ON29124.pdf

Office of the Secretary
Service Date
September 26, 2002
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INVESTIGATION
OF THE CONTINUED REASONABLENESS OF
CURRENT SIZE LIMITATIONS FORPURPA
QF PUBLISHED RATE ELIGIBILITY (i.e., 1
MW) AND RESTRICTIONS ON CONTRACT
LENGTH (i.e., 5 YEARS).
ORDER NO. 29124
CASE NO. GNR-O2-
Sections 201 and 210 ofthe Public Utility Regulatory Policies Act of 1978 (PURPA)
and pertinent regulations of the Federal Energy Regulatory Commission (FERC) require
regulated electric utilities to purchase power from qualifying facilities (QFs). On February 5
2002, the Commission initiated this generic docket soliciting comments on the reasonableness of
existing project size limitations for QFs of 1 MW and the five-year restriction on QF contract
length. On May 21 , 2002, the Commission issued Order No. 29029 increasing the size of QFs
eligible for published rates from 1 MW to 5 MW and increasing the maximum required contract
length from 5 years to 20 years.
On May 21 , 2002, Idaho Power Company filed a Motion to Stay Entitlement to
Published Rates, and Avista Utilities filed a similar motion on June 11 2002. On June 10 2002
Petitions for Reconsideration were filed by 1. R. Simplot Company (Simplot) and Earth Power
Resources, Inc. (Earth Power). Petitions for Reconsideration were also filed by Idaho Power
and Avista on June 11 2002.
The Commission in Order No. 29069 issued July 2, 2002 (1) granted the Petition for
Reconsideration filed by Simplot and Earth Power and increased the size of QFs eligible for
published rates from 5 MW to 10 MW; (2) granted the Petitions for Reconsideration filed by
Idaho Power and A vista for the purpose of reviewing the reasonableness of the variables in the
existing avoided cost methodology and scheduled an August hearing on the reconsideration; and
(3) granted the Motions for Stay filed by Idaho Power and Avista staying the published rates
resulting from Order No. 29029, except as they apply to existing QF contracts, until the
Commission rendered this decision on reconsideration.
The Commission in this Order approves changes to the generic variables in the
avoided cost methodology, approves the resultant fueled and non-fueled avoided cost rates for
Idaho Power Company, Avista Corporation, and PacifiCorp and reaffirms the changes to contract
length for QFs smaller than 10 MW approved in Order No. 29069.
ORDER NO. 29124
ORDER NO. 29029
The Commission initiated this case to review by written comments whether the
current size limitations for QFs eligible for published rates and restrictions on contract length
were still reasonable. Comments were received from developers of QF facilities, from interested
persons and from the regulated electric utility companies (Idaho Power, A vista, and PacifiCorp)
required to purchase QF power. Prior to the issuance of Order No. 29029, QFs were eligible to
contract to sell energy at the published rates if the facility produced up to 1 MW of electricity,
and the purchasing utilities were required to provide a contract length of at least five years.
Regarding the standard contract length, the Commission noted in Order No. 29029
that its policy has changed during the years that PURP A has been effective in Idaho. For the
first seven years, through 1987, utilities were obligated to provide QFs with a 35-year contract.
In 1987, the Commission shortened the standard contract length to 20 years to reduce the risk
and uncertainty inherent in long range forecasting. The Commission in 1996 shortened the
standard contract length to five years for projects 1 MW and larger.
Regarding the production capacity of QFs eligible to receive published rates, FERC
rules and regulations require only that QFs with a design capacity of 100 kW or less be eligible.
See 18 C.R. g 292.304(c). PURPA does not prohibit larger projects from being eligible for
published rates and this Commission had set the design capacity limit at 1 MW.
After reviewing the comments filed by all the parties, the Commission in Order
No. 29029 found "that a convincing case has been made to increase the QF size threshold for
published rate eligibility to 5 MW and also to provide QFs with contracts of up to 20 years in
length." Order No. 29029 , p. 9. Despite a recommendation made by many parties in the case to
expand the proceedings to explore avoided costs methodology and other QF issues, the
Commission declined to expand the scope of the case beyond the issues identified, i.
restrictions on contract length and QF published rate eligibility.
PETITIONS FOR RECONSIDERATION
The sole issue raised by the Petitions for Reconsideration filed by Simp lot and Earth
Resources is the Commission s decision on the size of QFs eligible for published rates. Simplot
and Earth Power asked the Commission to grant reconsideration to increase the eligible QF size
from 5 MW to 10 MW. The companies point out that QFs in size between 5 and 10 MW provide
56% of the total megawatt capacity provided to Idaho Power by QFs. Simp lot contends the 5
ORDER NO. 29124
MW limitation will prevent many QFs, such as wind, geothermal and biomass, from capturing
economies of scale. Simp lot and Earth Power also contend the effect of a 10 MW versus a 5
MW QF on a utility s electrical system is inconsequential. The companies assert that if the
published avoided rates are no longer fair and accurate, the appropriate response is to adjust the
rates, rather than limit too narrowly the size ofQFs eligible for published rates.
