electric.pdf

2002
ANNUAL REPORTPage 1 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
2001 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
318,076 Residential Customers/$0.0609
62,178 Commercial Customers/$0.0491
107 Industrial Customers/$0.0400
Avista Utilities
2001 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
89,837 Residential Customers/$0.0564
14,576 Commercial Customers/$0.0587
538 Industrial Customers/$0.0477
2001 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
PacifiCorp/Utah Power
44,644 Residential Customers/$0.0636
6,379 Commercial Customer/$0.0648
5,411 Industrial Customer/$0.0353
Idaho’s
Electricity
Rates Are
Among The
Lowest In
The Nation
IDAHO PUBLIC UTILITIES COMMISSION Page 22002
ANNUAL REPORT
Power Rates in Idaho
As of Oct. 1, 2002
These rates do not include customer charges. Not all available rate
schedules are shown for each utility.
IDAHO POWER COMPANY
Residential -- $0.0672
(Rate is $0.06867, but with BPA credit of $.001506, reduced rate is $0.0672.)
Commercial
Small commercial — $0.0769, plus $2.51 per kW demand charge
Large commercial — $0.04552, plus $2.73 per kW demand charge
Industrial
Large industry — $0.0428; plus $2.73 per kW demand charge
Irrigation — $0.0418 in season (not including BPA credit); plus $3.58 per kW
demand charge in season.
AVISTA UTILITIES
Residential
First 600 kWh — $0.0517
All use over 600 kWh — $0.0607
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 — $0.0345 per kWh plus $7,500 for first 3,000 kVA (kilovolt-
amps) of demand or less and $2.25 per kVA for demand over 3,000 kVA.
2002
ANNUAL REPORTPage 3 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 — $0.752
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 — $0.0326 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 — $0.0264, plus $4.05 per kW demand
Next 225,000 kWh — $0.0101, plus $4.05 per kW demand
All additional kWh -- $-0.0029, plus $4.05 per kW demand
IDAHO PUBLIC UTILITIES COMMISSION Page 42002
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 second year of poor hydro conditions in 2001, only 43 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 2001, the average Idaho Power household used 13,944 kWh, up
4.4 percent from the 13,535 kWh in 2000. This figure averages residential
customers with electric space and water heating with those who do not use
electricity for these uses.
Nov. 21, 2001
PUC ORDERS CONSERVATION, DELAYS SURCHARGE
Case No. IPC-E-01-13, Order No. 28894
The commission directed Idaho Power Co. to implement conservation
programs in time for this winter’s heating season and to use existing resources
to cover the costs of the short-term programs. The company requested a two-
year surcharge to fund the programs.
The programs, called demand side management programs, include
financial incentives to residential customers such as compact fluorescent bulb
coupons, Energy Star appliance incentives, high efficiency air conditioner and
heat pump rebates, weatherization loans and low-income assistance.
Idaho Power asked that a two-year tariff rider be added to customer
bills to generate $2.6 million to fund the programs. The rider would have
resulted in an increase to the average residential bill of about 28 cents a month.
The commission decided not to grant the rider at this time. “Given the large rate
increases authorized already this year, the commission is reluctant to raise rates
any further by implementing a tariff rider at this time, even to fund a worthy
endeavor such as this,” the commissioners said.
Commissioners noted that due to extremely low water conditions and
unusually high wholesale power costs, Idaho Power’s residential rates have
increased a combined average of 31 percent in the last seven months. Had
demand-side management programs such as those proposed now been in place
during the last year, they “may have reduced power supply costs and the
subsequent increases in Idaho Power’s rate,” the commissioners said.
Number of Customers
= 380,361
Idaho Power Company
1220 W. Idaho Street
P O Box 70
Boise, ID 83707
800-488-6161
208-388-2323
(Treasure Valley)
2002
ANNUAL REPORTPage 5 IDAHO PUBLIC UTILITIES COMMISSION
Feb. 13, 2002
NET METERING RATE OK’D, BUT IPC ASKED TO DO MORE
Case No. IPC-E-01-39, Order No. 28951
The Idaho Public Utilities Commission wants Idaho Power Co. to
expand a renewable energy program to include people in all customer classes,
such as irrigation customers, dairy farmers using biomass technology, and
generators of wind power. Idaho Power proposed to offer its net metering
program only to residential and small commercial customers.
