HomeMy WebLinkAboutAlaskan Hydropower - By John S. Whitehead 1983MANAGING WATER RESOURCES
FOR ALASKA'S DEVELOPMENT
PROCEEDINGS
James W. Aldrich, Chairman
Alaska Section
American Water Resources Association
Institute of Water Resources
University of Alaska
Fairbanks, Alaska 99701
Report IWR-105 November 1983
l
ALASKAN HYDROPOWER: BALANCING THE LONG RUN ADVANTAGES
WITH THE SHORT RUN PROBLEMS
By John S. Whitehead
Abstract
Hydroelectric facilities have been operating in Alaska since the turn
of the twentieth century. Through the use of historical documents drawn
from twelve hydro installations, this paper looks at the historical
performance record of Alaskan hydropower. The analysis compares the
advantages of hydropower with its disadvantages in terms of electric power
prices, operational reliability, capital financing, power demand growth
projections, and legislative intervention in the operation of the
installations, The advantages and disadvantages are analyzed in terms of
short run and long run time frames.
Introduction
Over the last decade the promotion of new hydroelectric power projects
has been particularly strong in Alaska. Much debate has taken place in the
public media both for and against this expanded use of Alaska's water
resources. The debate has become particularly heated since 1981 when the
Alaska legislature authorized $460 million for energy related projects
including funds for the construction of seven medium-sized hydroelectric
projects as well as feasibility and reconnaissance studies of a dozen
potential projects ranging in size from a few thousand kilowatts to the
mammoth 1.6 million KW Susitna project (SLA 1981, Chap. 90).
Advocates of hydropower often point to the use of a renewable energy
source, water, which would free the state from the use of fossil fuels with
ever escalating costs. Hydro is also claimed to provide stable and pre-
dictable power prices. Opponents often cite such disadvantages as runaway
capital costs, environmental hazards and cheaper kilowatt hour costs coming
from alternative sources such as natural gas. In the debate, as it appears
in the media, there is rarely any systematic reference to Alaska's actual
lAssociate Professor, Department of History, University of Alaska, j
Fairbanks, 99701
i
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experience with hydropower. At best, selected statistics from particular
projects, sometimes from projects in other states, are brought forward.
In order to compile a systematic account of Alaska's actual experience
with hydroelectric power I examined the records and operational histories
of 12 hydroelectric facilities which were operational .or under construction
in the summer of 1981 (see Table 1). The selection covers plants built
between the early 1900s and the present day and ranging in capacity from
1600 KW to 47,160 Kw. It includes plants in both southeast and
southcentral Alaska --the only areas of the state with major hydroelectric
facilities. The survey reveals that hydropower has had definite long run
advantages in terms of power price and operational reliability over periods
of 30-50 years. On the other hand definite short run problems in terms of
power price and operational reliability have occurred over periods of less
than 10 years. Such problems have been great enough, in some cases, to
jeopardize the financial viability and continued operation of certain
projects. The principal tool used to balance the short run problems with
the long run advantages has been legislative intervention in the operation
of the projects (Whitehead, 1983).
Long Run Advantages
In general the histories reveal that in the long run (i.e. 30-50
years) hydroelectric projects have fulfilled and exceeded the expectations
of their builders for three primary reasons. 1) Hydroelectric projects
were responsible for bringing reasonably priced --and in some cases very low
priced --electric power to Alaskan communities from the turn of the century
to the early 1960s--and into the 1980s in southeastern Alaska. 2) The
operation of Alaska's hydro projects has been extraordinarily reliable with
examples of plants in continuous operation from 1913 to the present day.
9.-2
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3) The long operational life of some plants has led to decreasing costs
over time.
Low Priced Power.
Throughout the history of Alaska in the 20th century, the high cost of
living has been a constant and recurring theme. One element in that high
price has been electricity generated by imported fossil fuels --primarily
diesel generation. Before the discovery of natural gas on the Kenai
Peninsula and in Cook Inlet in the late 1950s and early 1960s, the lowest
priced power in Alaska was hydropower.
Ketchikan was the first city in Alaska to have low priced power
Ketchikan's first developed water resource, Ketchikan Creek, was placed in
service as early as 1903. By 1922 Ketchikan, with a population of approxi-
mately 2,500, had a utility capacity of 2,600 KW and a power price of a
little over 2� per kwh (Dort, 1924). Steady growth in the capacity of the
Ketchikan Lake facility from 1923 to 1957 and construction of the Heaver
Falls facility in 1946-47 gave Ketchikan a system capacity of 10,000 KW in
1957 with a power price under 2C per kwh--less than the U.S. national
average. In that year 500 kwh cost $9.88 in Ketchikan versus $10.81 in
Juneau, $14.50 in Anchorage, and $27.50 in Fairbanks where there was no
hydropower. Ketchikan's low prices resulted in an average annual power use
of 5,800 kwh per residential customer compared to 3,780 kwh in Juneau,
3,759 kwh in Anchorage, and 2,800 kwh in Fairbanks (USFPC, 1960).