The Petitions for Reconsideration of Idaho Power and A vista address the
reasonableness of the existing rates, especially in light of the Commission s decision to extend
the contract period to 20 years. Idaho Power contends the Commission s Order is "unreasonable
unlawful, erroneous, unduly discriminatory, not based on facts in the record, and is inconsistent
with applicable law because the rates established by the Order for payment to qualifying
cogenerators and small power producers (QFs) exceed the level permitted by federal law." The
Company contends federal law requires that purchase rates set by the Commission cannot result
in the utility paying QFs more than the utility s avoided costs. Idaho Power asserts that the
Commission, by focusing only on QF eligibility size and the mandatory contract length, failed to
recognize the real effect of the Commission s decision on those issues. According to Idaho
Power
, "
by changing the mandatory term of the contract from 5 years to 20 years, the
Commission increased the levelized published rates Idaho Power will have to offer to QFs that
are entitled to receive the published rates. The resulting levelized purchase prices substantially
exceed Idaho Power s current avoided costs.Idaho Power asked the Commission to stay the
effectiveness of Order No. 29029 to allow time to update the assumptions in the existing avoided
cost rate methodology.
A vista made an argument similar to Idaho Power in its Petition for
Reconsideration. Avista claims the current published cost rates are not a fair, reasonable and
accurate representation of the costs of the surrogate avoided resource (SAR) over a 20-year
period. The Company contends the published rates over a 20-year period are much higher than
A vista s current estimates of the costs associated with constructing a combined cycle combustion
turbine. A vista requested that the Commission grant rehearing for the purpose of receiving
evidence and current information on avoided costs before QFs are entitled to 20-year contracts.
RECONSIDERATION - TECHNICAL HEARING
The Commission initiated this case to review only the reasonableness of existing
limitations on QF contract length and the size limitation on QFs eligible to sell energy at
ORDER NO. 29124
published rates. As the petitions and motions of Idaho Power and Avista make clear, however
changing those factors can have a significant effect on the overall reasonableness of the QF
terms during the life of the contract. In this case, the Commission has approved increases in the
maximum QF project size, from 1 MW to 10 MW, and in the contract length, from five years to
20 years. If the variables that make up the avoided cost formula are inaccurate, the effect will be
magnified significantly because the resulting rates will be in place over a 20-year contract. As
Simplot and Earth Power suggest, the cure is not to shorten the contract length or to decrease the
maximum project size, but to review and adjust if necessary the variables in the avoided cost
formula.
The other major factor affecting published rates is the recent extreme volatility in gas
pnces. The published rates are adjusted each year based on the average gas price at Sumas
Washington. The past two years saw extremely high spikes in natural gas prices, resulting in
higher published rates. Gas prices have now returned to more normal levels. QF contracts
signed now calculated with abnormally high gas rates that are then escalated at the currently
accepted rate of 6% each year under the avoided cost rate formula could result in unreasonable
and unfair costs borne by the regulated utility, which ultimately will be paid by its ratepayers.
The Commission cannot expose ratepayers to avoided cost rates that rely too heavily on
uncharacteristically high gas prices in combination with a high escalation rate.
On August 12, 13 2002, the Commission on reconsideration held a technical hearing
in Boise, Idaho on the continued reasonableness of the variables in existing avoided cost rate
methodology. The following parties appeared by and through their counsel of record:
Idaho Power Company Barton L. Kline; Monica Moen
A vista Corporation
PacifiCorp
Independent Energy Producers of Idaho
& J.R. Simplot Company
R. Blair Strong
John M. Eriksson
Peter J. Richardson
Potlatch Corporation
& Wind Works, Inc.
Plummer Forest Products, Inc.
Commission Staff
Conley Ward
Dean J. Miller
Scott Woodbury
The Commission has reviewed and considered the transcripts of the proceedings in
this case including exhibits, our underlying related Orders and filed comments. Not all parties
ORDER NO. 29124
addressed all the variables. Some variables were deemed to be more critical than others, i.
current year fuel cost, fuel escalation rate and first deficit year. The following matrix depicts the
changes in variables proposed by the parties:
COMPARISON OF PROPOSED VARIABLES
.... .. . ~;~: . .........
~~~::~:S Staff Avista
Surplus Energy Abandon 22.12 to
Cost (mil/kWh):' 30.
Surplus Cost
Base Year:1994 Abandon
First Deficit
Year:
2010/
1998/1999 Abandon
SAR" Plant Life
(Years):
SAR" Plant Cost
($/kW):
Base Year of
SAR" Cost:
SAR" Capacity
Factor (%):
SAR" Fixed
O&M ($/kW):
SAR" Variable
O&M (mil/kWh):
Current Yr Fuel
Cost ($/MMBtu):
Base Year, O&M
Expenses:
Escalation Rate;
SAR" (%):
Escalation Rate;
Surplus (%):
Escalation Rate;
O&M (%):
Escalation Rate;
Fuel (%):
Tilting" Rate
(%):
Heat Rate
(Btu/kWh):
$667
1994
92%
$7.43
1.65
$5.
1994
60%
50%
21%
nom
60%
7350
Change
$679
2000
Change
$10.
$3.
2000
10%
2002
2007
Idaho .
. .. .
m Plum
Illerl Avista
...
Power . PacifiCoI' Potlatch ,Rebuttal
22.12 to
30.28.
2002
2005No
Change Change
$577 $686/
$729
2000
89.
