developed, which includes a major cost breakdown for that
particular task. The cost estimating method was then to price all materials FOB Seattle, barge
the materials and equipment to King Cove, truck the materials & equipment to the site, add the
labor, equipment and camp support costs to construct the project. These costs were then
compared to previous report estimates.
MATERIALS
The preliminary design and layout of facilities was used to estimate the quantities of materials
needed for each task. These materials were then priced, FOB Seattle, using supplier's
information and comparing the costs to previous studies. For any shop fabricated materials, a
shop time was estimated then multiplied by a shop labor rate.
FREIGHT
Freight costs for the materials Iist was estimated using 1990 barging rates from Seattle to King
Cove. The weight and size of the materials was determined using supplier's and previous report
information. A spring delivery date to Seattle was assumed. Trucking from King Cove to the
construction site is based on the labor and equipment crew method explained below.
LABOR AND EQUIPMENT
Material and freight costs are fairly straightforward and fixed. However, labor and equipment
costs in "Bush" Alaska are very sensitive to existing conditions. In order to estimate these costs
accurately a labor and equipment crew breakdown was used, instead of a unit price per task.
Four construction crews were developed. Each crew is assigned to a certain operation, the
Diversion Crew will build the diversion structures, the Powerhouse Crew will work on the
powerhouse, etc. These crews consist of selected laborers and equipment necessary to perform
the intended operation. The labor costs are based on the Davis Bacon Wages (including
overhead) and a 60-hour week. The equipment costs are based on equipment rental rates for a
month plus overhead and maintenance, These labor and equipment rates were then reduced to
cost per day and then summed to calculate a crew cost per day for actual operation. To find the
actual cost for labor and equipment on a given construction phase, the estimated days of
construction is multiplied by the corresponding crew cost per day. The primary assumption
made here is the estimation of the length of time required for a crew to complete a construction
phase, which were based on previous studies and construction experience in King Cove.
CAMP COSTS
In order to compensate for crew down -time, a camp cost estimate was developed. This cost
estimate was calculated two different ways and the results compared for a final determination
of an estimate. The main assumption was an average of 14 men camp for five months. The two
methods of calculation were:
1) Use of previous report cost and inflated to 1990 dollars, which yielded
$200/person/day.
2) Two camp cooks at $587/day (Davis Bacon Wages) and supplies plus food at
$150/camp day, which yielded $192/person/day
GENERAL SUPERVISION
The general supervision cost is based on the labor cost and expenses for someone to oversee the
project.
TRANSMISSION LINE
The only exception to the stated cost estimating method is the cost estimate of the transmission
line. Since this task will probably be contracted out to a specialty contractor, construction costs
were based on information from two different experienced Alaskan contractors specializing in
transmission line construction. The materials are fixed cost, however, trenching is dependent
upon the soil characteristics. The trenching costs were based on geology reports and are the
average of the two contractors estimated costs.
TOTAL PROJECT COSTS
The total project cost includes the following costs, based as a percentage of the sum of materials,
labor, and equipment costs: administration (3 %), engineering (11 %), construction management
(7%) and contingencies (20%). The total project cost does not include permitting costs, any
mitigation costs, or cost to do any indepth design studies. These studies may include additional
sediment load work, and flow recording of each tributary.
Appendix XI Table 1
AEA - King Cove Hydropower
Summary Sheet
Component
Days
Labor
Equip.