Net metering allows customers who generate their own power through
means such as solar panels, windmills, fuel cells or small generators, to measure
how much power they are consuming and how much excess power they are
selling back to the power company. The meter is bi-directional. All energy
supplied by the company to the customer will cause the meter to run forward
while all energy delivered by the customer to the company will cause the meter
to run backward. Customers get credits when they are generating more power
than they are consuming.
The commission approved Idaho Power’s proposed tariff schedule for
residential and small commercial customers who want to participate in net
metering. But comments filed by organizations, including the Idaho Farm Bu-
reau, Idaho Rural Council, Renewable Energy Advocates and the Idaho De-
partment of Water Resources, supported expanding the program to include all
customer classes and to accept bigger projects than those limited to 25 kW
capacity as proposed by Idaho Power.
The commission approved the net metering rate proposed by Idaho
Power for just residential and commercial customers and agreed to the
company’s 25 kW limit for those two classes, but ordered the utility to file an
expanded net metering program within six weeks that includes the remaining
customer classes and higher capacity allowances for those other classes.
The commission also approved Idaho Power’s proposed 2.9 MW
capacity limit for the combined generation of all net metering projects, but
agreed with those who said that if the limit is reached, the commission will
review it for a possible increase.
Idaho Power opposed extending the program to irrigation and industrial
customers because those customers can already negotiate contracts to generate
renewable energy to sell to the utility under the Public Utilities Regulatory
Policies Act (PURPA). But the commission said the primary purpose of net
metering is not as much to generate power as it is to provide customers the
opportunity to offset their own energy requirements and turn back their meter,
which can be particularly helpful during this time of high electric bills.
Idaho Power also opposed increasing the 25 kW limit on each cus-
tomer-owned generation facility because of potential safety and service issues
and concerns about stress on the regional electric grid. However, the commis-
sion said Idaho Power’s 25 kW limit is “unreasonably low” for customer classes
IDAHO PUBLIC UTILITIES COMMISSION Page 62002
ANNUAL REPORT
other than residential and small commercial. “We find a more reasonable limit
for irrigators, dairies and other customer classes is in the range between 100 to
125 kW,” the commission said. The commission asked the company to detail
its concerns in the upcoming filing and offer proposed solutions.
April 3, 2002
UTILITY DIRECTED TO FORM ENERGY EFFICIENCY GROUP
Case No. IPC-E-01-13, Order No. 28993
The commission ordered Idaho Power Co. to immediately form an
Energy Efficiency Advisory Group that will outline proposed long-term conser-
vation programs. A commission order on Nov. 21, 2001, directed Idaho Power
to form the advisory group. On March 14, the Land and Water Fund of the
Rockies filed a motion asking the commission to enforce that order.
The commission did so, directing the company to appoint the members
of the advisory group and establish a plan for implementing conservation
programs by no later than May 2. “The deadline will prove to be a substantial
task, but it is a situation of Idaho Power’s own making,” the commissioners
said.
The company said it interpreted the original November order to mean it
could appoint the advisory group after the commission had decided how the
conservation programs would be funded. Idaho Power last year asked that a
two-year tariff rider be added to customer bills to fund the programs. The rider
would have resulted in an increase to the average residential bill of about 28
cents a month. The commissioners denied funding at that time, but said it would
take the matter up this spring through the company’s annual power cost adjust-
ment process.
Commissioners said the language of the November order explicitly
stated that Idaho Power would form the advisory group and create an imple-
mentation plan so that the necessary groundwork would be in place once the
funding issue was resolved. “We do not understand how Idaho Power could
construe this language in a manner that would justify waiting until the program
was funded before convening the advisory group,” the commissioners said.
“Although it would be helpful for the advisory group to know the amount of
funding that will be available, there is no reason it cannot investigate and priori-
tize desirable conservation programs without this information.”
“In short, the commission is disappointed that Idaho Power has done
so little to comply” with the November order, commissioners said. “Although
we do not currently hold the company in contempt, the commission does find
Idaho Power’s inaction to be a serious breach of compliance.”