$14.
NWPPC
2000
2.40%
2002
$9.45
$2.
2002
Abandon see above 5.90%
70%
4.4%
nom
10%
7100
2.40%
NWPPC 2.62%
nom
2.40%
7340 68991
6994
33.Abandon
2002
2007
Change
$669
2002
91.38
$9.
NWPPC
2002
2.26%
see above
53%
27%
NWPPC
38%
7127
;:~t~f~p . R::~al
33.Abandon
2002 Abandon 2002 Abandon
2008 2000/
NAINA 2008 AbandonAbandon
Change
$632
2002
Change
$7.
1.61
$3.$3.
Change
$632
2000
Change
$8.
$3.$3.
2002
0.47% thru
2007
5% after
50%
97%10%
2000
10%
80%
70%
10%
NWPPC 60%
50%
7074
10%
7100
A vista, on rebuttal, recommends averaging the recommendations made for capital cost, O&M
cost, heat rate, and escalation rates. Avista also accepts Staffs proposal to use a five-year rolling
ORDER NO. 29124
average to establish the starting year gas price, but proposes using a 50/50 blend of Sumas and
AECO gas prices. IEPI, on rebuttal, recommends that 3% be added to each utility s capital
carrying charge.
The positions advanced by the parties and our findings as to the continued
reasonableness of the variables can be summarized as follows:
First Deficit Year
The first deficit year determines the point at which the avoided cost rate converts
from a surplus energy cost to a rate that includes both the energy and capacity costs of the
surrogate avoided resource (SAR). The first deficit year for each utility is based on the utility
load/resource balance and forecast.
The Commission Staff proposed to abandon the "first deficit year" as an avoided cost
variable, together with the related surplus energy cost and surplus escalation rate. In support of
its position, Staff recited the following nine reasons:
1. Establishment of utilities' first deficit years requires regular filings by the
utilities followed by Commission Orders. None ofthe utilities have made
a filing to update its first deficit year since the first deficit years were last
established in 1996.
2. It is unclear whether determination of a first deficit year should be based
on a utility s energy needs or capacity needs.
3. When a utility becomes deficit depends on the conditions assumed for
planning. Water conditions and reserve margins used for planning are
not consistent for all of the utilities.
4. Load forecasts are one half of the surplus/deficit equation. Load
forecasts are prepared entirely by each utility with little or no oversight.
Utilities can easily manipulate their load forecasts to produce a desired
result.
5. Utilities increasingly rely on market purchases. Should long-term
contracts that do not begin for several years be counted as resources in
determining first deficit year?
6. The difference between "surplus" energy rates and "SAR-based" rates is
not as great as it used to be; therefore, there is less justification for two
different bases for parts of the avoided cost computations.
7. Utilities always plan to be surplus in the short-term, at least for as long as
it takes to acquire new resources. Having too large of surplus can be as
ORDER NO. 29124
problematic as being deficit. Avoided cost rates should not provide
incentives for a utility to increase its surplus period.
8. The addition of a PURPA project, particularly if it is less than 10 MW
does not have a large impact on a utility s load-resource balance. The
cumulative effect of many PURP A projects could have a significant
impact, but the capacity ofPURP A projects has historically been small.
9. If surplus energy rates are retained in the avoided cost analysis
determination of the prices to be used during a utility s surplus period
poses some difficulty because of recent extreme variations in market
pnces.
Staff and IEPI's proposal to eliminate the "first deficit year" as an avoided cost variable was met
with considerable opposition from Avista and PacifiCorp. No party, however, disputed any of
the reasons advanced by Staff. Establishing the first deficit year was likened by Staff to a mirage
in the desert, a goal which can never be reached. It was also suggested by Plummer that it poses
a "Catch 22" dilemma - i., a utility only has to purchase if it's deficit; however, a utility can
extend its surplus by constructing its own resources, so a utility is never deficit and never has to
purchase.
The testimony at hearing reflected the difficulty in determining a first deficit year.
The inherent problem lies in the fact that a utility s loads and resources are by their very nature
dynamic and continuously changing. Under the SAR methodology, the avoided cost rate is
computed as a surplus energy value for the immediate years in which the utility is surplus and a
SAR-based capacity and energy value from the first year of resource deficit forward. If the
surplus period is not recognized, the utility will immediately pay an avoided cost based on the
SAR. Such a result, the utilities argue, may run counter to the requirements of PURP A and
FERC which require consideration of a utility s "need" for resources and its marginal or
incremental costs. Reference 18 C.R. g 292.304 Rates for Purchases. Issues concerning the
deficit year computation, utilities suggest, can be adequately addressed with some additional
effort on the utility s part. It is Staffs contention that it would be an inordinate amount of effort
for what amounted to only about a 3 mill change in the avoided cost. Considering that two-
thirds or more of the avoided cost rate with a natural gas CCCT for SAR is entirely dependent on
fuel, Staff notes that there is a huge amount of uncertainty in the setting of any avoided cost rate.
