electric.pdf

2003
ANNUAL REPORTPage 15 IDAHO PUBLIC UTILITIES COMMISSION
Electrical Power in Idaho
Idaho residents consistently enjoy some of the least expensive electric service in
the nation, according to surveys conducted by the National Association of
Regulatory Utility Commissioners (NARUC), the Edison Electric Institute and
the Energy Information Administration of the U.S. Department of Energy.
Idaho Power Company
2002 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
326,788 Residential Customers/$0.0706
63,167 Commercial Customers/$0.0549
107 Industrial Customers/$0.0567
Avista Utilities
2002 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
91,076 Residential Customers/$0.0613
14,788 Commercial Customers/$0.0672
526 Industrial Customers/$0.0444
2002 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
PacifiCorp/Utah Power
45,606 Residential Customers/$0.0389
6,578 Commercial Customer/$0.0581
5,411 Industrial Customer/$0.0165
Idaho’s
electricity rates
are among the
lowest in
the nation
IDAHO PUBLIC UTILITIES COMMISSION Page 162003
ANNUAL REPORT
Power Rates in Idaho
As of Oct. 1, 2003
These rates do not include customer charges or high-voltage discounts. Not all avail-
able rate schedules are shown for each utility. Rates are in cents per kWh unless
otherwise indicated.
IDAHO POWER COMPANY
Residential -- $0.05486
(Rate is $0.05534, but with BPA credit of $.000475, reduced rate is
$0.05486.)
Commercial
Small commercial — $0.06813
Large commercial — $0.03219, plus $2.73 per kW demand charge
Industrial
Large industry — $0.03379; plus $2.73 per kW demand charge
Irrigation — $0.04158 in season (not including BPA credit); plus $3.58 per
kW demand charge in season.
AVISTA UTILITIES
Residential
First 600 kWh — $0.05255
All use over 600 kWh — $0.06003
Commercial
Small commercial — $0.0797 plus $3.50 per kW demand charge for demand
more than 20 kW
Large commercial — $0.05022 plus $225 for first 50kW of demand or less
and $2.75 per kW for demand over 50 kW
Industrial
Large industry — $0.03490 per kWh plus $7,500 for first 3,000 kVA (kilo-
volt-amps) of demand or less and $2.25 per kVA for demand over 3,000 kVA.
2003
ANNUAL REPORTPage 17 IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP-UTAH POWER
Residential
From May to October — $0.0734
From November to April — $0.0501
Time of Day residential rates
On-peak use from May to October — $0.0801
Off-peak use from May to October — $0.0113
On-peak use from November to April — $0.0648
Off-peak use from November to April — $0.0082
Commercial
Small commercial, May to October — $0.0847
Small commercial, November to April — $0.75146
Large commercial — $0.0288 plus $10.68 per kW demand charge from May
to October and a $8.79 kW demand charge from November to April.
Industrial
Small industry — $0.0325 per kWh plus $8.79 per kW demand charge from
May to October and a $6.59 per kW demand charge from November to April.
Irrigation (In-season)
First 25,000 kWh — $0.022615, plus $4.05 per kW demand
Next 225,000 kWh — $0.006319, plus $4.05 per kW demand
All additional kWh -- $-0.006705, plus $4.05 per kW demand
IDAHO PUBLIC UTILITIES COMMISSION Page 182003
ANNUAL REPORT
Electric Utility Case Reviews
Idaho Power Company
Idaho Power Co. is Idaho’s largest electric utility. The utility typically
generates 55 percent of its electricity at hydroelectric dams on the Snake River.
Due to a third year of poor hydro conditions in 2002, only 45 percent of the
utility’s electric generation came from hydro with increased reliance on the
company’s coal- and gas-fired plants (at Jim Bridger, Wyoming; Boardman,
Oregon; Valmy, Nevada, and Mountain Home, Idaho) and power purchases on
the wholesale market. Less than 5 percent of Idaho Power’s generation comes
from co-generators and small independent power producers.
In 2002, the average Idaho Power household used 12,846 kWh, down
8.5 percent from the 13,944 kWh in 2001. This figure averages residential
customers with electric space and water heating with those who do not use
electricity for these uses.
October 28, 2003
IDAHO POWER SEEKING RATE INCREASE
Case No. IPC-E-03-13, Order No. 29369
BOISE – Idaho Power Co. filed an application with the commission to
increase rates by an average 17.7 percent for all customer classes.
The company sought a permanent rate increase, which included $20
million for interim rate relief. Combined, the increases would raise $86 million in
annual revenues to allow Idaho Power to meet expenses for a growing cus-
tomer base and recover $156 million invested in new generating facilities, $198
million in new transmission facilities and $366 million in new distribution facilities
since 1993, the last year Idaho Power had a rate case.
The company requested an overall rate of return of 8.334 percent on a
rate base of $1.55 billion and an 11.2 percent return on common equity. The
company currently receives a 9.199 percent rate of return on rate base of
$1.22 billion and an 11 percent return on common equity.
If granted, rates would increase an average of 17.7 percent, but the
increase would vary by customer class because the costs of serving each class
vary. For residential customers, the increase would be 19.9 percent; for small
commercial, 21 percent; for large commercial, 15 percent; for industrial, 13.9
percent and for irrigation, 25 percent.
Included within the average 17.7 percent increase is a proposed
increase in the customer service charge for residential and small commercial
customers from $2.51 a month to $10 per month. Customer service charges
Number of Customers
390,062
Idaho Power Company
1220 W. Idaho Street
P O Box 70
Boise, ID 83707
800-488-6161
208-388-2323
(Treasure Valley)
2003
ANNUAL REPORTPage 19 IDAHO PUBLIC UTILITIES COMMISSION
are designed to recover a portion of costs associated with providing electrical
service such as meters, a portion of distribution facilities and billing. For irriga-
tion customers the in-season monthly charge would increase from $10.07 to
$25 and for large commercial customers from $5.54 to $21.