Hydropower was responsible for making Ketchikan Alaska's most electrified
city in the first half of the 20th century.
Juneau's experience with hydropower was similar to Ketchikan's
Several hydroelectric plants were constructed in Juneau before World War I
by various :private industrial corporations to power stamp mills in the gold
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mining industry. Surplus power was then sold to a private utility, Alaska
Electric Light and Power, for distribution to utility customers (Stone,
1980). Juneau's electric rates, while not as low as Ketchikan's, were
nonetheless reasonable. In 1922 AEL&P's rates varied from 3-6C per kwh
depending on use (Dort, 1924). In 1957 Juneau still offered power at an
average of 3p per kwh (USFPC, 1960).
Juneau and Ketchikan both had utility systems based on modern hydro-
electric plants before the Second World War. Reasonably priced electricity
was the norm in these cities. More dramatic illustrations of the effect of
hydropower on electric prices can be seen in areas that began utility
production with less efficient power systems and later switched to modern
hydro facilities.
From 1912 to 1961 Sitka relied on an antiquated utility system which
was composed at varying times of two 160 KW hydro generators, an ineffi-
cient steam electric plant, and diesel generators. in 1950 Sitka's system
had a capacity of 2,000-3,000 KW, depending on the season, and produced
power at 7-8p per kwh (USBR, 1954). In 1957 500 kwh sold for $26.50 (5.31,
per kwh). But few customers could get this price for such large
consumption as the average annual use was only 1750 kwh per customer or
only 150 kwh a month (USFPC, 1960). In 1961 the modern Blue Lake hydro
project went on line. By 1968 power prices had dropped to $19 per 500 kwh
with a rise in annual customer consumption to 6,516 kwh (USFPC, 1969).
In Anchorage a similar scenario took place. The city's first hydro
installation, the 1,000 KW Eklutna Creek project, began production in 1929.
Unfortunately, hydro development did not keep pace with Anchorage's post
World War 11 growth. In 1947-48 Anchorage with an estimated population of
19,000 had a system capacity of 6,800-7,700 KW, including 2,000 KW in
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hydro, 1,300 KW in diesel generators, and the remainder in a makeshift
steam electric system salvaged from a beached naval vessel. Power was
priced at $17.08 per 500 kwh (3.4¢ per kwh), but the production cost of the
steam and diesel power was 1C per kwh above that price. The low cost of
the hydropower subsidized the non -hydropower to create the relatively
reasonable price of 3.40 per kwh (USSR, 1948). With the completion of the
30,000 KW Eklutna hydroelectric plant in 1955 prices dropped to $14.50 per
500 kwh (2.9Q per kwh) by 1957 (USFPC, 1960).
The experiences of Ketchikan, Sitka, Juneau, and Anchorage certainly
indicate that hydropower was the key to bringing the first reasonably
priced electricity to Alaska.
Long Run Dependable Operation
Hydroelectric plants in Alaska have compiled a record of long term
reliable operation reaching decades beyond the term in which it takes to
amortize their capital costs. (Federal projects are scheduled to payout in
50 years. Municipally financed projects payout in shorter periods of
approximately 30 years.) The Ketchikan Lakes facility has been operating
continuously since 1923, though its capacity has been increased from 2,600
KW (1923) to 4,200 KW (1957). The 1923 facility was in fact a
refurbishment of a 1912 plant. So the date of reliable continuous opera-
tion can be increased by a decade.
Two particularly striking instances of long, reliable operational
lives are the Annex Creek and the Salmon Creek projects in Juneau. Con-
structed in 1913-14 and 1915--16 respectively, they were Juneau's basic
source of electricity until 1973 (Stone, 1980). The plants were owned
until 1972 by a California firm, A-J Industries, which sold wholesale power
to the local utility, AEL&P, for retail distribution. A-J Industries kept
a.
the facilities in poor physical repair after the Alaska -Juneau mine closed
in 1944 and also made no public disclosures of the financial aspects of its
hydroelectric operations. As a result the U.S. Bureau of Reclamation as
well as AEL&P considered both Annex and Salmon Creek outmoded and ineffi-
cient facilities. They both assumed that these plants would be closed
after the Snettisham plant began operation. In 1972 AEL&P purchased the
entire power system of A-J Industries with the expectation that it would
use only the company's transmission and distribution lines, not its
operating facilities (Whitehead, 1983).
In 1973 the new 47,160 KW Snettisham project went on line. Problems
with its transmission system, however, led to repeated power outages in it
first years of operation, thus forcing AEL&P to continue to use Annex Creek
and Salmon Creek for base load power production. The utility discovered
that the operation, both physical and financial, of these plants was so
reliable that it has continued to run them 365 days a year after the
transmission problems at Snettisham were corrected (Whitehead, 1983). In
fact, the continued reliable and economical operation of these plants has
caused an underconsumption of Snettisham power (see Short Run Prob-
lems --Surplus Capacity).