2002
ANNUAL REPORTPage 7 IDAHO PUBLIC UTILITIES COMMISSION
May 13, 2002
IDAHO POWER GRANTED $256 MILLION DEFERRAL, BUT
BOND PLAN DENIED
Case No. IPC-E-02-2, IPC-E-02-3. Order No. 29026
Declaring it refuses to mortgage Idaho Power ratepayers’ future, the
Idaho Public Utilities Commission denied the utility’s request to spread the past
year’s power supply costs over three years by issuing bonds.
Instead, the commission authorized recovery of nearly all the $255.9
million in cost recovery allowed in a one-year period. That will mean a slight
increase for most residential customers, varying from 3 to 10 percent. However,
residential customers who use more than 3,000 kWhs per month will notice a
decrease because of the commission’s decision to discontinue the residential
tiered-rate structure.
“We find it unreasonable and contrary to the public interest to mortgage
the future of ratepayers simply to achieve a small rate decrease this year,” the
commissioners said.
Uncertainties regarding water supply and market volatility led the
commission to choose a one-year recovery plan for all but about $11.5 million
of the $255.9 million in power supply costs. Commissioners rejected the three-
year plan because of fears that another drought year or another period of high
wholesale prices could result in customers paying for new increases while still
paying for the 2001-02 power supply expenses.
“The commission does not make this decision lightly. We understand the
hardships that last year’s large rate increase is imposing on customers,” the
commissioners said. “However … the commission is very concerned about the
unknown water and market conditions that lie ahead. We are also very reluctant
to create a situation where customers are required to continue paying costs from
this year on top of whatever increases may be required in future years.”
A one-year recovery will take care of nearly all the deferred costs
remaining from a sustained period of extraordinarily high wholesale prices at the
same time that hydro-dependent Idaho Power customers were experiencing the
second worst drought in 75 years. Ratepayers also avoid paying bond issuance
and finance costs of about $21 million with the commission’s decision to deny
Idaho Power’s three-year bond plan.
“We certainly hope that this is the last year Idaho Power ratepayers will
be faced with such extraordinarily high” power supply costs, the commissioners
said. “However, as we have learned over the past two years, there are no
guarantees about future stream flows or market prices,” commissioners said.
The commission also authorized Idaho Power to implement a tariff to
raise about $2.6 million for conservation programs that can mitigate the
impact of this rate increase as well as those that may occur in the future. For
example, a coupon program for compact fluorescent bulbs could offset the
increase and, in some cases, result in lower bills. The tariff will be a 30-cent per
IDAHO PUBLIC UTILITIES COMMISSION Page 82002
ANNUAL REPORT
month charge to residential customers.
The commission denied about $17.4 million of Idaho Power’s cost
recovery request. Most of that – $15.1 million – is money the utility sought to
recover as revenue the company would have earned had it sold power to
irrigation customers who participated in the company’s load reduction program.
Another $1.2 million the company spent installing mobile diesel generators was
denied as was $1.1 million in costs associated with construction of the utility’s
natural gas plant in Mountain Home. The commission also discounted, by $4.3
million, trading transactions from July 2001 through March of this year.
With the end of the tiered-rate structure, residential customers will
pay a flat rate of 7.1 cents per kWh. The result will be larger increases for
residential customers who benefited from the tiered-rate now in place. The
monthly bill of a residential customer who uses 500 kWhs per month will
increase from about $33.34 per month to $36.85, about a 10.5 percent in-
crease. The bill of a residential customer who uses 1,500 kWhs per month will
increase from $100.62 per month to about $105.52, or a 4.7 percent increase.
A customer who uses 3,000 kWhs per month will see a decrease from
$219.36 to about $208.23, about a 5 percent decrease.
Tiered rates created unanticipated problems when Idaho Power’s
meter reading cycle extended beyond 30 days. A 32- or 33-day billing period
sometimes pushed customers into a higher rate block, forcing them to pay more
than they would have under a normal 30-day cycle. The commission was also
concerned about the public’s perception of tiered rates. Many customers
blamed their high energy bills on the tiered rate rather than the primary cause: an
average 31 percent residential increase over the previous winter’s rate. Bills of
customers using about 2,000 kWhs per month were about the same with the
tiered rate as they would have been with a flat surcharge. The tiered rate was
designed to send a strong conservation signal and allocate a portion of less
expensive electricity to all customers to ensure a minimal amount of energy
essential for customer health and safety.