The company also proposed to implement seasonal rates for residential
and small-commercial. Summer base rates, charged between June and August,
would be 25 percent higher than current base rates. The base rate proposed for
the rest of the year is slightly lower than the current base rate.
Interim rate increase denied
On Nov. 13, the commission denied Idaho Power’s request for the 4.2
percent interim rate increase. The commission heard oral arguments from the
utility as well as attorneys representing interested parties in the case and ruled
from the bench.
Idaho Power said the interim increase was needed to meet capital and
relicensing costs, to lessen the need to borrow to meet growth-related demands,
and to send a message to the investment community. “Granting interim rate relief
sends a positive signal to the investment community,” said Barton Kline, attorney
for Idaho Power. “A positive signal can reduce costs to customers because it
reduces the cost of borrowing.”
The interim rate increase would have raised $20 million to: pay the costs
of the construction and operation of the Danskin Power Plant in Mountain
Home ($7.7 million); pay the costs associated with the re-licensing of several
hydro facilities ($1.57 million); recover a change in depreciation expenses ($3.8
million): and compensate for the increase in Idaho’s share of net power supply
costs due to reallocation between the Oregon and Idaho wholesale and retail
jurisdictions ($7 million).
The commission said legitimate concerns about Idaho Power’s financial
position are outweighed by other matters in the case, such as the potential of an
inequitable burden placed on some customer classes if a uniform 4.2 percent
increase were enacted immediately. Idaho Power had proposed a Nov. 15
implementation date, which the commission suspended to allow time for more
investigation and today’s oral arguments.
The investment community should not infer that the decision is an
indicator of what the commission may decide regarding the request for a perma-
nent rate increase, the commission said. “We have not prejudged this case and
neither should they,” the commissioners said. “This case will be processed
expeditiously and fairly.”
In a related matter, commission staff and intervenors in the case con-
ducted a pre-hearing conference to establish the schedule for consideration of
the permanent rate increase request. A number of deadlines for pre-filed testi-
mony, discovery requests and exhibits were established. A date of March 29,
IDAHO PUBLIC UTILITIES COMMISSION Page 202003
ANNUAL REPORT
2004, was scheduled as the beginning of a technical hearing that could last up
to two weeks. Commission staff and the commissioners will also conduct public
workshops and public hearings throughout Idaho Power’s service territory
before a final decision is made.
Intervenors in the case include the Industrial Customers of Idaho
Power, the Idaho Irrigation and Pumpers Association, the Department of
Energy, Micron, the Community Action Association & AARP, the Northwest
Energy Coalition and United Water of Idaho.
May 13, 2003
IDAHO POWER PCA RESULTS IN LOWER BILLS
Case No. IPC-E-03-5, Order No. 29243
BOISE – The Idaho Public Utilities Commission approved a power
cost adjustment (PCA) for Idaho Power that will result in an average 18.9
percent reduction for the utility’s residential customers effective May 15.
The action by the commission reduces Idaho Power’s revenue by $114 million,
but commission staff is seeking to reduce yet another $5.1 million. Idaho Power
disagrees with commission staff findings and has requested a hearing to address
the parties’ differences.
Rather than wait until those issues are resolved, commissioners opted to
implement the interim rate immediately.
“It’s extremely important that we get rate relief to customers as soon as
possible,” said Commission President Paul Kjellander.
The decrease is 18.9 percent for residential customers, 11 percent for
small commercial customers, 24.7 percent for large commercial; 20.2 percent
for industrial and 0.5 percent for irrigation customers. The rate for irrigators and
small general service customers drops only slightly because power supply costs
incurred by Idaho Power for those two classes are being recovered over a
two-year period to soften the impact of large increases last year to those
customer classes.
Most of the $5.1 million sought in further reductions by commission
staff comes from a view by staff and the Idaho Irrigation and Pumpers Associa-
tion that the company use more updated sales data in calculating the PCA rate.
The company agrees that updated data may be necessary but that changes in
the already approved PCA methodology should apply to future PCAs and not
this year’s case.
Here is the impact the rate adjustment will have on each customer class
(all cents are on a per kWh basis):
Residential: Old surcharge: 1.94 cents, new surcharge: 0.604 cents.
2003
ANNUAL REPORTPage 21 IDAHO PUBLIC UTILITIES COMMISSION
Old rate: 7.06 cents, new rate 5.73 cents.
Small commercial: Old surcharge: 1.72 cents, new surcharge: 0.85
cents. Old rate: 7.99 cents, new rate 7.115 cents.
Large commercial: Old surcharge: 1.94 cents, new surcharge: 0.604
cents. Old rate: 5.4 cents, new rate 4.06 cents.
Industrial: Old surcharge: 1.72 cents, new surcharge: 0.82 cents. Old
rate: 4.46 cents, new rate 3.55 cents.
Irrigation: Old surcharge: 1.34 cents, new surcharge: 1.3 cents. Old
rate: 5.17 cents, new rate 5.14 cents.
FACTS ABOUT THE PCA:
„The power cost adjustment is an annual mechanism that adjusts
rates either upward or downward based on changes in variable power supply
costs. The adjustment is a surcharge added to the base rate during low water
years or a credit subtracted from the base rate during high water years.
„ Since the PCA for Idaho Power began in 1993, customers have
received credits in three years (1996, 1997 and 1999) and surcharges in the
other 12 years. The wholesale market crisis of 2000-01 and four straight low-
water years have resulted in surcharges every year since 2000.
„This year’s $81 million PCA is significantly lower than the last two
years, $217 million in 2002 and $256 million in 2003. But it still results in a
substantial surcharge added on to customers’ base rate. However, because the
surcharge that begins May 15 is smaller than the 2002 surcharge that expires
May 15, customers will see a reduction in their bills. For example, the base rate
for residential customers is 5.12 cents per kWh. The one-year surcharge of
.6043 cents that begins Thursday makes the total residential rate 5.73 cents per
kWh. The surcharge of 1.93 cents that expires Wednesday made the total
residential rate 7.06 cents.