Rather than being junked as outdated projects, both Annex Creek and
Salmon Creek are being refitted for automatic control operation which will
further reduce their operating cost. The generating capacity of both
plants is also being increased with loans from the Alaska Power Authority
(SLA, 1981, Chap. 90).
Decreasing Costs Over Time
Hydroelectric projects have high capital costs compared to their
operating costs; the price of electricity produced is thus composed of a
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substantial cost, from 50-90% in some cases, to amortize .the capital and a
smaller amount for operation and maintenance. If the capital component of
the project remains operational after its initial cost has been amortized,
the price of power production will obviously drop to the operation and
maintenance costs --unless a large new infusion of capital is required to
rehabilitate the project. Such decreasing costs over time have been
acknowledged by utility operators in Juneau and Ketchikan--though reliable
historic cost data in these locations is hard to come by. It appears, for
example, that in 1981 the Annex Creek and Salmon Creek facilities could
produce power for less than 20 mills per kwh compared to 22.5 mills per kwh
charged by A-J Industries in 1962.
Possibly the most reliable data to illustrate the decreasing cost
phenomenon can be found in the Eklutna plant in Anchorage, operated by the
Alaska Power Administration. Eklutna went on line in 1955 and is now more
than halfway into its 50 year payout schedule which will terminate in 2005.
In that year the price of Eklutna power should fall dramatically. A few
figures will help illustrate this. In 1979 the wholesale power rate at
Eklutna was 12.5 mills per kwh. More than half of the price, however,
included interest and amortization expenses. The operation and maintenance
costs at Eklutna for FY 1979 were $693,928; if the allowance for plant
depreciation is added the costs rise to $882,496. These costs divided by
the firm annual energy generation of 153 million kwh would yield a price
for Eklutna power of 5.8 mills per kwh, including depreciation, or 4.5
mills per kwh, excluding depreciation. It is possible that operation and
maintenance expenses may rise over the years. In fact, APA announced a 21%
price increase in January 1980. This, however, may be offset by increased
production through rewinding the generators and upping their capacity by
i
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15%. Soon after the turn of the 21st century, it is definitely possible
that Eklutna will be producing power for less than 10 mills per kwh in 2005
prices. Few other known sources of power offer such possibilities (APA,
1980).
Short Run Problems
While the long run advantages cited above make a convincing case for
hydropower in Alaska, the histories of the twelve facilities in my study
revealed a number of short run problems which in some cases called the
continued use of hydropower into question and in others produced a re-
markably high price for power. The principal short run problems were 1)
high power prices resulting from the debt service costs of new projects, 2)
substantial variations in the annual water flow --and consequently of the
annual power production --in some projects, 3) competition from natural gas,
and 4) underconsumption of power.
High Power Prices Resulting From Debt Service Costs
The completion of Sitka's Blue Lake project in 1961 brought reasonably
priced power to that community. By 1969 Blue Lake was beginning to reach '
its installed capacity, based on a low reservoir level, of 6,000 KW. To -
prepare for future demand the city purchased a 2,000 KW diesel generator in
addition to 1,100 KW in diesel units that it already owned. Several good
water years after 1969 staved off the need to generate substantial quan-
tities of diesel power. But by 1978-79 Sitka was generating 10-15% of its
powers needs through diesel production. Consequently, the price of 500 kwh
of power, which had risen from only $19 in 1968 to $20.90 in 1976, rose to
$25.60 in 1979. Diesel generation was eroding Sitka's reputation of
low-priced electricity. (Official Statement $54,000,000, 1979).
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To re-establish total hydropower generation the city embarked on plans
to construct the 16,500 KW Green Lake project with a $54 million bond sale.
The city was able to market the bonds at 7 5/8% interest in 1979, but under
conditions which were far from ideal. The bond underwriters, Dillon Read
and Co. required Sitka to refinance its outstanding utility debt as a
portion of the new bond issue. Thus the city was forced to pay 7 5/8%
interest on some of the Blue Lake bonds it had sold in 1961 for 4%. The
utility was also required to raise its electric rates so that revenues
would bring in 1.25 times the amount required for debt service. This
translated into an overall 45% increase in Sitka's electric rates. That
500 kwh of power which cost $25.60 in 1979 rose to $38 in November 1980.
(Official Statement $54,000,000, 1979).
The debt service requirements to build Green Lake raised Sitka's power
price in the short run far beyond what it would have cost to add small
annual increments of diesel generation. The city was willing to accept a
substantial, though predictable, rate increase from hydropower to prevent
the potentially uncontrollable rate rise which might come from ever in-
creasing diesel generation in the long run. Sitka had to pay now for what
it hoped would be cheaper power in the future.
.Annual Waterflow Variation
Substantial variations in annual waterflow and a consequent variation
in annual power production have occurred at two hydroelectric facilities in
southcentral Alaska--Eklutna and Cooper Lake.. While the average energy
production over any decade has been reliable, the peaks and valleys in
individual years require closer examination as potential problem areas.