Mobilization & Logistics
225
$89,320
$23,439
Diversion Structures - (Clear
62
$213,693
$49,011
Water & Glacial Tributaries)
Penstock
66
$176,496
$286,880
Powerhouse & Tailrace
21
$63,551
$59,056
Transmission Line
60
$521,400
$0
Total
434
$1,064,460
$418,386
Construction Subtotal
Total Weeks
Adminstration (3%)
Engineering (11%)
Construction Management (7%)
Contingency (20%)
Administrative Subtotal
TOTAL COST
USE
$4,033,016
72
$120,990
$443,632
$282,311
$ 806,603
$1,653,537
$5,686,553 (1990 Dollars)
$5,687,000 (1990 Dollars)
(Two 35OkW Turbines & Generator)
Material Total
$767,855
$81,331
5416,507
$1,036,757
$247,720
52,550,170
$880,614
$344,036
$879,883
$1,159,363
$769,120
$4,033,016
Table 1 Page 1
Appendix II Table 1
AEA - King Cove Hydropower (Two 350kW Turbines & Generator)
Mobilization & Logistics
Item
Crew Days
Labor
Equip.
General Supervision
210
$66,000
$0
Freight
0
$0
$0
Trucking
Trucking 15
$23,320
$23,439
Camp Costs
0
$0
$0
Misc. Standby Equip.
0
$0
$0
Materials Profit
MOB. TOTAL
225
$89,320
$23,439
Material
Total
Comments
$0
$66,000
$261,230
$261,230
From Seattle to King Cove (includes equip. return to Seattle)
$0
$46,759
From dock to construction site
$425,600
$425,600
Lump Sum based on daily camp costs
$11,220
$11,220
3% of Freight, Trucking and General Supervision
$69,805
$69,805
10% of materials
$767,855
$880,614
Table 1 Page 2
Appendix II Table I
AEA - King Cove Hydropower (Two 350kW Turbines & Generator)
Diversion Structures (Clear Water & Glacial 'Tributaries)
Item
Crew
Days
Labor
Equip.
Material
Total
Comments
Clear Water Tributary
6' High Sheet Pile Dam:
Sheet Piling
Diversion
15
$51,700
$11,858
$23,600
$87,158
20' Sections
Concrete
Diversion
15
$51,700
$11,858
$8,900
$72,458
Riprap
Diversion
1
$3,447
$791
$o
S4,237
Sluice Gate
Diversion
1
$3,447
$791
S300
$4,537
Misc. Materials
0
$o
$0
$1,224
$1,224
3% of Materials
Intake Structure:
Barrel Screen
Diversion
2
S6,893
$1,581
$8,000
$16,474
Subtotal
34
$117,187
$26,877
$42,024
$186,088
Glacial Tributary
Weir:
Sheet Piling
Diversion
10
$34,467
$7,905
$12,600
$54,972
20' Sections
Concrete
Diversion
10
$34,467
$7,905
$4,444
$46,816
Pill
Diversion
2
$6,893
$1,581
$0
$8,474
Boulders (Riprap)
Diversion
1
$3,447
$791
$0
$4,237
Sluice Gate
Diversion
1
$3,447
$791
$300
$4,537
Iron Boulder Deflector
0
$0
$0
$800
$800
Prefaberacated steel
'H' Piling
Diversion
2
$6,893
$1,581
$840
$9,314
Misc. Steel
0
$0
$0
$930
$930
3% of Materials
Intake Structure:
Screen
Diversion
1
$3,447
$791
$11,200
$15,437
Box (steel)
Diversion
1
$3,447
$791
$800
$5,037
Subtotal
28
$96,507
$22,134
$31,914
$150,554
Materials Profit
$7,394
$7,394
10% of materials
DIVERSION TOTAL
62
$213,693
$49,011
$81,331
$344,036
Table 1 Page 3
Appendix 1I Table 1
AEA - King Cove Hydropower (Two 350kW Turbines & Generator)
Penstock
Item
Crew
Days
Labor
Equip.