The parties should be mindful, Staff notes, that avoided cost calculation is not an exact science;
ORDER NO. 29124
it is only an approximation. Testimony revealed considerable concern that the utility companies
could continue to game the system. One need only to look at A vista for an example of the
problems inherent in the first deficit year. Avista in its last IRP (2001) recognized the need to
update its avoided costs, promised to do so and then failed to do so. Avista is a utility officially
on record as implicitly claiming to have adequate resources through 2007-2010 and yet it is
nevertheless building and buying resources, in addition to covering deficits with purchased
power.A vista is not alone, however - all the utilities in this case are adding additional
generating capacity, gas combustion turbines that are smaller in size and more rapidly installed.
As a consequence, company IRPs almost never accurately reflect a utility s actual surplus/deficit
situation.
As the utilities candidly admit, their load/resource balances are not static numbers
but can change from day to day. Indeed, in the short course of these proceedings Avista in its
filings has claimed a number of different first deficit years. The record reflects the year that it
presently recommends, 2007, may be in error because the Company continues to factor in
Potlatch's self-generation as if it were a contracted resource and it is not. As recognized by the
parties, all utilities in this proceeding are reconsidering their energy purchase strategies and have
been recently active in upgrading existing resources and/or building or contracting for new
resources and capacity. As a new twist, supply resources are often also being developed through
the unregulated subsidiaries of utilities, thus avoiding or delaying regulatory scrutiny. Not once
during this recent period of resource acquisition and building, it was noted, did a utility suggest
that we should revisit avoided cost rates because perhaps the rates were too low, failed to reflect
the need for resources and were not sending an appropriate market signal to QFs. In failing to do
, it was suggested that utilities have denied their customers a least-cost opportunity to acquire a
greater diversity in supply resources.
The continued importance of a first deficit year in avoided cost calculations has to be
weighed against the improbability of settling on a surplus period in which anyone has
confidence. Utilities have had the opportunity to instill confidence in the first deficit year but in
failing to update for changes in load/resource balance have compromised the public confidence
in the reasonableness of its continued use.It is a factor in avoided cost calculation, the
Commission finds, that needs to be taken into account only to the extent practicable. Reference
18 C.R. g 292.304(e). The record supports a finding that continued use of the first deficit year
ORDER NO. 29124
is administratively burdensome and no longer practicable. We therefore accept Staff and IEPI's
proposals to abandon the first deficit year. In doing so, we acknowledge that we effectively
eliminate the need for related variables including surplus energy costs, surplus cost base year and
surplus escalation rate. Most utilities in the northwest are experiencing intermittent and seasonal
shortages. The utilities before us are just now beginning to admit that they have capacity needs
as well as energy needs. We find it appropriate to create an avoided cost that contains the full
value for both energy and capacity.
Initial Year Fuel Costs ($/MMBtu)
Fuel costs are a component in both the fueled rates and non-fueled rates available to
QFs.The rate for both fueled and non-fueled projects includes a levelized capital cost
component. Non-fueled rates also include a levelized fuel component - locking in an assumed
rate of inflation for the life of the contract. Fueled rates and the starting fuel price for non-fueled
rates are adjusted each July 1 and are based on the average monthly gas price at Sumas
Washington during the previous calendar year. Non-fueled rates escalate the starting fuel price
at a fixed rate over a 30-year plant life.
Idaho Power suggests that only two variables need be addressed in these proceedings
to get avoided costs to a level that is accurate or realistic, i., (1) current year fuel costs and (2)
fuel escalation rate. With a combined cycle combustion turbine as the SAR, fuel and associated
variable costs typically comprise more than two-thirds of the total power costs making up
avoided costs. This year s annual adjustment included prices from the 2000-2001 period of
extreme market volatility when gas prices in the northwest went to extremely high levels. A
change in the way the fuel cost component is computed for non-fueled rates is necessary to avoid
the effect of locking in a single year of extreme gas prices for the entire contract length.
Alternative methods proposed for providing a starting gas price or current year fuel
costs included historical averages, historical trend lines and future market projections, i., (1) a
five-year rolling average of historic prices, (2) a five-year average consisting of two years
historic and three years forecast, (3) the contract price of a one-year strip of power beginning
November 1 , (4) a seven-year historic average with high and low years discarded, (5) a three-
year average, two and half years historic and one-half year projected, and (6) a combination
three-year look back and five-year look forward. The only thing all parties agreed to was the
ORDER NO. 29124
inappropriateness of using the current year Sumas numbers which captured the 2000-2001 price
volatility.
Idaho Power is of the opinion that a price based on something that is actual or known
and measurable is preferable to something in a forecast. The problem with forward prices, it
contends, is that they are somewhat volatile and include a premium - anyone who agrees to sell
something at a fixed price has to charge more than one feels the price is going to be to earn a
profit, i., to cover the risk premium. The relevant initial gas price, Idaho Power contends, is
that which is most representative of current natural gas prices, not an average of several past
years. Unless the present period appears to be one of very high or very low prices, Idaho Power
contends that the principle ought to be to use the year s current data and price forecasts. Such a
process, it was noted, would require an annual review as to whether gas prices are "normal."
The danger perceived in using a five-year average was that any year might include an
outlier or market aberration. The alternative historic seven year average excluding high and low
was seen to address this problem but was also perceived to be fallible to the extent that high and
low prices were cyclical and actually part of the historic symmetry.