Before Eklutna was constructed, the Bureau of Reclamation noted that
it did not have sufficient streamflow data to make accurate predictions for
9` 10 i
Eklutna's firm annual energy production, The Bureau set a target in 1948
of 100 million kwh of critical year firm energy and 43.6 million kwh of
non -firm energy (USBR, 1948). More streamflow data was accumulated during
the years of construction, and the Bureau revised the critical year esti-
mate to 137 million kwh in 1955. Later the figure was raised to 153
million kwh. _.
In the first decade of Eklutna's operation water flow was sufficient
to maintain a level of generating capacity substantially above the critical
year estimates. The good years, however, came to an end in 1969. From
1969 to 1976 a period of poor water years severely lowered Eklutna's power
production. The Alaska Power Administration, the operator of Eklutna, drew
down the reservoir for a number of years to maintain capacity, but in 1973
even this option was no longer viable. In FY 1974 Eklutna produced only
86.5 million kwh of power --less than 57% of its estimated firm annual
production. Low power production continued in FY 1975. Exceptionally good
water years, however, came after 1976, and in FY 1980 Eklutna produced
198,864 kwh or 130% of its firm annual supply. Table 2 illustrates the
power variation at Eklutna (APA, 1980)..
A similar water flow problem has been encountered at the Cooper Lake
hydro project, operated by the Chugach Electric Association. Cooper Lake's
annual firm energy output is approximately 41 million kwh. Chugach rep-
resentative Tom Kolasinski noted in 1981 that annual generation has fluctu-
ated between 24 and 60 million kwh. As a result of this fluctuating water
flow, Chugach did not deem it feasible to raise Cooper Lake's original
installed capacity of 15,000 KW to the anticipated 30,000 KW (Whitehead,
1983).
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Table 2
Annual Generation of Eklutna Power Project
Fy Million kwh
1955
43.8b
1956
119.3b
1957
136.7
1958
164.5
1959
165.8
1960
188.2
1961
198.8
1962
150.5
1963
156.5
1964
159.1
1965
135.3c
1966
138.9
1967
184.2
1968
164.3
1969
168.0
1970
160.8
1971
127.3
1972
159.2
1973
142.8
1974
86.6
1975
120.9
1976
160.2d
1976 (Third Quarter)
24.7
1977
174.4
1978
193.6
1979
153.0
1980
198.9
1981
196.3
a Source: Alaska Power Administration, March 1982.
b Project capability exceeded demand in early years of operation.
c
Low production mainly due to draw down of reservoir in 1964 to permit
repairs to earthquake damage.
d After Fy 1976 the federal, fiscal year changed from July 1-June 30, to
October I -September 30. This entry covers July 1, 1976, to September
30, 1976.
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Annual water flow variation and a resulting variation in power produc-
tion are expected in all hydroelectric projects. But the variation in
Anchorage seems high. At Eklutna, production has fluctuated between 199
million kwh and 87 million kwh--a drop of 57% from the high to the low.
Similar figures hold for Cooper Lake. By comparison, power production in
Ketchikan has fluctuated between 68 million kwh and 57 million kwh for all
three plants in its municipal system --a drop of 16% from the high to the
low. One may well wonder if such wide variations as those in Anchorage
indicate that hydropower in certain locations is an unreliable power
source. What would have happened if low water years had come 10 to 15
years earlier when Anchorage was more dependent on Eklutna's production?
In 1957, for example, the energy demand in Anchorage was 154 million kwh.
If Eklutna's .production had dropped from 140-150 million kwh to 86.6
million kwh, Anchorage would have faced a power crisis. The two utilities
with operating capacity, Chugach and the Anchorage Municipal Light and
Power Department, would have been hard pressed to fill the gap from their
steam and diesel plants since their combined capacity was little more than
half of Eklutna's 30,000 KW.
Alaska Power Administration head Bob Cross has noted that the varia-
tion in Eklutna's production requires closer scrutiny. Before 1968 APA
operated Eklutna on a "critical year" mode. Water in the reservoir was -
conserved in good water years so that the firm target of 137 million kwh
could be met in poor water years. After 1968, when hydro was no longer the
major source of power in Anchorage, APA shifted its mode of operation to
"maximum annual energy production." Under this mode all the available
reservoir capacity was used for energy production in good years rather than
stored for poor years. According to Cross a severe drop in power
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production would not have occurred if poor water years had come earlier.
He estimated that under critical year operation Eklutna could still have
produced 130 million kwh annually under drought conditions (Whitehead,
1983).
Cross' explanation is helpful. But let us look at the figures again.
Even under "critical year" operation, the variation in Eklutna's power
production would have been substantial if a drought had occurred. From
1958 to 1968 Eklutna produced substantially more than 137 million kwh,
except in the earthquake year of 1964. .If a drought had come in the late
1950s or early 1960s, Eklutna's production could have fallen by as much as
65-70 million kwh from a high of 199 million (1961) to an estimated low of
130 million kwb--a drop of 35% between the high and the low. Chugach and
AML&P would not have been as hard pressed to generate the difference with
diesel and steam, but the price of electricity would certainly have risen
in the days before cheap natural gas became an alternative fuel (Whitehead,
1983).