Material
Total
Comments
Penstock
24" steel pipe
Earthwork
2
$5,955
$9,679
$8,450
$24,083
Clear Water to Connection (250')
30" steel pipe
Earthwork
2
$5,955
$9,679
$8,450
$24,083
Glacial Fork to Connection (250')
32" steel pipe
Earthwork
42
$105,040
$170,734
$204,000
$479,774
Connnection to Powerhouse (6000')
Trestle
For creek crossing
Steel
Earthwork
2
$5,955
$9,679
$1,200
$16,833
Concrete
Earthwork
4
$11,909
$19,358
$12,800
$44,067
Trestle foundation & Anchor blocks
Misc_ Appurtances
0
$0
$0
$11,745
$11,745
5% of mat. costs, bedding not included
Screened Bedding
0
$0
$0
$46,000
$46,000
Classified Fill ($10/C.Y.)
Subtotal
52
$134,814
$219,128
$292,645
$646,587
Road Construction
1) 1/2 mile Access Rd.
Earthwork
14
$41,683
$67,752
$0
$109,434
Airport to Powerhouse
Classified Fill
0
$0
$0
$21,500
$21,500
Fill
0
$0
$0
$19,165
$19,165
Culverts
0
$0
$0
$12,000
$12,000
6 culverts @ $2,000 ea.
2) Penstock Rd, (6,000 FT.)
built at the same time as the penstock
Fill
0
$0
$0
$9,333
$9,333
6" minus road surface
Culverts
0
$0
$0
$24,000
$24,000
12 culverts @ $2,000 ea.
Subtotal
14
$41,683
$67,752
$85,998
$195,432
Materials Profit
$37,864
$37,864
10% of materials
PENSTOCK TOTAL
66
$176,496
$286,880
$416,507
$879,883
Table 1 Page 4
Appendix 11 Table 1
AEA - King Cove Hydropower
Powerhouse & Tailrace
Item
PREFAB. METAL BLDG.
HVAC
Lighting
Concrete Floor
Earthwork
Erection.
Subtotal
TURBINE & GENERATOR
Installation
Mechanical
Electrical
Start Up
Turbine & Gen. Subtotal
Station Auxiliary,
City of King Cove
Power Plant
New Control Panel
Metalclad Switchgear
Installation
King Cove Junction
Metalclad Switchgear
Installation.
System Telemetry
Misc.
Gen. Support Subtotal
Materials Profit
POWERHOUSE TOTAL
(Two 350kW Turbines & Generator)
Crew
Days
Labor
Equip.
Material
Total
Comments
0
$0
$0
$20,500
$20,500
1,750 SF, insulated
Powerhouse
1
$3,051
$1,799
$35,000
$39,849
Powerhouse
1
$3,051
$1,799
$14,000
$18,849
Earthwork
3
$8,932
$14,518
$103,700
$127,150
Earthwork
4
$11,909
$19,358
$0
$31,267
Includes site preperation, tailrace
Powerhouse
4
$12,203
$7,194
$0
$19,397
13
$39,145
$44,667
$173,200
$257,013
0
$0
$0
$458,500
$458,500
Two 350kW Turbines and generators
Powerhouse 2
$6,101
$3,597
$0
Powerhouse 2
$6,101
$3,597
$0
Powerhouse 2
$6,101
$3,597
$0
6
$18,304
$10,792
$458,500
Powerhouse 2
$6,101
$3,597
$90,000
$9,699
$9,699
$9,699
$487,596
$99,699 Includes Control & Protection, Switchboard Equ
& Grounding System
0
$0
$0
$24,000
$24,000
0
$0
$0
$52,000
$52,000
0
$0
$0
$17,000
$17,000
0
$0
$0
$87,000
$87,000
0
$0
$0
$40,806
$40,806 3% of materials
2
$6,101
$3,597
$310,806
$320,505
$94,251
$94,251 10% of materials
21
$63,551
$59,056
$1,036,757
$1,159,363
Table 1 Page 5
Appendix II Table 1
AEA - King Cove Hydropower (Two 350kW Turbines & Generator)
Transmission Line
Item
Transmission Line
Cable
Trench Excavation
4.5 miles (Gravels)
0.5 miles (Rock)
Materials Profit
TRAM TOTAL
Crew Days Labor Equip. Materia Total Comments
0 0 $0 $0 $225,200 $225,200 Standard URD, 3 phase, 3o cable
Includes backfill
0 0 $415,800 $0 $0 $415,800
0 0 $105,600 $0 $0 $105,600
$22,520 $22,520 10% of materials
0 60 $521,400 $0 $247,720 $769,120 Specialty Contractor Bid Item
Table 1 Page 6
Appendix II Table 2
AEA - King Cove Hydropower (One 700kW Turbine & Generator)
Summary Sheet
Construction
Days
Labor
Equip.