„This year’s total power cost adjustment of $81 million is made up of
three components: above-normal supply costs of $38.7 million over the last
PCA year; a projection of $26.6 million in above-normal power supply costs
during this PCA year; and $16 million still owed the company on commission
approved deferrals for small-commercial, irrigation and industrial customers.
Most of the $38.7 million in costs last year, about $28.2 million, is load reduc-
tion and settlement costs with Astaris, a Pocatello phosphorous plant that closed
last year. Those are one-time costs that will not recur after this year’s PCA.
„At the end of each PCA year, which runs from April to April, there
is a true-up on the difference between the prior year’s actual cost and the
forecast made by the company. The PCA account is audited by commission
staff to ensure that the surcharge collected from customers goes only to pay for
power supply expenses. Revenues from the surcharge cannot be spent on
capital expenses, salaries or anything else not attributable to power supply cost.
IDAHO PUBLIC UTILITIES COMMISSION Page 222003
ANNUAL REPORT
„In normal water years, Idaho Power’s system of hydroelectric
dams generates about 55 percent of the power the company needs to serve its
customers. The National Weather Service projects that inflow into the
Brownlee Reservoir, Idaho Power’s primary water storage facility, will be only
3.37 million acre feet, better than last year’s 3.25 maf, but only about half the
average inflow of 6.3 maf during normal water years.
May 22, 2003
REIMBURSEMENTS RESULTING FROM FERC ORDER
ALREADY PAID TO IDAHO POWER CUSTOMERS
Customers of Idaho Power Company have already received most, if
not all, of the financial benefits resulting from FERC’s May 16 order dealing
with trades between Idaho Power and IDACORP Energy (IE).
Late last week, the Federal Energy Regulatory Commission ordered
IDACORP Energy (IE), to transfer $5.8 million in revenues it earned from
wholesale power trades to Idaho Power, ensuring that Idaho Power ratepayers,
and not IE shareholders, get the benefits. Idaho Power included nearly $4
million of that as a credit to customers in its 2002 power cost adjustment. The
remaining $1.8 million was included in the 2003 power cost adjustment interim
rate established last week that results in an average 18.2 percent rate decrease
for customers.
Idaho Power has been working with FERC and the Idaho Public
Utilities Commission to resolve the matter that resulted from trades executed by
IE from January 2000 through April of 2002.
IE, as a wholesale buyer and seller of energy, is regulated by FERC,
not the commission. “Wholesale trading is FERC’s issue to police, however, the
Idaho commission felt compelled to act in advance of a final FERC order,” said
Paul Kjellander, commission president.
“While the commission cannot regulate trading practices of wholesale
energy traders, it is interested in determining if more revenues should be
awarded Idaho Power customers for IE’s use of Idaho Power transmission
lines and other sources which, over the years, have been built from rates paid
by Idaho Power customers,” Kjellander said.
The commission opened a case of its own in 2001 to address, among
other issues, additional compensation to Idaho Power and its customers for use
of its transmission system and other resources by IE.
Now that the FERC matter has been resolved, commission staff will
attempt to negotiate and enter into a written stipulation to resolve all remaining
issues, including whether even more IE revenues are due Idaho Power custom-
ers.
In its May 16 ruling, FERC said Idaho Power gave preferential treat-
2003
ANNUAL REPORTPage 23 IDAHO PUBLIC UTILITIES COMMISSION
ment to its trading subsidiary, IE, in its assignment of electric grid capacity.
IDACORP acknowledged that it failed to get IE registered as a trader
before engaging in power deals that should have been pre-approved by FERC.
“I think this is a very serious violation of trust by Idaho Power Com-
pany, and I’m glad to see FERC’s order to resolve these violations,” said
Commissioner Dennis Hansen. “I also support this commission’s continued
efforts to see if maybe even more revenues are due Idaho Power customers.”
Commissioner Marsha Smith also expressed support for the FERC
ruling, but noted that FERC’s ability to order sufficient financial remedy is limited
and outdated.
“The civil penalties FERC can impose, although not applicable in this
matter, seem inadequate to deter unlawful activity,” she said.
The maximum penalties FERC can assess companies has not been
updated since the Federal Power Act was enacted in 1920. “Enhanced enforce-
ment penalties for FERC should be adopted in the energy legislation now
pending in Congress,” Smith said.
In August 2002, IDACORP announced it was winding down its whole-
sale trading activities. The regulated side of the company, Idaho Power, will act
as the trader for the company, which is the way the company operated before
the creation of IDACORP Energy.
March 17, 2003
AIR CONDITIONING PILOT PROGRAM APPROVED
Case No. IPC-E-02-13, Order No. 29207
Idaho Power Company has been given the go-ahead to implement a
two-year pilot program that allows the company to temporarily control air
conditioning in the homes of up to 500 volunteer residential customers during the
summer months when power consumption is at its peak.
The program allows the company to install programmable, remote
control thermostats for air conditioning units in the homes of Boise and Meridian
residents who volunteer to participate. The volunteers will permit the company
to turn air conditioning on and off for 15-minute intervals over a four-hour period
between 1 and 9 p.m. up to 10 weekdays per month in June, July and August.
Volunteers – 200 in the first year and an additional 300 in the second year – will
receive a credit of $10 per month from Idaho Power for participating in the
program. The company has originally proposed a credit of $5 per month, but
commissioners said a $10 credit would result in more customer response while
only marginally increasing the costs of the program.
Cycling will be accomplished remotely by turning air conditioners off
and on for specified lengths of time, or until a specified temperature is reached,
or by changing the thermostat’s temperature at a set point. Volunteers will be
able to opt out of the program for one day each month by notifying the company
one day in advance.
IDAHO PUBLIC UTILITIES COMMISSION Page 242003
ANNUAL REPORT
The company would thermostatically reduce air conditioning use when
systemwide reductions in power use are needed to prevent outages or lessen
the need to buy additional power when the price is abnormally high due to
supply shortages.