“From the public comments we received, it was apparent many
ratepayers did not understand the purpose or actual dollar effect of tiered
rates,” commissioners said. Of the 274 written comments the commission
received about this case, 132 specifically mentioned opposition to the tiered
rates while only nine supported their continued use. More than 100 of those
commenting mentioned they lived in all-electric homes where it is difficult to
drastically reduce consumption and fall into a lower-rate tier.
While the commission directed Idaho Power to recover nearly all the
$255.9 million in approved power supply costs in one year, it did allow the
deferring of $11.5 million in costs allocated to customers in the irrigation
(Schedule 24) and small general service (Schedule 7) classes into a second
year. Customers in those classes will experience no increases as a result.
2002
ANNUAL REPORTPage 9 IDAHO PUBLIC UTILITIES COMMISSION
June 11, 2002
IPUC ACCEPTS IDAHO POWER, FMC-ASTARIS SETTLEMENT
Case No. IPC-E-01-43, Order No. 29050
At the urging of the Idaho Public Utilities Commission, Idaho Power
Co., Astaris LLC and the staff of the commission have resolved potentially
costly and time-consuming contract issues in a manner that benefits both compa-
nies and Idaho Power ratepayers.
“The result is a financial benefit to ratepayers and it resolves costly
matters in the courts,” said Commission President Paul Kjellander.
During last year’s season of record drought and extremely high whole-
sale market prices for power, Idaho Power entered into a voluntary load
reduction program with Astaris, a phosphorous plant near Pocatello. Astaris
agreed to consume no more than 70 megawatts of the 120 MWs of power
Idaho Power had agreed to provide and Astaris had agreed to take each year
under a 1997 agreement.
In the 2001 load reduction agreement, Idaho Power agreed to pay
Astaris 15.9 cents for each kWh not used. That prevented Idaho Power from
having to go to the market and buy the remaining 50 MW at wholesale prices
that were nearly twice as high as the agreed upon 15.9 cents.
The load reduction program began in April 2001, but in December,
Astaris decided to close its Pocatello plant, which then reverted to FMC. That
closure, coupled with wholesale prices returning to normal levels, prompted the
commission, in January of this year, to initiate an investigation into the continued
reasonableness of the load reduction program.
In the wake of its plant closure, Astaris, earlier this year initiated court
action against Idaho Power in the Fourth Judicial District seeking relief from its
1997 “take or pay” agreement with Idaho Power.
After an evidentiary hearing in late February, the commission directed
the parties to attend a settlement conference, which was followed by protracted
negotiations. The parties signed a settlement on June 6 and this order by the
commission adopts that settlement.
Under the settlement, FMC/Astaris has agreed to a reduction by $5
million in the payments it would have otherwise received under the voluntary
load reduction agreement, which translates into savings for ratepayers. Idaho
Power also agreed to distribute $425,000 of its share of the load reduction
program’s savings to Idaho Power ratepayers through its yearly power cost
adjustment mechanism.
FMC/Astaris’ take-or-pay obligation to Idaho Power will be reduced
by $7.9 million. Idaho Power has agreed it will not seek $6.9 million of that in
recovery from ratepayers and include only $1 million for possible recovery
through the power cost adjustment mechanism. FMC/Astaris also agreed that it
would dismiss its state district court action against Idaho Power.
IDAHO PUBLIC UTILITIES COMMISSION Page 102002
ANNUAL REPORT
June 28, 2002
DEFERRAL GRANTED FOR INDUSTRIAL CUSTOMERS
Case No. IPC-E-02-2, Order No. 29065
Industrial customers of Idaho Power will be able to spread their portion
of the costs they owe to Idaho Power over a two-year period, according to an
order issued by the commission.
The Industrial Customers of Idaho Power petitioned the commission for
reconsideration of an order it issued on May 13 authorizing Idaho Power to
recover, over one year, $244.4 million of power supply expenses the utility
incurred during 2001-02. About $91.7 million of that is assessed to the indus-
trial class. The result to most industrial customers of Idaho Power would have
been about a 4.7 percent increase.
Industrial Customers of Idaho Power requested that the commission
authorize the industrial customers to spread costs over a five-year period. The
commission said it would not be prudent to spread costs over five years, but it
did allow industrial customers to spread their costs over two years – $87.5
million in the current power cost adjustment (PCA) year and $4.2 million over
the 2003-2004 PCA year. While that spreads the costs of one year’s power
supply expenses over two years for industrial customers, it does eliminate the
4.7 percent increase industrial customers would have paid this year.
