Fish and wildlife recovery in the Pacific Northwest: Breaking the Deadlock
A draft analysis by the Northwest Power Planning Council staff
Appendix B
Introduction
The staff of the Northwest Power Planning Council was asked to look at
how the Bonneville Power Administration?s future power rates might
compare to potential market prices, considering uncertainties such as
changes in the operations of the Columbia River
hydropower dams. This analysis, while carried out by Council staff, is not
a Council-endorsed report. A more complete Council analysis is ongoing and
will be published this fall.
For this analysis, two approaches were taken. The first analysis
considered the subscription approach to Bonneville?s power sales.
Assuming that the federal agency?s firm power is fully subscribed, this
analysis asked what rate would subscribers need to pay to satisfy all of
Bonneville?s obligations. The second analysis looked at what losses or
benefits Bonneville might incur if it sold its energy products at market
rates.
Caveats
This is a "reconnaissance-level" analysis, describing
relative costs and values, not a detailed analysis that could be used as
the basis for key decisions. Some of the data used are considered rough
estimates.
Similarly, this analysis does not endorse any particular hydropower
system operating regime. The studies represented in the figures used a
base case of current hydropower operations (based on mandated regimes from
the National Marine Fisheries Service?s 1995 biological opinion). To
model a significant power and revenue loss, staff used a scenario that
included a year round drawdown to natural river elevation of the lower
Snake River dams and John Day Dam. The drawdown scenario includes the
estimated cost for dam modification as well as lost power revenues. The
costs do not include secondary impacts due to changes in navigation,
irrigation, flood control, or other non-power uses, which could be
substantial. Similarly, the analysis does not include cost allocations to
non-power river users or potential drawdown cost savings.
Case 1 (C1) is the same as the base case except that the four lower
Snake River dams and John Day Dam are operated at natural river elevations
year round. This effectively eliminates all generation from these
projects. All other constraints are left in place. The constraints to fill
federal projects during the fall and winter months remain, along with the
flow objectives described in the base case. Sturgeon flows are provided at
Libby Dam. Draft limits at the federal dams also remain the same. Spill at
the drawn down projects effectively becomes 100 percent.
Capital cost for drawdown to natural river for the four Lower Snake
River dams was estimated to be $533 million, based on the U.S. Army Corps
of Engineers Lower Snake Feasibility Study, conducted in December 1996.
The figure is in nominal dollars and assumes a completion date of 2005.
The capital cost for drawdown at John Day Dam was based on the Harza
Study, conducted in November 1994. That study estimated the cost for
drawdown to spillway crest, not to natural river elevation. Although it is
generally accepted that a drawdown to natural river will be less expensive
than a drawdown to spillway crest, the spillway crest estimate was used
for lack of better information. That cost is $988 million (also in nominal
dollars) and assumes a completion date of 2007. Other costs were based on
Bonneville estimates drafted for the System Configuration Team, and from
the Bonneville Financial Services Group. Hydropower operation and
maintenance costs came from the Corps? Fiscal Year 1997 budget
estimates.
A second drawdown scenario is described (C8) in which drawdowns were
placed on another schedule to test the impact of timing. In the original
drawdown scenario, all five dams are drawn down by 2007. Instead of
completing the drawdown of the four Lower Snake and John Day dams by 2007,
Case 8 has them scheduled as follows:
Ice Harbor 2006
Lower Monumental 2009
Little Goose 2011
Lower Granite 2013
John Day 2018
The capital costs in Case 8 were kept constant in real terms relative
to Case 1.
Both of these drawdown scenarios are merely "surrogates" for
any substantial drop in Bonneville?s revenues and energy production
capability. Additional scenarios were simulated, but only the base case
(CO) and the drawdown cases (C1 and C8) are included in this report.
The scenarios are compared to fixed long-term market prices of 16 and
20 mills per killowatt-hour. "Real" 1996 dollars are used
throughout, that is, costs have been adjusted to net out the effect of
inflation over time. No transmission costs or lost transmission revenues
are included in these costs.
Care should be taken in comparing the 16 and 20 mill market estimates
to current BPA rates. BPA?s current Priority Firm (PF) rate of 24.4
mills includes 3.2 mills for transmission. The PF rate will also be
unaffected by inflation for the 1996-2001 period. Adjusting the PF rate
for transmission and projected inflation produces a rate of 19.7 mills per
killowatt-hour, which is more comparable to the market prices used.
Similarly, adjusting BPA?s future target rate of 20 mills in 2000
produces a value of about 16 mills, which is comparable to the low
estimate of market price in this analysis.
The studies assume that the price long-term subscribers to Bonneville?s
electricity pay would be based on the cost of producing that electricity.
Bonneville?s costs were based on the agency?s 1996 rate case, as well
as on a special set of studies conducted for the Comprehensive Review to
estimate Bonneville?s outyear costs. Although significant cost-cutting
efforts are under way at Bonneville, no additional cost cutting is
included in this analysis. Actual costs will vary depending on several
factors, particularly hydropower system operations.
The calculation of subscriber?s rates assumed that any benefits from
non-firm power sales would be shared proportionally among all of
Bonneville?s customers.
To determine the potential stranded costs Bonneville would incur if its
power is sold at the market rate (as opposed to at the cost to generate
it), staff assumed that all Bonneville?s energy products and
services are sold at average rates of either 16 or 20 mills per
kilowatt-hour, depending on the set of analyses. The benefits or losses
described represent the difference between Bonneville?s costs and the
market rate. How those benefits or losses are distributed was not a part
of this study.