Idaho Power projects it will be short on power in future years during
times of peak use. A program like this could decrease the demand for electric-
ity, thus preventing the company from having to build new power lines or
generating facilities to meet peak demand. The program could decrease Idaho
Power’s overall energy costs, which, in turn, results in savings for all customers.
The program will also allow the company to measure the effectiveness of air-
conditioning thermostat control in reducing peak load.
The cost of the program, estimated to be about $410,000 for each of
the two years will be paid from the 30-cents per month conservation surcharge
currently included on customer bills.
The company proposes that it be allowed to solicit customers for
participation based on their energy use, location, size of home or other factors
aimed at creating a diverse population for the pilot program. Customers may
terminate participation by returning the thermostat in working condition or be
charged $100 for the thermostat. If they remain in the program for one cooling
season and choose not to participate the second year they can keep the ther-
mostat at no charge.
July 9, 2003
IDAHO POWER CONTRACT WITH PPL MONTANA APPROVED
Case No. IPC-E-03-8, Order No. 29286
The Idaho Public Utilities Commission has approved a purchase
agreement allowing Idaho Power Co. to purchase power from PPL Montana
during the peak consumption months of June, July and August. The energy from
PPL Montana will replace what would have been provided by the proposed
Garnet project near Middleton. The Garnet project was never built due to lack
of financing.
Idaho Power will buy 83 megawatts per hour in June and July and 26
MWh during August. (One megawatt, or one million watts, is enough electricity
to provide power for 750 homes.) The company proposes to pay $44.50 per
MWh (4.45 cents per kWh), which, the commission said, is a competitive rate
compared to other options for providing the needed power.
Commission staff recommended the company seriously investigate a
variety of conservation programs to potentially reduce summertime peak loads.
“Traditional demand-side management, voluntary curtailment programs,
interruptible rates and time-of-use rates are just some of the possible mecha-
nisms that might be employed to reduce or eliminate the company’s need to
acquire additional supply-side resources in the future,” commission staff said.
2003
ANNUAL REPORTPage 25 IDAHO PUBLIC UTILITIES COMMISSION
Those conservation steps could also reduce the company’s need to operate its
Mountain Home plant, which has operation costs that far exceed the cost of the
PPL contract, staff said.
In June 2000, Idaho Power’s Integrated Resource Plan indicated that,
beginning in 2004, it would not have enough capacity to serve customer load.
The company proposed a 250 MW natural gas plant. Garnet Energy
LLC, a division of IDACORP, was the successful bidder on a proposal to build
the project near Middleton. However, in July 2002, Garnet notified Idaho
Power that it had not been able to secure the financing to build the project. The
commission, in subsequent orders, asked the company to file a report outlining
its strategy to acquire power that would otherwise been provided through the
Garnet project.
Contracting with PPL Montana is advantageous, Idaho Power officials
said, because existing limits on the west side of Idaho Power’s system made
power purchases on the east side of the company’s system more preferable.
After the Montana Legislature de-regulated its retail electric industry, the
state’s major utility, Montana Power, sold its generating plants to Pennsylvania
Power & Light. PPL Montana operates 11 hydroelectric plants in Montana with
a generating capacity of 474 MW as well as 500 MW of coal-fired generating
capacity.
October 29, 2003
COMMISSION ORDERS LIMITED AMR IMPLEMENTATION
Case No. IPC-E-02-12, Order No. 29362
Idaho Power Company must present a plan to implement automated
meter reading on a pilot basis in selected service areas within 60 days, accord-
ing to an order from the Idaho Public Utilities Commission.
After one year, the company will report back to the commission on the
cost-effectiveness and results of the program. The commission will then decide
on whether to expand the meter technology to the rest of Idaho Power’s service
territory.
Automated meter readers (AMR) can be read from a remote location
without having to enter a customer’s property, significantly reducing operational
costs and the potential for error. Some AMR systems have the ability to inform
customers of current electric prices, potentially allowing them to manage their
electrical use and reduce their bills.
AMR also allows utilities to save money in areas beyond meter reading,
including real-time service outage reporting; tamper and theft-of-power report-
ing. Further, voluntary conservation by customers empowered with real-time
pricing and use information can reduce the wholesale cost of power during peak
demand periods.
Idaho Power claims AMR is not cost-effective at the present time but
would consider implementation at a future date. If the commission wanted
IDAHO PUBLIC UTILITIES COMMISSION Page 262003
ANNUAL REPORT
implementation sooner, the company did say it would be willing to install the
technology in the Emmett area and measure the results.
The commission said implementation in the Emmett area alone is not
sufficient to adequately resolve uncertainties regarding the technology and
directed Idaho Power to propose a combination of two or three service areas
that will incorporate a larger, more diverse customer group and geographic
scope. The commission said phase one of AMR must be installed in the se-
lected territory by Dec. 31, 2004. The company must file its implementation
plan, including the selected territory, by Dec. 24, 2003.
“The potential benefits of advanced metering available to ratepayers
and the company are too great to delay AMR implementation indefinitely,” the
commission said. “However, we also recognize that significant questions and
uncertainty remain regarding the proper technology, installation costs, function-
ality and actual cost savings that may be realistically achieved.”
Automated meters are one way customers could respond to the recent
rapid increase in electric rates by being able to view real-time pricing informa-
tion and adjust their own use accordingly, the commission said.
“Over the last two years the commission heard from many frustrated
residential customers who did not have the information and options necessary
to make informed choices relative to their use of the energy,” the commission
said. Commissioners noted that due to extremely low water conditions and
large purchased power costs, Idaho Power residential rates increased about 39
percent over base rates between May 2001 and 2003.
The commission expressed concern about the company’s ability and
willingness to efficiently implement Phase One and fairly evaluation its results.
The commission said the company may file to recover costs of AMR implemen-
tation, but only if the company “makes a sincere effort to efficiently and effec-
tively install and evaluate this technology.”