Much of my above concern is hypothetical. The poor water years came
after Eklutna had acquired a reputation for good service to Anchorage and
at a time when alternate energy production from natural gas was cheaper
than hydropower. But what about such variations in future projects?
Consumers who have enjoyed an abundance of cheap hydropower for a series of
good water years may react negatively to a drop in hydro production and a
consequent rise in electric rates, if power must be generated from a more
expensive source. Such a short term public reaction could cause problems'
in Alaska where positive public opinion is often critical in securing state
legislation and approving local bond proposals for a new hydro facilities.
In future hydro developments it may be wise to make the potential
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fluctuations in production known to consumers. It might even be advisable
to include an allowance for alternative fuel generation in the rate
structure to smooth out any variation in power prices between good and poor
water years.
Competition From Natural Gas in Southcentral Alaska
The opening of the Eklutna plant in 1955 established hydropower as the
preferred form of electrical generation in the Anchorage load area. Six
years later Chugach Electric Association opened its 15,000 KW Cooper Lake
plant on the Kenai Peninsula. In the late 1950s and early 1960s plans were
proposed by the U.S. Corps of Engineers to build the 46,000 Kid Bradley Lake
project; Chugach also obtained a federal license to build the 10,000 KW
Grant Lake plant. Hydro advocates also pushed for federal construction of
the 580,000 KW Devil Canyon (Susitna) project 150 miles north of Anchorage
By 1964 most of the enthusiasm for new hydro construction in the
state's largest load area was over. The Corps of Engineers announced that
there would be no demand for Bradley Lake power, even though the project
was authorized for construction in the Flood Control Act of 1962. Chugach
abandoned it plans for Grant Lake. Since 1962 not one kilowatt of
hydropower has been added to the Anchorage system (Whitehead, 1983). What
happened?
The answer is simple. Discoveries of natural gas on the Kenai Penin-
sula in 1957 and later at the Beluga Field in Cook Inlet undercut the cost
of hydro production by a half. Electricity from combustion turbines could
be generated for less than 5 mills per kwh compared to 11 mills for Eklutna
power and a projected 9-10 mills per kwh for Bradley Lake hydro. Chugach
opened its first combustion turbine plant at Bernice Lake in 1963 and
installed its first gas facility at the Beluga field in 1968. The price of
9-15
Chugach gas power dropped to $12.95 per 500 kwh in 1968 compared to the
$14.50 per 500 kwh it charged for hydropower in 1957 (USFPC, 1960, 1968).
By 1976 Chugach had installed 316,000 KW in gas power compared to 15,000 KW
in hydro (USFPC, 1976). Gas turbine electricity effectively stopped the
construction of new hydroelectric facilities in the Anchorage load area.
What effect did it have on the existing facilities?
The purchasers of Eklutna power --Chugach, the Anchorage Municipal
Light and Power Department, and the Matanuska Electric Association --were
tied to 25 year contracts. Chugach also continued operation of Cooper
Lake. So no immediate move to discontinue existing production developed.
However, after the 1964 Anchorage earthquake concern mounted that the
long-term contracts for Eklutna power might not be renewed when they
expired. The cause for concern lay in the cost of repaying earthquake
damage at Eklutna.
On the day of the earthquake, March 27, 1964, both Eklutna and Cooper
Lake sustained little visible damage. Both facilities were able to gener-
ate power within a few hours after minor repairs. Later investigations at
Eklutna in July of 1964 revealed that there had been settling at the base
of the dam and a general weakening of the structure. It soon became
evident that substantial rebuilding of the dam, particularly of the
spillway, would have to take place (USBR, 1966).
The repairs were completed at a cost of $2,885,415. Under the terms
of the original Eklutna Act of 1950, this cost would have to be fully
reimbursable through power rates --an effective 1 mill -� g p per kwh increase. By
the late 1960s, the increasing use of natural gas for electrical generation
led the Department of Interior to be concerned over the potential effect of
the 1 mill increase. In 1968 an assistant secretary in the department told
Congress that "this rate differential ... will add to the problem created by
current competitive natural gas prices in future contract negotiations for
Eklutna Power." (U.S. Congress, 1968). In response Congress intervened in
September 1968 and passed Public Law 90-523 making all but $80,000 of the
repairs non -reimbursable. This legislation, coupled with the fact that
Eklutna had generated more revenue in power sales prior to 1968 than had
originally projected, allowed the Alaska Power Administration to lower
Eklutna's prices by 10% in 1968 (APA, 1969).
When the time came to renew the power contracts in the late 1970s (the
contracts would expire in 1980), the Alaska Power Administration had no
problem finding purchasers for Eklutna power at 12.5 mills. The rising
price of natural gas and Anchorage's ever increasing demand for power made
Eklutna's electricity fully competitive. It does not appear that the
legislation of 1968 was particularly important a decade later in contract
negotiations. The long run stable price and availability of Eklutna power
were its selling points.