Observations
The greatest determinant of risk or benefit to Bonneville or its
subscribers is the market price of power. In a 20 mills per kilowatt-hour
market, Bonneville?s subscribers will do well over the long term,
whether the five dams are drawn down or not. In a 16 mills per
kilowatt-hour market, Bonneville?s customers don?t see benefits for
about a decade even under current operations. In a lower than 16 mills per
kilowatt-hour market, losses for Bonneville or its subscribers would be
greater and extend throughout the study period.
If Bonneville markets its power in an open market, its annual revenue
losses from drawdowns, even if it is selling into a 16-mills per
kilowatt-hour market, would be less than its annual debt payment to the
U.S. Treasury. These annual losses under the drawdown scenario would run
over $200 million on average for about 20 years and in some years could be
over $400 million. Consequently, Bonneville could potentially cover some
of its losses in some years by deferring its payment to the Treasury or by
utilizing a reserve account. Some of Bonneville?s losses could also be
offset through Bonneville?s cost cutting efforts.
BPA?s ability to fund major dam modifications is affected by both the
market price of power and its obligation to pay nuclear plant debt. If the
dam modification schedule is adjusted to take nuclear debt schedules into
account, as in Case 8, funding impacts are reduced.
We recommend that the Northwest Power Planning Council convene a
regional discussion and peer review of this preliminary analysis.
Current operations (CO) in a 16-mills per kilowatt-hour market
If the market rate of power stays around 16 mills per kilowatt-hour,
the cost to subscribers of Bonneville?s power under current operations
will be lower than the market cost by around 2009 (Figure 1). The
subscribers? rate under current operations would continue to decline
over the study period, reaching about 9 mills per kilowatt-hour between
2020 and 2030.
If instead of a subscription rate, Bonneville sells its energy services
at the 16-mills per kilowatt-hour average rate, the agency will lose about
$50 million a year (on average) for the first 10 years (Figure 2).
Bonneville will accrue on average about $500 million in benefits annually
for years 20 to 30 of the study period.
Figure 1 [figure not available]
Figure 2
Current operations (CO) in a 20-mills per kilowatt-hour market
If the long-term market rate of electricity is 20 mills per
kilowatt-hour, subscribers paying Bonneville?s costs start the study
period at about the market rate, but they experience below market rates
for the remainder of the study period, dropping down to about 8 mills per
kilowatt-hour for the last 15 years of the study period (Figure 3).
If Bonneville sells all its services at the 20-mills per kilowatt-hour
average market rate, the annual benefits to the federal power system begin
small, but climb to more than half a billion dollars a year for most of
the last 20 years of the study period (Figure 4).
Figure 3
Figure 4
Drawdown (C1) in a 16-mills per kilowatt-hour market
Under a drawdown scenario (C1) in the flat-rate 16-mills per
kilowatt-hour market, Bonneville?s subscribers will not see below-market
rates until about 2018 (Figure 5). After 2018, Bonneville?s subscribers?
rates would only drop to about 15 mills per kilowatt-hour, under this
scenario.
If Bonneville were selling all its services at the 16-mills per
kilowatt-hour market rate, for the first 20 years of the study period, the
agency would face losses that average over $200 million annually (Figure
6). Between 2020 and 2030, Bonneville would begin to earn about $80
million in annual benefits.
Figure 5
Figure 6
Drawdown (C1) in a 20-mills per kilowatt-hour market
Under this drawdown scenario, both Bonneville and its subscribers fare
better if the market goes to 20 mills per kilowatt-hour and stays there.
The period during which subscribers pay a rate that is higher than the
market rate is shorter than in the 16-mills per kilowatt-hour market
(Figure 7), and the rate differential is more narrow (rates peak at about
25 mills per kilowatt-hour, or 5 mills per kilowatt-hour above market).
If Bonneville were to sell its power at the average 20-mills per
kilowatt-hour rate, the annual federal loss would be less than $250
million in its worst year and it would only be down for six years out of
the 30-year study period (Figure 8). The annual federal benefit would
reach nearly $400 million in the second decade of the study period and
would stay between $200 million and $350 million throughout the last
decade of the period.
Figure 7
Figure 8
Delayed drawdown (C8) in a 16-mills per kilowatt-hour market
To test the impact on these figures of delaying drawdown, staff assumed
staggered drawdown dates beginning in 2006, with John Day Dam not being
drawn down until 2018 (In the original drawdown analysis, the projects
were completed between 2005 to 2007). Delaying drawdown essentially
flattens out the financial picture. Bonneville?s subscribers experience
smaller rate impacts and begin to see below-market rates sooner, during
the second rather than third decade out (Figure 9).
Delaying drawdown also narrows the benefit/loss gap. If Bonneville were
to sell at the market rate of 16 mills per kilowatt-hour, it would
experience early losses of about $100 million annually for the first
decade, but the second and third decades would see annual benefits
averaging around $100 million (Figure 10).
Figure 9
Figure 10
Delayed drawdown (C8) in a 20-mills per kilowatt-hour market
The delayed drawdown scenario has a similar impact if the market power
rate is 20 mills per kilowatt-hour, with less discrepancy between
subscribers? rates and the market and a greater long-term benefit to
Bonneville if it sells at the market rate (Figure 11).
If Bonneville were to sell its power in a 20-mills per kilowatt-hour
market, it would see a benefit almost immediately (Figure 12). The
long-term average annual benefit is about $300 million.
Figure 11
Figure 12
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