“We are frustrated with what appears to be the shifting position of the
company with respect to AMR implementation,” the commission said. The
company initially expressed intent to seek budget approval to implement AMR
in 2004, but now states AMR is not cost-effective and should not be imple-
mented at any level, the commission said.
By the end of 2005, Idaho Power must submit a status report on the
first phase of AMR installation. “Upon review of that status report detailing
costs and benefits resulting from this limited AMR installation, the commission
will determine if the benefits of AMR justify its implementation beyond the areas
covered in Phase One,” the commission said.
The company said it is now installing AMR-capable meters for new
residential and commercial services. Commissioners said installation for new
customers “makes sense, and we expect the company to pursue this strategy
regardless of the Phase One implementation.”
Automated
meter reading allows
utilities to save money
in areas beyond meter
reading, including real-
time service outage
reporting; tamper and
theft-of-power report-
ing. Further, voluntary
conservation by cus-
tomers empowered
with real-time pricing
and use information
can reduce the whole-
sale cost of power
during peak demand
periods .
2003
ANNUAL REPORTPage 27 IDAHO PUBLIC UTILITIES COMMISSION
October 30, 2003
IDAHO POWER PROPOSES NEW GAS PLANT
Case No. IPC-E-03-12, Order No. 29370
The Idaho Public Utilities Commission was expected to rule by the end
of 2003 on Idaho Power Company’s application to construct a 162-megawatt
gas-fired power plant in Mountain Home called the Bennett Mountain Plant.
Idaho Power selected a bid from Boise-based Mountain View Power,
one of 11 bids considered for the project. Mountain View contracted with
Siemens-Westinghouse Power Corporation to furnish all the labor, equipment
and materials and to perform all the engineering and construction of the pro-
posed project. Upon completion of the project and passage of necessary
performance tests, title of the project will transfer from Mountain View to Idaho
Power.
Idaho Power contracted with Mountain View for $44.6 million for
construction of the plant with a commitment estimate of up to $54 million to
account for unanticipated costs. Idaho Power will absorb all costs that exceed
$54 million.
Idaho Power is requesting that the commission issue a Certificate of
Public Convenience and Necessity by no later than Dec. 31. Mountain View
needs to receive a notice to proceed by that date, Idaho Power said. Construc-
tion is to be 95 percent complete by December 2004 and the plant ready to
operate by summer 2005.
The commission has accepted petitions to intervene from the Industrial
Customers of Idaho Power and the Idaho Irrigation Pumpers Association.
Construction of the plant is intended to help Idaho Power provide an
additional 250 megawatts the company will need to meet its customer demand
by summer of 2005. The shortfall was to be met with the construction of a 250-
MW Garnet plant in Middleton. That project was discontinued after Garnet
failed to secure financing for the project.
Idaho Power anticipates that construction of the Bennett Mountain plant
– in addition to an agreement recently approved by the commission for Idaho
Power to buy 83 megawatts from PPL Montana during the peaking months of
June, July and August beginning next year – will meet the company’s anticipated
shortfall.
The company estimates $11.6 million in transmission costs to connect
the plant to the company’s transmission system four miles north of the plant site.
Fuel costs for the project will be included in the company’s annual power cost
adjustment process as are all power supply expenses. Williams Northwest
Pipeline, whose pipeline is less than one mile from the proposed plant site, will
supply gas.
The plant site is an approximate 10-acre plot within the Mountain Home
Industrial Park. The plant site is large enough to accommodate an additional
IDAHO PUBLIC UTILITIES COMMISSION Page 282003
ANNUAL REPORT
generating unit if needed. The city has already issued a conditional use permit
for construction of the plant. According to Idaho Power, the city has substantial
water supply capacity to serve the plant. The plant’s wastewater will be dis-
charged into the city’s sewer system.
2003
ANNUAL REPORTPage 29 IDAHO PUBLIC UTILITIES COMMISSION
Nov. 13, 2003
AVISTA FILES RATE INCREASE NOTICE OF INTENT
Avista Utilities filed a notice of intent to file a combined electric and
natural gas general rate case on or after January 15, 2004. Under commission
rules, utilities are required to provide a minimum 60-day notice wiht the com-
mission if they intend to file for a rate increase. An intention to file does not
necessarily mean that the utility will in fact file for a rate case, but it is a strong
indicator that it will do so. The timeline allows PUC staff time to prepare for an
anticipated filing.
In its notice, Avista stated it was its intent to use the calendar year
ending Dec. 31, 2002, as the test year for its filing. The last time, Avista imple-
mented a general rate change in Idaho was Aug. 1, 1999, for electric customers
and Feb. 17, 1990 for natural gas customers.
A rate case can take up to six months for the commission to decide.
Nov. 20, 2003
AVISTA SURCHARGE CONTINUED ANOTHER YEAR
Case No. AVU-E-01-16, Order No. 28948
A 19.4 percent surcharge that is added to Avista Utilities’ base rate has
been extended by the Idaho Public Utilities Commission for another 12 months.
However, the commission may yet decide to deny the company author-
ity to collect from customers nearly $12 million in expenses resulting from two
fuel purchase transactions entered into by the company during the energy crisis
of 2000-01.
The fuel purchased by Avista was not used and ultimately sold back
into the market. The fuel was intended for use at Avista’s Coyote Springs II
gas-fired generating plant. The plant wasn’t operational at the time and keeping
the gas was no longer economical.
In order to allow the company an opportunity to defend the fuel pur-
chases, the commission agreed to treat the matter in a rate case that Avista
expects to file in early 2004. An adjustment to rates will be made at the time to
Number of Customers
106,390
Avista Utilities
(physical address)
E 1411 Mission Ave.
(mailing address)
P O Box 3727
Spokane, WA 99220
800-727-9170
509-489-0500
(Spokane)
208-664-0421
(Coeur d’Alene)
208-743-5541
(Lewiston)
208-882-7511
(Moscow)
Avista Utilities
During 2002, Avista Utilities generated 70 percent of its electricity at
hydropower dams located in Washington, Idaho and Montana. The company
also receives power from thermal plants in the same three states.