The legislation of 1968 did, however, have a more important effect of
the future development of hydroelectric power. It set a precedent for
legislative intervention in the financial operation of a facility.
Alaskans would not forget it. They would use the 1968 law as a precedent
in asking the federal government to intervene in the financial operation of
the Snettisham plant in 1976 for reasons much less dramatic than earthquake
damage.
Surplus Capacity
The Eklutna project was built to meet an acute shortage of power for
utility customers in a rapidly growing load area. Three years after going
on line, Eklutna was selling more than its annual firm energy capacity (see
i
i
9-17
Table 2). In contrast, the substantially larger Snettisham plant near
Juneau was built with the assumption, really the hope, that a full demand
for its power would develop in 2-3 decades. I£ such hopes failed to
materialize, or if the power growth was considerably off schedule, the
project would have surplus capacity. The price of power per kwh would
obviously have to rise to higher than projected levels to pay off the fixed
capital costs. Depending on how much surplus capacity existed, the price
rise could be minimal or it could be substantial. Surplus capacity could
have the effect of making hydropower one of the most expensive forms of
electricity. Why was the federal government willing to take such a risk in
building Snettisham?
Snettisham was not originally planned with surplus capacity in mind.
When the project was first designed in the late 1950s by the U.S. Bureau of
Reclamation, it was to be a supplier of industrial power. Specifically,
Snettisham would provide power for a pulp and newsprint mill to be built by
the Georgia-Pacific Corporation. The hydro facility would thus promote the
economic development of the timber industry in southeastern Alaska. Of the
facility's projected annual energy production of 292 million kwh, 230
million kwh would go to Georgia-Pacific and only 47.4 million kwh would go
for utility use. The remaining 14.6 million kwh would be absorbed in
transmission losses. Based on these assumptions the Bureau recommended in
1959 that Snettisham be constructed (USBR, 1959).
The planning for Snettisham changed abruptly in June 1961 when
Georgia-Pacific Corporation announced that it would not build its newsprint
plant. On the surface of things, it would appear that there was no longer
any justification for building Snettisham. But by 1961 Juneau residents, _
Alaska's new congressional delegation, and the Bureau of Reclamation itself
3
were so committed to seeing Snettisham built that the project had almost
taken on a life of its own. In November 1961 the Bureau of Reclamation
revised its estimates of Juneau's potential utility growth over the next
two decades and concluded that if Snettisham were built in stages, it would
be feasible for utility production alone. It would take approximately a
decade longer for utility demand to reach the level originally proposed for
industrial demand. According to the Bureau, a rise in the price of power
produced from 6.1 mills per kwh to 7.47 mills per kwh would make Snettisham
feasible (USSR, 1961).
These new planning estimates assumed that the existing hydro facil-
ities in Juneau (Annex Creek and Salmon Creek) would be retired when
Snettisham came on line. The projections also assumed a certain surplus
capacity or underconsumption of power in the early years of operation. But
at 7.47 mills per kwh, enough revenue would be generated in later years to
offset initial deficits and hence to pay out the project in the standard 50
year period for federally financed installations. In essence, Snettisham's
new payout schedule resembled a "balloon mortgage" for a home. The deci-
sion to take the risk with such a forecast of initial surplus capacity was
not the original plan; it was one which developed to save the project in
mid -stream.
Snettisham was authorized for construction by Congress in the Flood
Control Act of 1962 (P.L. 87-874). After many delays in receiving
appropriations, the Long Lake stage was completed in 1972-73 at a cost
roughly 50% greater than the amount authorized in 1962. As a result, the
price of Snettisham power rose from the projected 7.47 mills per kwh to
15.6 mills per kwh. This was still lower than the price A-J Industries had
charged for its hydropower. The price rise resulting from escalating
construction costs was the least of Snettisham's problems.
During its first three years of operation (1973-76), Snettisham's
transmission line was constantly problem -prone. As a result, Snettisham
was out of service for months at a time. Repairs were made, but finally
the Alaska Power Administration relocated the line in 1976. The total cost
for repairs and relocation was $11 million --all of which was required by
law to be reimbursable through increased power rates.
The failure of Snettisham's transmission line was only part of the
facility's problem. By 1976 it was evident that Snettisham was simply not
selling as much power as had been projected. As late as 1979 Snettisham
sold only 80.45 million kwh or less than half of its 168 million kwh of
firm annual energy. What caused such underconsumption? (APA, 1980)
As noted earlier, Snettisham's transmission line failures led AEUP to
depend on hydro power from its older facilities (Annex Creek and Salmon
Creek) and to continue using them after Snettisham went back into service.
The permanent operation of Annex Creek and Salmon Creek thus took an annual
40-50 million kwh of the market away from Snettisham. In addition, the
1961 estimates of Juneau's projected utility demand had been too optimis-
tic. From 1960 to 1973 growth in demand had been closer to 7.6-7.8% rather
than the "conservative" 9.3% estimated by the Bureau of Reclamation.