The Commission is persuaded that a reasonable method for calculating a starting gas
price is to move away from Sumas and adopt a fuel cost from the draft Fifth Northwest
Conservation and Electric Power Plan, April 25 , 2002 of the Northwest Power Planning Council.
Reference Idaho Power Exhibit 610. The Power Council produces five different levels or
forecasts of statistical probabilities of occurring (low, medium-low, medium, medium-high and
high). Specifically, we adopt the NWPCC medium 2002 forecast of $3.75/MMBtu calculated in
the manner proposed by IEPI witness Trippel, i., a simple arithmetic average of nominal prices
for the years 2000 through 2002 to arrive at an initial year (2002) medium forecast price.
(Source Reference IEPI Exhibit 603, Tr. p. 464; IPCo Exhibit 610, NWPPC Forecast App. D p.
l.) In doing so, we express confidence in the source and the use of a medium forecast which
we believe has the highest probability of being right. We acknowledge that the Power Council
does not issue its forecast on a regular basis. This will preclude a regular updating of the fuel
price. Although annual updates for starting gas prices have worked well in the past, we do not
consider an annual update to be an absolute necessity. Natural gas prices can be updated when a
new NWPPC forecast becomes available. A proceeding to review in the starting gas price can
ORDER NO. 29124
also be initiated at any time by the Commission on its own motion or by petition of any utility or
QF.
The current fuel price escalation rate is 6%. The escalation rate has a truly 10ng-
lasting impact. It was suggested that the best forecast of price escalation is that which has the
highest probability of being right, a medium forecast being preferable to a medium-high or high
forecast. Idaho Power witness Pesaeu, Tr. p. 637. Use of a single forecast from DOE/EIA as
recommended by Staff was criticized as having greater fallibility than a forecast such as the
Northwest Power Planning Council's Fuel Price Forecast which relies upon several independent
forecasts including DOE/EIA. Staffs objection to use of NWPPC is that the forecasts are not
issued on a regular basis and there is no certainty that they will be issued any differently in the
future. Staff also noted that the problem with an attempt to collect, compile and calculate an
average based on separate independent forecasts is that the forecasts are issued at different times
and do not cover the same periods. Idaho Power recommended use of the DRI-WEFA Group
long-term gas escalator. Reference Tr. p. 56. The Commission finds the existing escalation rate
of 6% to be unreasonably high for a fuel price escalator for non-fueled contracts. We find it
reasonable to adopt the NWPPC estimate of2.6% nominal rate as calculated using Mr. Trippel'
methodology and NWPPC numbers for medium forecast. The escalation rate we approve is a
significant downward correction but is high enough to reasonably reflect continued uncertainty
in gas prices and supply.
SAR Generic Variable Costs
Apart from fuel costs, there are three primary cost components to the surrogate
avoided resource, (1) capital costs, (2) fixed O&M, and (3) variable O&M. Capital costs are
based on the initial plant construction costs amortized over the 30-year life of the plant at the
utility s weighted cost of capital. O&M costs are based on an initial year estimate that is
escalated at a fixed rate over the life of the plant. As proposed by a number of parties, the values
of many of the variables under consideration can continue to be drawn from the plant cost data
provided by the Generating Resources Advisory Committee (GRAC) of the Northwest Power
Planning Council.
In 1996, the Commission in Order No. 25882 adopted a General Electric Frame 7FA
230 MW combined cycle combustion turbine (1 x 1 configuration) as the surrogate avoided
resource (SAR). Values for the equipment related variables were drawn from GRAC. A
ORDER NO. 29124
question raised in this case is whether the Commission as part of its review of the variable rates
should continue basing cost data on the GE Frame 7F A (1 x 1 configuration) or instead change
to the GE Frame 7FB (2 x 1 configuration), a larger 490 MW CCCT. The larger unit and
configuration was represented to reflect more current technologies and efficiencies. The Power
Planning Council provides current cost data for both turbines and configurations.
The generic variable costs we find appropriate and approve are the Staff proposed
NWPPC draft Fifth Power Plan - GRAC updated numbers for the GE Frame 7F A (1 x 1
configuration) with plant cost adjustments for approximate AFUDC that would be required if a
plant were to be constructed and heat rate adjusted for elevation. We find that the smaller
configuration is a size that better matches the needs of at least two of the three utilities in this
case, Idaho Power and Avista, as evidenced by base-load generating units recently constructed or
proposed by those utilities or their affiliates. (Coyote Springs for Avista; Garnet for Idaho
Power). The approved values are as follows:
Plant Cost
Fixed O&M
Variable O&M
Heat Rate
Base Year of SAR Cost
Base Year O&M Expenses
SAR Plant Life
SAR Capacity Factor
$679/kW
$10.70/kW
80 mil/kWh
7100 Btu
2000
2000
30 Years (no change)
92% (no change)
$624 + $55 adder for AFUDC
6980 w/adjustment for elevation
We find it reasonable to update and approve the following Staff-proposed escalation
rates derived from the NWPPC's Fifth Power Plan preliminary data which forecasts a 0.
percent real decrease in combined cycle plant costs adjusted upwards by a 2.70 percent inflation
rate from DOE/EIA Annual Energy Outlook 2002:
SAR Construction Costs
Tilting Rate
2.10%(0.6%) real decrease in combined cycle plant
costs + 2.70% inflation adjustment
10%
We also find reasonable an escalation rate for O&M set at 2., the same inflation rate from
DOE/EIA's Annual Energy Outlook.