In 2002, the average Avista household used 11,095 kWh, essentially
the same as the 11,105 kWh used during 2001. This figure averages residential
customers with electric space and water heating with those who do not use
electricity for these uses.
IDAHO PUBLIC UTILITIES COMMISSION Page 302003
ANNUAL REPORT
reflect the commission’s decision regarding the gas purchases.
The 19.4 percent surcharge was implemented in October 2001. At that
time, the company sought a 27-month surcharge to recover $78 million in
extraordinary power supply costs incurred during the 2000-01 energy crisis.
The commission agreed to implement the surcharge for only 12 months so it
could annually review how Avista was handling the deferred account. After
commission adjustments, the account reflects a balance of $16.5 million as of
June 30 of this year. Last year on June 30, the deferral balance was $45 million.
The commission also increased the deferral amount by $256,727 as the
result of an interest adjustment.
Commission staff had earlier recommended denying the company
recovery for a single transaction that included $5.93 million in fuel and interest
costs for the Coyote Springs plant. In this week’s order, the commissioners
expand staff findings, proposing that yet another transaction that included $6
million in gas and interest costs also be considered for denial.
In both transactions, Avista locked in its price for gas for well beyond
the 18-month time period allowed by the company’s risk management policy,
according to commission staff. One transaction locked in the price for two and
a half years and the other for three and a half years.
Avista anticipated that Coyote would be operational and more eco-
nomical to operate than buying energy from the wholesale market. As it turned
out, Coyote Springs was neither operational nor was it economical to use the
gas purchased for Coyote at Avista’s other facilities. Instead, Avista simply
purchased its needs on the wholesale market and sold the gas back into the
market at a loss.
According to staff, work papers from the transactions indicated the gas
purchases were entered into for the sole purpose of securing financing for the
Coyote Springs project. Commission staff contends the transactions were made
to meet Avista’s cash flow requirements and were not necessarily associated
with utility operations. To be able to recover power supply costs, utilities have
to demonstrate to the commission that the costs were incurred strictly to
provide power for customers and not for other benefits such as, in this instance,
improving the utility’s cash flow.
Avista contends the transactions were made at a time when wholesale
electric prices were at unprecedented highs, federal regulators were continuing
to refuse to intervene and the utility was facing the worst hydroelectric condi-
tions in its history. The company believes that a careful review of the information
available at the time the transactions were made will show the company’s
decisions were reasonable given the circumstances.
2003
ANNUAL REPORTPage 31 IDAHO PUBLIC UTILITIES COMMISSION
October 23, 2003
AVISTA, POTLATCH NEAR SETTLEMENT
Case No. AVU-E-03-2
At the time this annual report was going to press, the commission was
near ruling on a proposed settlement of a 10-year power purchase agreement to
buy 62 average megawatts of capacity from Potlatch Corporation at a rate of
$42.92 per megwatt-hour.
Potlatch owns and operates four electric generators at its wood product
manufacturing facility in Lewiston.
Under the agreement, Potlatch would sell Avista 543,120 megawatt-
hours a year at the $42.92 per MWh rate. For generation beyond that amount,
Avista would pay 85 percent of the market price at the Mid-Columbia trading
hub as long as the rate does not exceed $55 per MWh.
Avista proposes to recover the costs from the Potlatch generation from
its customers through the annual power cost adjustment process.
The agreement also stipulates that Potlatch buy power from Avista at the
established tariff rate for all extra-large general service customers.
The agreement, if approved, would settle two other open cases before
the commission regarding Potlatch and Avista.
IDAHO PUBLIC UTILITIES COMMISSION Page 322003
ANNUAL REPORT
March 17, 2003
PUC, PACIFICORP AGREE ON IRRIGATION PROGRAM
Case No. PAC-E-03-3, Order No. 29209
The Idaho Public Utilities Commission approved a PacifiCorp program
that pays credits to irrigators who volunteer to shift their electrical use from
super-peak hours to light-load hours during the four-month irrigation season.
The “time-of-use” program is a compromise from the program originally
proposed by PacifiCorp, which would allowed the company to pay irrigators
credits for the ability to interrupt service to irrigators who chose to participate.
But that proposal was unacceptable to the commission because the company
factored “lost revenue” (revenue the company would have gained from irrigators
had the program not been in place) into the value of the credit, resulting in a
significantly lower credit to irrigators. The Idaho Irrigation Pumpers Association
also did not agree with PacifiCorp’s proposed method of calculating the value of
the credit.
PacifiCorp then submitted an alternative proposal that rewards irrigators
for shifting operation of their pumps from periods of high use, called “super-
peak” hours to light-load hours.
Using a comparison of super-peak market prices to light-load hour
market prices, the company will provide these credits against irrigators’ monthly
demand charge for the 2003 irrigation season:
„June, $1.54 per kW
„July, $2.06 per kW
„August, $2.25 per kW
„September, $1.26 per kW
In calculating the value of the credit, PacifiCorp included a 30 percent
uncertainty factor in recognition of several factors that are difficult to measure
ahead of time such as the total amount of load that will be shifted, hours of the
day that load is shifted, the level of load control equipment failure, failure of
Number of Customers
57,595
Pacificorp
dba
Utah Power & Light
1407 West N.Temple
Salt Lake City
Utah, 84116
801-220-2000
(SLC)
208-852-1916
(Preston)
208-356-7366
(Rexburg)
PacifiCorp-Utah Power
Based in Salt Lake City, Utah Power, a division of Portland-based
PacifiCorp, provides electricity in eastern Idaho. It is the third largest electric
utility in Idaho.
During 2002, Utah Power generated 88.5 percent of its energy needs
from thermal resources.
In 2002, the average UP&L residential customer used 12,783 kWh of
electricity, a 1.5 percent increase from the 12,599 kWh average in 2000. This
figure averages residential customers with electric space and water heating with
those who do not use electricity for these uses.