Material
Total
Mobilization & Logistics
225
S89,320
$23,439
$767,855
$880,614
Diversion Structures - (Clear
62
$213,693
$49,011
$81,331
$344,036
Water & Glacial Tributaries)
Penstock
66
$176,496
$286,880
$416,507
$879,883
Powerhouse & Tailrace
16
$48,517
$40,941
$845,545
$935,003
Transmission Line
60
$521,400
$0
S247,720
$769,120
Total
429
$1,049,427
$400,270
$2,358,958
$3,808,656
Subtotal
$3,808,656
Total Weeks
72
Adminstration (3%)
$114,260
Engineering (11%)
$418,952
Construction Management (7%)
$266,606
Contingency (20%)
$761,731
TOTAL COST $5,370,204 (1990 Dollars)
USE $5,370,000 (1990 Dollars)
Table 2 Page 1
Appendix II Table 2
AEA - King Cove Hydropower (One 700kW Turbine & Generator)
Mobilization & Logistics
Item
Crew Days
Labor
Equip.
Material
Total
Comments
General Supervision
210
$66,000
$0
$0
$66,000
Freight
0
$o
$0
$261,230
$261,230
From Seattle to King Cove {includes equip. return to Seattl
Trucking
Trucking 15
$23,320
$23,439
$0
$46,759
From clock to construction site
Camp Costs
0
$0
$Q
$425,600
$425,600
Lump Sum based on daily camp costs
Misc. Standby Equip.
0
$0
$0
$11,220
$11,220
3% of Freight, Trucking and General Supervision
Materials Profit
$69,805
$69,805
10% of materials
MOB. TOTAL
225
$89,320
$23,439
$767,855
$880,614
Table 2 Page 2
Appendix 11 Table 2
AEA - King Cove Hydropower (One 700kW Turbine & Generator)
Diversion Structures (Clear Water & Glacial Tributaries)
Item
Crew
Days
Labor
Equip.
Material
Total
Comments
Clear Water Tributary
6' High Sheet Pile Dam:
Sheet Piling
Diversion
15
$51,700
$11,858
$23,600
$87,158
20' Sections
Concrete
Diversion
15
$51,700
$111858
$8,900
$72,458
Riprap
Diversion
1
$3,447
$791
$0
$4,237
Sluice Gate
Diversion
1
$3,447
$791
$300
$4,537
Misc. Materials
0
$0
$0
$1,224
$1,224
3%n of Materials
Intake Structurc:
Barrel Screen
Diversion
2
$6,893
$1,581
$8,000
S16,474
Subtotal
34
$117,187
$26,877
$42,024
S186,088
Glacial Tributary
Weir. -
Sheet Piling
Diversion
10
$34,467
$7,905
$12,600
$54,972
20' Sections
Concrete
Diversion
10
$34,467
$7,905
$4,444
$46,816
Fill
Diversion
2
$6,893
$1,581
$0
$8,474
Boulders (Riprap)
Diversion
1
$3,447
$791
$0
$4,237
Sluice Gate
Diversion
1
$3,447
$791
$300
$4,537
Iron Boulder Deflector
0
$0
$0
$800
$800
Prefaberacated steel
'H' Piling
Diversion
2
$6,893
$1,581
$840
$9,314
Misc. Steel
0
$0
$0
$930
$930
3% of Materials
Intake Structure:
Screen
Diversion
1
$3,447
$791
$11,200
$15,437
Box (steel)
Diversion
1
$3,447
$791
$800
$5,037
Subtotal
28
$96,507
$22,134
$31,914
$150,554
Materials Profit
$7,394
$7,394
10% of materials
DIVERSION TOTAL
62
$213,693
$49,011
$81,331
$344,036
Table 2 Page 3
Appendix II Table 2
AEA - King Cove Hydropower (Two 350kW Turbines & Generator)
Penstock
Item
Crew
Days
Labor
Equip.