ORDER NO. 29124
O&M 70%DOE/EIA Annual Energy Outlook 2002-
general inflation rate
* Annual Energy Outlook 2002, Table A20 Macroeconomic Indicators, GDP Chain
- Type Price Index, Annual Growth 2000-2020; Tr. p. 578.
Utility Specific Variables
IEPI on rebuttal recommends that 3% be added to each utility s capital carrying
charge (currently 12.424% for Idaho Power, 11.813% for Avista, and 12.600% for PacifiCorp) to
reflect difficulty in obtaining financing for power plants in the current market. Reference
Exhibit 608, Affidavit of Darrel Anderson, Vice President and Chief Financial Officer of
IdaCorp, Inc. submitted in Idaho Power Garnet Case, IPC-01-42. In cross-examination it was
clarified that the statement attributed to Mr. Anderson related specifically to the financing of
merchant power plants, not utility rate-based generation. Reference Tr. p. 506. The Commission
is persuaded that the distinction is relevant. We find no reason on the facts presented to modify
the utilities' capital carrying charges , nor do we in this case modify any of the other relevant
utility specific variables used in calculation of avoided cost rates.
Utility Avoided Costs
Having selected the generic variable values that we find to be reasonable, the 20-year
levelized non-fueled avoided cost rates of Idaho Power, Avista and PacifiCorp for purchases
from eligible QFs are: 47.43 milslkWh Idaho Power, 46.97 milslkWh Avista, and 47.
mils/kWh PacifiCorp, as more specifically detailed in Attachment B to this Order. We find the
purchase rates to be just and reasonable, to be in the public interest and to fairly represent the
avoided costs of each utility. Reference 18 C.R. g 292.101(6); 292.304. It is the
Commission s belief that in issuing this Order we are establishing a platform for avoided cost
pricing that is reasonable and will appropriately reflect the avoided cost of each utility into the
future.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over A vista Corporation dba
A vista Utilities, Idaho Power Company, and PacifiCorp dba Utah Power & Light Company,
electric utilities, pursuant to the authority and power granted it under Title 61 of the Idaho Code
and the Public Utility Regulatory Policies Act of 1978 (PURP A).
ORDER NO. 29124
The Commission has authority under PURP A and implementing regulations of the
Federal Energy Regulatory Commission (FERC) to set avoided costs, to order electric utilities to
enter into fixed term obligations for the purchase of energy from qualified facilities, and to
implement FERC rules.
ORDER
In consideration of the foregoing and as more particularly described, IT IS HEREBY
ORDERED and the Commission on reconsideration does hereby approve changes to generic
variables in avoided cost methodology (modification and/or elimination) as detailed in
Attachment A to this Order.
IT IS FURTHER ORDERED and the Commission with the changes approved above
does hereby approve the resultant fueled and non-fueled avoided cost rates for Idaho Power
Company, Avista Corporation, and PacifiCorp as detailed in Attachment B to this Order.
IT IS FURTHER ORDERED and the Commission reaffirms the changes to contract
length for QFs smaller than 10 MW approved pursuant to the Petitions for Reconsideration filed
by J.R. Simplot Company and Earth Power Resources, Inc. in Order No. 29069.
THIS IS A FINAL ORDER ON RECONSIDERATION. Any party aggrieved by
this Order or other final or interlocutory Orders previously issued in this Case No.GNR-02-
may appeal to the Supreme Court of Idaho pursuant to the Public Utilities Law and the Idaho
Appellate Rules. See Idaho Code g 61-627.
ORDER NO. 29124
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this ;J.t, 11--
day of September 2002.
ARSHA H. SMITH, COMMISSIONER
ATTEST:
(J
-Pi
Commission Secretary
bls/O:GNRE0201 sw2
ORDER NO. 29124
AVOIDED COST GENERIC VARIABLES
DATA CURRENT NEW
TYPE VARIABLES VARIABLES
SURPLUS ENERGY COST (mil/kWh):19.Abandon
SURPLUS COST BASE YEAR:1994 Abandon
FIRST DEFICIT YEAR:2010/1998/1999 Abandon
SAR" PLANT LIFE (YEARS):No Change
SAR" PLANT COST ($/kW):$667 $679
BASE YEAR OF "SAR" COST:1994 2000
SAR" CAPACITY FACTOR (%):92%No Change
SAR" FIXED O&M ($/kW):$7.43 $10.
SAR" VARIABLE O&M (mil/kWh):
CURRENT YR FUEL COST ($/MMBtu):$5.$3.
BASE YEAR, O&M EXPENSES:1994 2000
ESCALATION RATE; "SAR" (%):60%10%
ESCALATION RATE; SURPLUS (%):50%Abandon
ESCALATION RATE; O&M (%):21%70%
ESCALATION RATE; FUEL (%):0% nom
TILTING" RATE (%):60%10%
HEAT RATE (Btu/kWh):7350 7100
ATTACHMENT A
ORDER NO. 29124
CASE NO. GNR-O2-
IDAHO POWER COMPANY
AVOIDED COST RATES FOR NON-FUELED PROJECTS
SMALLER THAN TEN MEGAWATTS
September 26, 2002
mills/kWh
LEVELIZED NON-LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS)2002 2003 2004 2005 2006 2007 YEAR RATES
39.40.41.42.43.45.2002 39.