On another matter, but included in the order, the commission said it will
allow Idaho Power to collect a carrying charge on money the utility invests in
the early stages of implementing commission-mandated conservation, or de-
mand side management (DSM), programs.
In its May 13 order, the commission approved a tariff rider on all Idaho
Power customers to fund DSM programs. In this order, the commission said
Idaho Power is entitled to recover interest to the extent DSM programs are
pre-funded by the utility in advance of funds being generated by the tariff rider.
The company requested a 6 percent carrying charge. The commission granted
4 percent, based on the interest rate currently paid on customer deposits.
August 27, 2002
INTERCONNECTION TARIFF OK’D FOR SMALL GENERATORS
Case No. IPC-E-01-38, Order No. 29092
Idaho Power customers who generate their own power should have an
easier time interconnecting with Idaho Power’s electricity grid as a result of an
updated process approved by the Idaho Public Utilities Commission.
Idaho Power proposed the updated procedure, which requires custom-
ers who generate their own power through means such as small wind or solar
systems to pay for the costs of interconnection and agree to periodic inspec-
tions to ensure the safety and reliability of the generators.
The purpose of the changes is to provide a standard tariff for small,
independent generators (called non-utility generators), which would enable a
safe, economic and reliable interconnection with Idaho Power’s electric grid.
2002
ANNUAL REPORTPage 11 IDAHO PUBLIC UTILITIES COMMISSION
The tariff is also to ensure that Idaho Power’s other customers do not subsidize
the costs associated with non-utility generation.
Idaho Power had originally requested that small generators pay for an
annual independent inspection of the generation facilities, but the Idaho Rural
Council and the Renewable Energy Advocates objected, maintaining that after
an initial inspection, repeated inspections should not be required unless major
modifications are made to the projects.
The commission ruled that small-generation projects – 25 kilowatts or
fewer – be inspected only once every three years if the projects use intercon-
nection equipment that meets nationally recognized standards and are approved
by Idaho Power in advance. Renewed certification will be required if material
modifications or additions are made. Projects larger than 25 kW would require
annual inspection.
The commission also ruled that interconnection costs should be borne
by the generator, not by the company and its ratepayers.
The commission cautioned Idaho Power Co. against making intercon-
nection too difficult. “We put the company on notice that should it abuse its
discretion in interconnect matters and thwart the development of non-utility
generation, the commission will entertain a complaint and revisit this issue.”
August 29, 2002
COMMISSION CLOSES GARNET CASE
Case No. IPC-E-01-42, Order No. 29085
The Idaho Public Utilities Commission closed its case on Idaho Power’s
petition to enter into a contract to buy power from the proposed Garnet power
plant project near Middleton. Commissioners made clear that its decision does
not mean the commission either endorses or opposes the Garnet project.
“This decision is no reflection on how the commission views the
project,” said Commissioner Marsha Smith. “This is merely a procedural
decision.”
Idaho Power filed a motion with the commission to vacate hearings
about whether Idaho Power should be allowed to enter into contracts to buy
power from the Garnet project because IDACORP, Garnet’s corporate parent,
and Garnet Energy LLC have been unable to obtain the financing necessary to
construct the proposed 250-megwatt natural gas plant. Idaho Power asked that
the matter be continued for at least 120 days to allow IDACORP and Garnet to
find a creditworthy partner or make other financing arrangements.
A competing motion filed by Citizens for Responsible Land Use and
Idaho Rural Council asked that the case be dismissed without prejudice.
Commissioners said if IDACORP and Garnet are successful in finding financing
for the project, it might open a new case with the commission.
The commission also ordered the company to file a report within 90
days on the progress of possible financing for Garnet. If financing has not been
secured, the company must include in the report alternatives for meeting the
IDAHO PUBLIC UTILITIES COMMISSION Page 122002
ANNUAL REPORT
expected 350-megawatt energy shortfall the company anticipates will occur by
mid-2005.
August 30, 2002
IDAHO POWER’S ‘LOST REVENUE’ REQUEST DENIED
Case No. IPC-E-01-34, Order No. 29103
The Idaho Public Utilities Commission upheld its earlier denial of Idaho
Power’s request to collect an additional $12 million from its customers to
recover potential lost revenue as the result of a load reduction program with
irrigation customers last summer. Idaho Power is appealing the commission’s
decision to the state Supreme Court.