Material
Total
Comments
Penstock
24" steel pipe
Earthwork
2
$5,955
$9,679
$8,450
$24,083
Clear Water to Connection (2501)
30" steel pipe
Earthwork
2
$5,955
$9,679
$8,450
$24,083
Glacial Fork to Connection (250')
32" steel pipe
Earthwork
42
$105,040
$170,734
$204,000
$479,774
Connnection to Powerhouse (6000')
Trestle
For creek crossing
Steel
Earthwork
2
$5,955
$9,679
$1,200
$16,833
Concrete
Earthwork
4
$11,909
$19,358
$12,800
$44,067
Trestle foundation & Anchor blocks
Misc. Appurtances
0
$0
$0
$11,745
$11,745
5% of mat. costs, bedding not included
Screened Bedding
0
$0
$0
$46,000
$46,000
Classified Fill ($10/C.Y.)
Subtotal
52
$134,814
$219,128
$292,645
$646,587
Road Construction
1) 1/2 mile Access Rd_
Earthwork
14
$41,683
$67,752
$0
$109,434
Airport to Powerhouse
Classified Fill
0
$0
$0
$21,500
$21,500
Fill
0
$0
$0
$19,165
$19,165
Culverts
0
$0
$0
$12,000
$12,000
6 culverts @ $2,000 ea.
2) Penstock Rd. (6,000 FT.)
built at the same time as the penstock
Fill
0
$0
$0
$9,333
$9,333
6" minus road surface
Culverts
0
$0
$0
$24,000
$24,000
12 culverts @ $2,000 ea.
Subtotal
14
$41,683
$67,752
$85,998
$195,432
Materials Profit
$37,864
$37,864
10% of materials
PENSTOCK TOTAL
66
$176,496
$286,880
$416,507
$879,883
Table 2 Page 4
Appendix 11 Table 2
AEA - King Cove Hydropower
Powerhouse & Tailrace
Item
PREFAB. METAL BLDG
HVAC
Lighting
Concrete Floor
Earthwork
Erection
Subtotal
TURBINE & GENERATOR
Installation
Mechanical
Electrical
Start Up
Turbin & Gen. Subtotal
Station Auxiliary
City of King Cove
Power Plant
New Control Panel
Metalclad Switchgear
Installation
King Cove Junction
Metalclad Switchgear
Installation
System Telemetry
Misc.
Gen. Support Subtotal
Materials Profit
POWERHOUSE TOTAL
Crew
Powerhouse
Powerhouse
Earthwork
Earthwor';
Powerhouse
Powerhouse
Powerhouse
Powerhouse
Powerhouse
Days
0
z
z
2
2
2
8
0
Labor
$0
$3,051
$3,051
$5,955
$5,955
$6,101
$24,112
$0
2 $6,101
2 $6,101
2 $6,101
6 $18,304
2 $6,101
(Otte 700kW Turbine & Generator)
Equip.