40.29 41.42.43.44.47 45.2003 40.
40.41.42.43.44.46.2004 41.
41.42.43.44.45.46.2005 42.
41.42.43.44.46.47.2006 43.
42.43.44.45.46.47.2007 45.
42.43.44.45.46.48.2008 46.
42.44.45.46.47.45 48.2009 47.
43.41 44.49 45.46.47.49.2010 48.
43.44.46.47.48.49.2011 49.
44.45.46.46 47.48.50.2012 50.
44.45.46.48.49.50.49 2013 52.
45.46.47.48.47 49.50.2014 53.
45.46.47.48.50.51.2015 54.
45.46.48.49.50.51.2016 56.
46.47.48.44 49.50.52.2017 57.
46.44 47.48.50.51.52.2018 59.
46.47.49.50.51.52.2019 60.
47.48.49.50.52.53.2020 62.
47.43 48.49.51.52.53.2021 63.
2022 65.
2023 66.
2024 68.
2025 70.
2026 72.
2027 73.
ATTACHMENT B
ORDER NO. 29124
CASE NO. GNR-O2-
Page 1 of 6
IDAHO POWER COMPANY
AVOIDED COST RATES FOR FUELED PROJECTS
SMALLER THAN TEN MEGAWATTS
September 26, 2002
mills/kWh
LEVELIZED NON-LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS)2002 2003 2004 2005 2006 2007 YEAR RATES
13.13.49 13.14.14.44 14.2002 13.
13.13.13.14.14.14.2003 13.49
13.48 13.14.14.43 14.15.2004 13.
13.13.14.14.14.15.2005 14.
13.14.14.14.15.15.41 2006 14.44
13.14.14.14.15.15.2007 14.77
14.14.14.15.15.15.2008 15.
14.14.48 14.15.15.15.2009 15.46
14.14.14.15.15.16.2010 15.
14.40 14.15.15.42 15.16.2011 16.
14.14.15.15.15.16.2012 16.
14.14.15.15.16.16.41 2013 16.
14.15.15.45 15.16.16.2014 17.
14.15.15.15.16.16.2015 17.
14.15.15.16.16.41 16.2016 18.
15.15.43 15.16.16.16.2017 18.
15.15.15.16.16.17.2018 18.
15.15.16.16.16.17.2019 19.42
15.15.16.16.48 16.17.2020 19.
15.48 15.16.16.16.17.2021 20.
2022 20.
2023 21.
2024 21.77
2025 22.28
2026 22.
2027 23.
EFFECTIVE DATE ADJUSTABLE COMPONENT
9/26/2002 26.
The total avoided cost rate in each year is the sum of the adjustable component and the fixed component from either of the tables
above.
Example 1. A 20-year levelized contract with a 2002 on-line date would receive the following rates:
Years Rate
15.48 + 26.
15.48 + Adjustable component in each year
Example 2. A 4-year non-Ievelized contract with a 2002 on-line date would receive the following rates:
Years Rate
13.18 + 26.
13.49 + Adjustable component in year 2003
13.80 + Adjustable component in year 2004
14.11 + Adjustable component in year 2005
ATTACHMENT B
ORDER NO. 29124
CASE NO. GNR-O2-
Page 2 of 6
AVISTA UTILITIES
AVOIDED COST RATES FOR NON-FUELED PROJECTS
SMALLER THAN TEN MEGAWATTS
September 26, 2002
mills/kWh
LEVELIZED NON-LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS)2002 2003 2004 2005 2006 2007 YEAR RATES
39.40.41.42.43.45 44.2002 39.
39.40.41.42.43.45.2003 40.
40.41.42.43.40 44.49 45.2004 41.
40.41.42.43.44.46.2005 42.
41.42.43.44.45.49 46.2006 43.45
41.42.43.44.45.47.2007 44.
42.43.44.45.46.47 47.2008 45.
42.43.44.45.46.48.2009 46.
42.44.45.46.47.40 48.2010 47.
43.44.43 45.46.47.49.2011 49.
43.44.45.47.48.49.2012 50.41
44.45.46.47.48.49.2013 51.
44.45.46.47.49.50.40 2014 52.
44.46.47.48.49.50.2015 54.
45.46.41 47.48.49.51.2016 55.
45.46.47.49.50.51.2017 57.
45.47.48.49.50.52.2018 58.
46.47.48 48.49.51.52.43 2019 59.
46.47.49.50.51.52.2020 61.48
46.48.49.50.51.53.2021 63.
2022 64.
2023 66.
2024 67.
2025 69.
2026 71.
2027 73.
ATTACHMENT 8
ORDER NO. 29124
CASE NO. GNR-O2-
Page 3 of 6
AVISTA UTILITIES
AVOIDED COST RATES FOR FUELED PROJECTS
SMALLER THAN TEN MEGAWATTS
September 26, 2002
mills/kWh
LEVELIZED NON-LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS)2002 2003 2004 2005 2006 2007 YEAR RATES
12.13.13.13.13.14.27 2002 12.
12.13.13.47 13.14.14.43 2003 13.