2003
ANNUAL REPORTPage 33 IDAHO PUBLIC UTILITIES COMMISSION
customers to shift load, etc. The proposed credits are thus 70 percent of the
difference between expected super-peak and off-peak market prices.
The commission’s order emphasizes that the program is voluntary to
irrigation customers who enter into a Load Control Service Agreement with
PacifiCorp.
The commission directed the company to submit a report at the end of
the irrigation season summarizing its results. Once filed, the report will be
opened for public comment in anticipation of possible changes that will result in
an improved program for the 2004 irrigation season.
A commission order issued last June that allowed PacifiCorp to recover
$22.7 million in power supply expenses, encouraged the company to work with
irrigators to develop a load control program that can reduce power supply
expenses for the company and prevent it from going to the wholesale market
for additional power.
June 20, 2003
PUC APPROVES PACIFICORP NET METERING PROGRAM
Case No. PAC-E-03-4, Order No. 29260
The Idaho Public Utilities Commission approved a “net metering”
program for PacifiCorp’s southeast Idaho customers.
The program will allow customers who own a generation facility fueled
by solar, wind, biomass or hydropower to interconnect with PacifiCorp’s
electric grid and generate all or a portion of their electric needs. Customers who
generate more power than they consume will credited at the retail rate.
In late February, the Northwest Energy Coalition petitioned the com-
mission to establish a net metering plan for PacifiCorp customers that was
similar to plans already in place for Idaho Power Co. and Avista Utilities
customers. The coalition is made up of 12 member organizations including the
Idaho Rural Council, Idaho Rivers United and the Idaho Community Action
Agency.
PacifiCorp responded by stating that it was in the process of develop-
ing a net metering schedule at the time the coalition filed its petition.
Under PacifiCorp’s proposal, residential and small-commercial custom-
ers can qualify small generators up to 25kW. Irrigation and large commercial
customers would have a capacity limit of 100 kW. Customers can interconnect
their generators on to the company’s system, but must pay interconnection and
any additional metering costs that may be necessary. Residential and small-
commercial customers would be credited the current retail rate for excess
energy they produce, while irrigation and large commercial customers would be
IDAHO PUBLIC UTILITIES COMMISSION Page 342003
ANNUAL REPORT
August 29, 2003
COMMISSION OKs PACIFICORP ‘BLUE SKY’ PROGRAM
Case No. PAC-E-03-9, Order No. 29329
The Idaho Public Utilities Commission has accepted a PacifiCorp-Utah
Power program that allows customers who volunteer to buy renewable energy
for an additional $1.95 per month for every 100 kilowatt-hours purchased. The
renewable energy tariff becomes effective on Sept. 1.
Commissioners approved the program on a 2-1 vote, “with some
degree of reluctance and disappointment.” Commissioner Marsha Smith
dissented. The commission said the company allocates too much of the cost of
the $1.95 premium to administration, marketing and promotion of the program
rather than to green power purchases.
The commission three years ago rejected the program for Idaho
because the $4.95 per month premium was too expensive. While the commis-
sion said it was pleased the company has significantly lowered the premium
since its 2000 application, it notes that the premium reduction is due primarily to
changes in wind energy costs and not program redesign, as the commission had
encouraged. Nearly 60 percent of the premium still goes toward administration
and marketing. “Our prior admonition regarding overhead and allocation of
premium dollars appears to have fallen on deaf ears,” the commission said.
Commissioners were also disappointed that the company projects only
160 customers to participate in the program during the first year and 415 by
year four.
“We also note that the projected level of program participation in Idaho
remains quite small, much lower than the company’s other service area jurisdic-
tions, and that no change in marketing is proposed to increase participation
levels,” the commissioners said. Currently, about 11,500 PacifiCorp customers
in Oregon, Utah, Washington and Wyoming are enrolled.
Customers who voluntarily agree to pay $1.95 per month would buy a
single 100-kWh block of renewable energy and can choose to pay an addi-
tional $1.95 for each 100-kWh block.
PacifiCorp will use two methods to secure the renewable energy.
One is buy green energy, such as from a wind farm, and to make arrangements
for transmission of that energy to its eastern Idaho territory within two years of
credited 85 percent of a Dow Jones index price for non-firm energy.
Customers will be allowed to participate on a first-come, first-served
basis until the total rated generated capacity reaches one-tenth of 1 percent of
the company’s Idaho retail peak demand in 2002.
Some organizations, like the Farm Bureau, sought a higher cap on the
capacity of net metering projects. The commission said that if the cap is reached,
it will consider increasing it at that time.
2003
ANNUAL REPORTPage 35 IDAHO PUBLIC UTILITIES COMMISSION
when the energy is purchased by the customer.
The other method is to purchase “green tags,” or credits that allow the
company to buy green energy for its use, although the actual kilowatts pur-
chased may not directly go to the customer. However, the energy purchased
becomes part of PacifiCorp’s portfolio and eliminates the need for PacifiCorp
to acquire that energy from non-renewable sources. The energy from the credit
must be delivered within 18 months.
Commissioners expressed concern that the two-year lapse between
premium payment and a renewable energy benefit will not encourage customer
acceptance of the program.
Despite those reservations, the commission agreed to accept the
program because it supports renewable energy choices, the program is volun-
tary, the premium price is now comparable to other green tariff programs and
no subsidy is required from non-participants.
PacifiCorp serves about 60,000 customers in its eastern Idaho territory,
of which about 47,000 are residential customers.
IDAHO PUBLIC UTILITIES COMMISSION Page 362003
ANNUAL REPORT
Generic Electric Cases
March 28, 2003
PUC DENIES REQUEST BY ENERGY PRODUCERS
TO INLCUDE LARGER PROJECTS UNDER PURPA
Case No. GNR-E-03-1, Order No. 29216
By a 2-1 vote, the Idaho Public Utilities Commission declined a request
by the Independent Energy Producers of Idaho that larger independent power
projects be able to qualify for published contract rates.