$0
$1,799
$1,799
$9,679
$9,679
$3,597
$26,552
$0
$3,597
$3,597
$3,597
$10,792
$3,597
Material
Total
Comments
$14,350
$14,350
1,225 SF, insulated
$24,500
$29,349
$9,800
$14,649
$72,590
$88,223
$0
$15,633
Includes site preperation, tailrace
$0
$9,699
$121,240
$171,904
$345,000
$345,000
One 700kW Turbine and generator
$0 $9,699
s0 $9,699
$0 $9,699
$345,000 $374,096
$90,000 $99,699 Includes Control & Protection, Switchboard ERu
& Grounding System
0 $0
$0
$24,000
$24,000
0 $0
$0
$52,000
$52,000
0 $0
$0
$17,000
$17,000
0 $0
$0
$87,000
$87,000
0 $0
$0
$32,437
$32,437 3% of materials
2 $6,101
$3,597
$302,437
$312,136
$76,868
$76,868 10% of materials
16 $48,517
$40,941
$845,545
$935,003
Table 2 Page 5
Appendix 11 Table 2
AEA - King Cove Hydropower
Transmission Line
Item
Transmission Line
Cable
Trench Excavation
4.5 miles (Gravels)
0.5 miles (Rock)
Materials Profit
TRAN.TOTAL
(One 700kW Turbine & Generator)
Crew Days Labor Equip. Material Total Comments
0 0 $0 $0 $225,200 $225,200 Standard URD, 3 phase, 3o cable
Includes backfill
0 0 5415,800 $0 $0 $415,800
0 0 $105,600 $0 $0 $105,600
$22,520 $22,520 1.0% of materials
0 60 $521,400 SO $247,720 $769,120 Specialty Contractor Bid Item
Table 2 Page 6
Appendix II Table 3
AEA - King Cove Hydropower
Crew Definitions
Labor
Casual Laborcr
Foreman
Equip. Operator
Welder
Electrician
Mech. HVAC
Total Labor $/Day
Equipment
CAT 980
JD 350
Dyn 190
CAT D-6
CAT D-8
10 CY
Compactor
Truck
Total EQ $/Day
Total $/Day
(Support Data For Tables 1 & 2)
CREW NAME
$/Day Powerhouse Earthwork
$367
3
3
$513
1
1
$455
1
3
$469
$513
1
$469
1
$3,051
$2,977
$1,435
$236
$555
$804
$1,546
$855
$200
$128
1
1
1
$1,799
$4,849
1
1
1
1
1
$4,839
$7,817
Diversion
3
1
3
1
$3,447
1
1
$791
$4,237
Trucking
3
1
$1,555
1
1
$1,563
$3,117
Table 3 Page 1
Appendix II Table 3
AEA - King Cove Hydropower
Labor Rates
$/HR Raw Overtime
Category Rate Rate
(Support Data For Tables 1 & 2)
`Overhead
& Profit
Per Day $/Day
Casual Laborer
$25.00
$37.50
$75.00
$366.67
Foreman
$35.00
$52.50
$105.00
$513.33
Equip. Operator
$31.00
$46.50
$93.00
$454.67
Welder
$32.00
$48.00
$96.00
$469.33
Electrician
$35.00
$52.50
$105.00
$513,33
Mech. HVAC
$32.00
$48.00
$96.00
$469.33
Average $/Day assumes 60 hr week and over time, Davis -Bacon wages
* Additional 30% of straight time pay to account for overhead costs and profit.
Overhead includes bond, property damage liability insurance, unemployment
insurance contributions, social security and other taxes.
Table 3 Page 2
Appendix 11 Table 3
AEA - King Cove Hydropower
Equipment Rates
Name
Type $/HR
(Support Data For Tables 1 & 2)
$/Day
CAT980
FE Loader
$143.45
$1,434.50
]D 350
Dozer
$23.60
$236.00
Dyn 190
Backhoe
$55.45
$554.50
CAT D-6
Dozer
$80.39
$803.90
CAT D-8
Dozer
$154.62
$1,546.20
10 CY
Dump
S85.48
$854.80
Compactor
Self Propelled
$20.00
$200.00
Truck
Fiat Bed
$12.81
$128.10
Average $/Day assumes a 10 hr day
Table 3 Page 3