13.13.13.13.14.14.2004 13.
13.13.45 13.14.14.40 14.2005 13.
13.13.13.14.14.14.2006 13.
13.41 13.14.14.14.15.2007 14.
13.13.14.14.14.15.2008 14.
13.13.14.14.14.15.2009 14.
13.14.14.44 14.15.15.46 2010 15.
13.14.14.14.15.15.2011 15.
14.14.14.15.15.15.2012 15.
14.14.48 14.15.15.15.2013 16.
14.14.14.15.15.15.2014 16.
14.14.15.15.15.16.2015 17.
14.48 14.15.15.15.16.2016 17.
14.14.15.15.15.16.2017 17.
14.15.15.15.16.16.47 2018 18.
14.79 15.15.48 15.16.16.2019 18.77
14.15.15.15.16.16.2020 19.
14.15.15.16.16.41 16.2021 19.
2022 20.
2023 20.
2024 21.
2025 21.
2026 22.
2027 22.
EFFECTIVE DATE ADJUSTABLE COMPONENT
9/26/2002 26.
The total avoided cost rate in each year is the sum of the adjustable component and the fixed component from either of the tables
above.
Example 1. A 20-year levelized contract with a 2002 on-line date would receive the following rates:
Years Rate
14.98 + 26.
14.98 + Adjustable component in each year
Example 2. A 4-year non-Ievelized contract with a 2002 on-line date would receive the following rates:
Years Rate
12.73 + 26.
13.02 + Adjustable component in year 2003
13.32 + Adjustable component in year 2004
13.63 + Adjustable component in year 2005
ATTACHMENT B
ORDER NO. 29124
CASE NO. GNR-O2-
Page 4 of 6
PACIFICORP
AVOIDED COST RATES FOR NON-FUELED PROJECTS
SMALLER THAN TEN MEGAWATTS
September 26, 2002
mills/kWh
LEVELIZED NON-LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS)2002 2003 2004 2005 2006 2007 YEAR RATES
40.41.42.43.44.45.2002 40.
40.41.42.43.44.45.2003 41.
40.42.43.44.45.46.2004 42.
41.44 42.48 43.44.45.46.2005 43.
41.42.44.45.46.47.2006 44.
42.43.44.47 45.46.47.2007 45.
42.43.44.46.47.48.2008 46.43
43.44.45.46.47.48.2009 47.
43.44.45.46.48.49.2010 48.
43.45.46.47.48.49.2011 50.
44.45.48 46.47.48.50.2012 51.
44.45.47.48.49.50.2013 52.
45.46.47.48.49.51.2014 53.
45.46 46.47.48.50.51.44 2015 55.
45.46.48.49.50.51.2016 56.
46.47.29 48.47 49.50.52.2017 58.
46.46 47.48.50.51.52.2018 59.45
46.47.49.50.51.52.2019 60.
47.48.49.45 50.51.53.2020 62.47
47.48.49.51.52.53.2021 64.
2022 65.
2023 67.
2024 68.
2025 70.
2026 72.47
2027 74.
ATTAcHMENT B
ORDER NO. 29124
CASE NO.GNR-O2-
PaQe 5 of 6
PACIFICORP
AVOIDED COST RATES FOR FUELED PROJECTS
SMALLER THAN TEN MEGAWATTS
September 26, 2002
mills/kWh
LEVELIZED NON-LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVELIZED
(YEARS)2002 2003 2004 2005 2006 2007 YEAR RATES
13.42 13.14.14.14.15.2002 13.41
13.13.14.14.14.15.2003 13.
13.14.14.14.15.15.2004 14.
13.14.14.49 14.15.15.2005 14.
13.14.14.14.15.15.2006 14.
14.14.44 14.15.15.46 15.2007 15.
14.14.14.15.15.15.2008 15.
14.14.15.15.15.16.2009 15.
14.14.15.15.15.16.2010 16.
14.14.15.15.16.16.2011 16.46
14.15.15.43 15.16.16.2012 16.
14.15.15.15.16.16.2013 17.
14.15.15.16.16.16.77 2014 17.
15.15.42 15.16.16.16.2015 18.
15.15.15.16.16.17.2016 18.44
15.15.15.16.16.17.2017 18.
15.15.16.16.46 16.17.2018 19.
15.47 15.16.16.16.17.2019 19.
15.15.16.16.17.17.43 2020 20.
15.16.16.16.17.17.2021 20.
2022 21.
2023 21.
2024 22.
2025 22.
2026 23.
2027 23.
EFFECTIVE DATE ADJUSTABLE COMPONENT
9/26/2002 26.
The total avoided cost rate in each year is the sum of the adjustable component and the fixed component from either of the tables
above.
Example 1. A 20-year levelized contract with a 2002 on-line date would receive the following rates:
Years Rate
15.65 + 26.
15.65 + Adjustable component in each year
Example 2. A 4-year non-Ievelized contract with a 2002 on-line date would receive the following rates:
Years Rate
13.41 + 26.
13.72 + Adjustable component in year 2003
14.03 + Adjustable component in year 2004
14.36 + Adjustable component in year 2005
ATTACHMENT B
ORDER NO. 29124
CASE NO. GNR-O2-
Page 6 of 6