Currently, only renewable projects that generate up to 10 megawatts
can qualify for the rates, often called PURPA rates. The Independent Energy
Producers of Idaho asked that projects up to 30 MW qualify for PURPA rates.
The energy crisis of the late 1970s prompted Congress to pass the
Public Utilities Regulatory Policies Act, or PURPA. Its purpose is to encourage
the development of renewable energy technologies as alternatives to burning
fossil fuels or building new power plants. PURPA requires that electric utilities
offer to buy power produced by qualifying small power producers or
cogenerators. State commissioners set the rate that utilities must pay small
power producers for the power they generate. That rate, called “avoided cost
rate,” is to be equal to the cost the electric utility avoids by not generating the
power itself.
Last year, the commission agreed to a request by developers to extend
the contract length of PURPA projects from five to 20 years and increase the
size of projects that can qualify from 1 megawatt to 10 megawatts.
The Independent Energy Producers of Idaho claim that the 10 MW
limit is still not big enough to allow energy producers to recover their investment
in energy projects. IEPI contends the commission is to proactively encourage
development of renewable sources as a means of diversifying the national
energy portfolio, making it less dependent on foreign sources.
Commission President Paul Kjellander and Commissioner Dennis
Hansen voted to deny IEPI’s request, saying more time is needed to gauge the
response from last year’s increase. Further, they said, independent producers
larger than 10MW can still negotiate individual contracts with utilities. If the
parties cannot agree on a rate, either can file a complaint with the commission.
In her dissent, Commissioner Marsha Smith said IEPI’s contention that
the effect of an increase in project size to utilities and consumers is inconsequen-
tial merits further examination and public comment.
“Development of renewable resources not tied to natural gas as a fuel
source would help avoid additional demand for natural gas and the associated
upward pressure on rates for that commodity,” Smith said. “It would also add
to the diversity in the resources available for electricity production in our state
and region.”
2003
ANNUAL REPORTPage 37 IDAHO PUBLIC UTILITIES COMMISSION
November 29, 2002
PUC DENIES WINTER MORATORIUM CHANGES
Case No. GNR-U-02-1, Order No. 29165
The Idaho Public Utilities Commission denied a request by Intermoun-
tain Gas and PacifiCorp to significantly alter commission rules regarding the
“winter moratorium,” the three-month period during which utilities are prohib-
ited from disconnecting customers who fail to make payments.
Customers who commented on the proposed changes said they were
uncomfortable with the quick scheduling necessary to implement the proposed
two-year pilot program, which would have begun Sunday, Dec. 1, 2002, and
lasted through Feb. 28.
Commissioners shared the utilities’ concern regarding customers who
abuse the program, which does not include income eligibility requirements and
does not disconnect eligible customers who fail to make any payment during the
three-month period. “We are aware that the desire to protect those who
struggle financially from winter disconnection must be balanced with requiring
accountability from customers who are able to pay but use the moratorium as
an opportunity to avoid making monthly payments,” the commissioners said.
However, after evaluating 142 comments received from the public,
commissioners said a “significant number of customers did not fully understand”
the proposal, which would have required income eligibility criteria and minimum
monthly payments from customers if they wanted to avoid disconnection during
the winter months. “Under these circumstances, the commission is not willing to
alter a 20-year public safety policy without allowing sufficient time to educate
the public and respond to customer concerns,” the commissioners said.
Instead, the commissioners are directing all of the state’s investor-
owned utilities to compile more information through this winter heating season
for possible revisions next winter. And during this year’s winter heating season,
the commission is asking utilities to encourage customers participating in the
moratorium to pay a minimum amount during the winter months. “We expect
the utilities’ customer service representatives to ask what amount the customer
can afford to pay and receive the customer’s oral commitment to pay a mini-
mum amount,” the commissioners said. Also, Intermountain Gas customers who
wish to participate in the moratorium must contact the company to declare
eligibility this year even if they have participated in the program during past
years.
Enacted in 1979, the moratorium does not excuse customers from
paying their bills, but it postpones disconnection for failure to pay bills until after
March 1. Utilities sought the revisions partially due to concerns that customers
were choosing not to pay any amount during the winter moratorium and then
could not pay the typically high bills that became due March 1. Under current
rules, utilities cannot disconnect customers who declare they are unable to pay
and have children under 18 or people over 62 or “infirm” persons living in the
IDAHO PUBLIC UTILITIES COMMISSION Page 382003
ANNUAL REPORT
household. There is no income eligibility requirement.
After a series of meetings with representatives from community action
agencies, the Department of Health and Welfare, commission staff, Intermoun-
tain Gas, PacifiCorp and Avista, the utilities applied for a two-year pilot program
that would require customers become eligible for the moratorium by meeting the
income requirements for receiving energy assistance benefits under the Low-
Income Heating Energy Assistance Program (LIHEAP). To qualify for LIHEAP,
participants must earn no more than 150 percent of federal poverty guidelines.
The utilities also wanted customers to pay a minimum amount each of the three
months that would equal one-half of what they would pay under a level-pay
plan. Avista later withdrew from the case, citing customer concerns over its
timing.
Timing was also the major concern cited by commissioners in its denial
of the utilities’ application. Commissioners were also concerned that a notice
sent by Intermountain Gas to its customers may have led too many customers to
believe that the minimum monthly payment for customers participating in the
moratorium would have been only $25 during those three months. “The com-
mission is concerned that the public is not aware that the $25 amount referred to
by Intermountain Gas was an average amount.” The actual payment could be
significantly more, the commissioners said.
The commission included in the order a detailed list of information it
wants the utilities to compile this winter. It also directed Intermountain Gas to
require its customers to notify the company each winter heating season if they
are seeking winter moratorium protection. Up until now, the company required
customers to declare they wanted to participate only once and then they are
permanently coded as moratorium eligible.
2003
ANNUAL REPORTPage 39 IDAHO PUBLIC UTILITIES COMMISSION