(Table 3 gives the original 1959 estimate of utility growth in Juneau, the
revised 1961 estimate of utility growth in Juneau, and the actual utility
generation in Juneau from 1960 to 1982.)
The combination of competition from the older hydro plants and the
slower than anticipated growth of the Juneau power market resulted in a
surplus of power at Snettisham. If the price of electricity had to reflect
9-20
ii
A
B
Table 3 A-G
1959 U.S. Bureau of Reclamation Feasibility Report of Utility Load
Growth in Juneau.
Peak Annual Generation
(thousand IM) (million kwh)
1952
(actual)
4.1
16.70
1958
(actual)
5.1
24.40
1960
(projected)
6.6
29.20
1962
7.6
33.64
1965
10.9
47.90
1970
15.3
67.61
1975
20.4
89.72
(USBR, 1959)
1961 U.S. Bureau of Reclamation Reappraisal of Utility Load Growth
Peak Annual Generation
(thousand KW) (million kwh)
1958
(actual)
5.1
24.4
1960
(actual)
5.8
29.2
1962
(projected)
7.2
34.9
1965
9.4
45.5
1970
15.2
73.4
1975
24..3
116.9
1976
26.5
127.6
1977
28.9
139.1
1978
31.4
151.3
1979
34.1
164.3
1980
37.0
178.1
1981
40.0
192.7
1982
43.2
208.1
1983
46.6
224.7
1984
50.4
242.7
1985
54.4
262.1
1986
58.8
283.1
1987
63.5
305.7
(USBR, 1961)
'f
9_21
C
Table 3 cont.
Actual Generation of Power in the Juneau Area, 1960-1982
Peak Annual Generation
(thousand KW) (million kwh)
1960 (Calendar Year)
5.8
29.2
1961
7.8
32.3
1962
7.1
34.7
1963
9.0
37.2
1964
9.4
41.5
1965
10.0
43.5
1966
10.9
48.3
1967
10.5
49.3
1968
11.1
52.8
1969
11.8
56.0
1970 (Fiscal Year)
12.4
58.3
1971
13.8
63.8
1972
14.9
70.3
1973
15.5
75.8
1974
16.2
83.1
1975
17.8
94.6
1976
19.8
106.3
1977
20.4
112.2
1978
23.4
122.2
1979
23.1
133.5
1980
26.2
143.1
1981
32.2
160.7
1982
42.2a
(Alaska Power Administration, March 1982)
a January 1982
Note: As a rough rule of thumb, Snettisham's generation for any one
year would be 50 million kwh less than the annual generation figure
;i
9_22
I
the costs involved with the transmission line as well as amortize the
project's full capital costs, Snettisham's power rate would rise to a much
higher level. (To my knowledge, projections of those rates have never been
published.) Such potential price increases were forestalled in 1976 by
federal legislation which resembled in many ways the Eklutna legislation of
1968.
In the Water Resources Development Act of 1976 (P.L. 94.-587, Sec.
201) Congress provided that the cost of relocating the transmission line
($5.6 million), though not the cost of line repairs, would be
non -reimbursable. To alleviate the problem of surplus capacity the act
extended the payout schedule for 10 years and froze the price of power at
the rate of 15.6 mills per kwh until 1986. During this 10 year "load
development period" the project would not be required to cover its full
amortization costs, but would actually increase its overall capital indebt-
edness. In effect, the "balloon" aspects of the payout schedule were
simply extended another ten years. in 1986 the price of power will rise to
generate sufficient revenues to complete the 60 year payout schedule. The
Alaska Power Administration predicts that the 1986 price will be 25.8 mills
per kwh.. What chance of success does Snettisham have to develop a full
load for its power?
The current policy of the Alaska Power Administration for utilizing
Snettisham's surplus capacity is the development ❑f new markets for elec-
tricity in Juneau. The principal new market is residential electric
heating. According to APA estimates made in 1980, this could provide a
full demand for Snettisham power by 1983; without heating the full utility
demand would not develop until 1995 or 2000. And in the event that the
capital of Alaska moved from Juneau, Snettisham would never reach a full
demand without residential heating (APA, 1980).
Oddly enough both the "heat" and the "no heat" strategies present
problems. If the residential heating strategy is successful, Snettisham
could reach capacity rather quickly, Then additional electricity may have
to be generated by diesel fuel thus raising the price of power. Or new
hydro facilities could be built with the potential debt servicing costs we
have already noted in Sitka. If the heating strategy does not work,
Snettisham will continue to have surplus capacity for at least another
decade. The price of power will have to rise beyond the projected 1986
rate unless a new round of political intervention occurs. The most likely
form of intervention would be a state purchase of Snettisham from the
federal government. The capital costs of the project could then be
absorbed by the state and an arbitrary price for power could be set.
The dilemma of surplus capacity in many ways defies a simple solution.
It is particularly exaggerated in Juneau because Snettisham is not connect-
ed with another power market. Thus Snettisham's short run surplus cannot - -
be sold to another area and saved in the long run for Juneau's potential
growth. In an isolated load center surplus capacity in hydropower can
cause the price of electricity to be as unstable as that generated by a
fossil fuel. In such a situation, hydropower loses its advantage of stable
and predictable power rates.
Conclusions
The historical survey of twelve of Alaska's hydroelectric instal -
cations provides evidence that hydropower has been successful in the long
run in bringing reasonably priced electricity to Alaska. The operational
lives of some of the facilities have exceeded .the expectations of their
9-24
builders. Hydroelectric generation has presented .few operational problems.
No hydra installations in the survey have declined in their ability to
produce power over the long run. In fact, a number of the water power
sites have had their capacity increased. Even in the Anchorage area, where
water flow has varied substantially from year to year, the long run average
power production has been quite reliable --even exceeding the original
estimate for Eklutna.
Despite these long run advantages we have seen that in the short run
communities may have to pay a substantial price for hydropower. This has
come from debt servicing costs in Sitka, from earthquake damage in
Anchorage, from transmission line failures and surplus capacity in Juneau.
A community may also have to pay a higher price for hydropower in certain
periods when an alternative fuel, natural gas in Anchorage's case, can
provide a lower price, And it may be necessary to provide stand-by sources
of power --and absorb the cost of power rates --in places where the annual
waterflow of a project causes power -production to fluctuate substantially
between years.
The case histories also indicate that the Alaskan public has felt at
times that the costs of the short run problems should not be borne by power
consumers alone. Attempts to balance or smooth out the short run costs
through legislative intervention have occurred. in the case of Eklutna the -
legislation was probably justified on the ground of disaster relief. In
the long run the legislation has actually proved unnecessary for keeping
Eklutna's price competitive.
The 1976 legislation in regard to Snettisham, however, is more
problematic. It provided relief from the cost of operational failures (the
transmission line problems) which had nothing to do with a natural
EM
l
disaster. The transmission line risks were well known. Equally risky were
the planning assumptions for Juneau's electric power growth. There is an
inherent risk in any project built on long-range growth projections. The
Water Resources Development Act of 1976 essentially absorbed the costs of
those risks to maintain reasonably priced hydropower. Thus the 1976
legislation set the precedent that consumers may not have to absorb the
risks involved in constructing and operating hydro projects in their
communities. If we consider the construction of a hydropower project as
partially an economic enterprise and partially a political enterprise, the
1976 legislation clearly pushed Snettisham toward the political end of that
scale. If future government intervention, state or federal, at Snettisham
or other installations continues in this direction, the Alaskan public may
well come to view the development of hydropower as a game played by
politicians in which the public purse absorbs the economic risks. Such a
negative public view could do serious damage to the image of hydropower and
jeopardize the future development of one of the state's most valuable
natural resources.
Hydropower's short run cost problems definitely pose a dilemma for its
future development. The balancing act through political intervention is a
delicate one which must be handled with extreme care.
References
Alaska Power Administration, 1969, First Annual Report 1968.
Alaska Power Administration, 1980a, 1979 Annual Report.
Alaska Power Administration, 1980b, Juneau Area Power Market Analysis.
Dort, J.C., 1924, Report_ to the Federal Power Commission on the Water
Powers of Southeastern Alaska.
9-26
i
Official Statement $54,000,000 City and Borough of Sitka, Alaska, Municipal
Utilities Revenue Bonds, 1979.
Stone, David, 1980, Hard Rock Gold.
Session Laws of Alaska 1981, Chapter 90.
U.S. Bureau of Reclamation, 1948, Eklutna Project Alaska.
U.S. Bureau of Reclamation, 1954, A Report on the Blue Lake Project.
U.S. Bureau of Reclamation, 1959, Snettisham Project Crater -Long Lakes
Division Alaska.
U.S. Bureau of Reclamation, 1961, Reappraisal of the Crater -Long Lakes
Division, Snettisham Project, Alaska.
U.S. Bureau of Reclamation, 1966, Eklutna and the Alaska Earthquake.
U.S. Congress, House, 1968, Providing for the Rehabilitation of the Eklutna.
U.S. Federal Power Commission, 1960, Alaska Power Market Survey 1960.
U.S. Federal Power Commission, 1969, Alaska Power Survey 1969_
U.S. Federal Power Commission, 1979, Alaska Power Survey 1976, Vol. 1.
Whitehead, Sohn S., 1983,
anchorage, i1jueau, 1(etenl,,an, and SitKa. 7'nis paper is an adaptation and
condensation of research reported in this work. Readers interested in
greater detail and explanation of the issues noted in this paper should
consult the above work. In citing references in this paper, I have cited
(Whitehead, 1983) when the information was received through interviews or
unpublished sources. When the information or data originally appeared in
another published source, that source is cited.
9-27