Earlier this year, the commission allowed Idaho Power to recover from
customers the direct costs of the program, nearly $74 million. But, in an order
issued April 15, the commission rejected the company’s request to collect
another $12 million in “lost revenue” – the amount, including interest, the
company believes it might have received from the sale of power to irrigation
customers had the program not been in operation. This order responds to
Idaho Power’s request for reconsideration.
The commission said the load reduction program was the prudent, if not
the required, action to take in response to last year’s crisis and that financial
incentives to enact the program, such as recovery of lost revenue, were not
needed.
“To charge ratepayers for lost revenue is unreasonable in the context of
the crisis that existed,” the commission said. “Requiring ratepayers to pay for
energy they did not consume, but avoided, due to this program is also unrea-
sonable.”
When the commission adopted the program last year it told the com-
pany that the “direct costs and lost revenue impacts may (emphasis added) be
treated as a purchase power expense” that the company could later recover
from ratepayers.
“The commission finding did not guarantee that Idaho Power was
entitled to recovery of alleged reduced/lost revenue that resulted from this
program,” the commission said in its April order. “Rather, the commission
merely recognized that the issue of recovery would be considered.”
October 21, 2002
MORE TIME ALLOWED ON IDAHO TIME-OF-USE STUDY
Case No. IPC-E-02-12, Order No. 29133
The Idaho Public Utilities Commission granted a motion by Idaho
Power Co. and by commission staff to extend the comment deadline regarding
an Idaho Power Co. report that says installing time-of-use meters for the
utility’s residential customers is too costly for the company and does not pro-
vide substantial benefit for customers. The comment deadline was moved to
Dec. 6, 2002.
2002
ANNUAL REPORTPage 13 IDAHO PUBLIC UTILITIES COMMISSION
Time-of-use meters let customers know how many kilowatts they have
consumed during peak and off-peak periods of the day. “Peak” periods are
those times when demand on an electrical system is at its highest. By monitoring
the amount of electricity consumed during certain hours of the day, customers
can better measure the benefits by shifting their high use to off-peak hours.
Some utilities offer customers a lower rate for shifting use to off-peak hours.
Earlier this year, the commission directed Idaho Power and its Energy
Efficiency Advisory Group to consider implementing a pilot time-of-use metering
program. The commission advised the company to “consider installing time-of-
use meters in new subdivisions and the feasibility of allowing existing customers
to voluntarily install time-of-use meters.” The cost to customers of the meters
and their installation would be spread over a number of years.
Idaho Power hired Christensen Associates to complete a study on the
feasibility of implementing a time-of-use program. The study concluded that a
mandatory time-of-use program would provide “very modest potential benefits”
to customers. A voluntary program produces somewhat higher consumer
benefits, the study said, but would result in net revenue losses to Idaho Power.
However, the study also said that a mandatory time-of-use program that
operates only during critical peak periods could result in annual customer
benefits of more than $1 million and has the potential of saving Idaho Power
about $12 million in costs to operate its peaking facilities during those critical
periods.
Costs to install the meters would be about $145 per customer or about
$47 million for all of Idaho Power’s residential customers. The incremental cost
of the time-of-use meter compared to the standard meter would result in an
increased charge to customers of about $1 a month, according to the
Christensen study. The study further points out that an automated meter reading
system that would allow customers to receive more timely information about
their energy use would cost about $72 million.
October 22, 2002
DEPOSIT REQUIREMENTS FOR IRRIGATORS MODIFIED
Case No. IPC-E-02-9, Order No. 29132
The conditions that will require irrigators to pay a deposit to Idaho
Power Co. and the way those deposits are calculated will change for the 2003
irrigation season. The Idaho Public Utilities Commission approved a request by
Idaho Power to revise its deposit requirements for the utility’s approximately
12,400 irrigation accounts.
The new rule requires a deposit from irrigation customers who get two
or more reminder notices. The former rule required a deposit from customers
with two or more late payments of $100 or more during a 12-month period.
The new rule allows customers 45 days instead of 30 to pay their bills without
incurring the requirement of a deposit in the following year.
IDAHO PUBLIC UTILITIES COMMISSION Page 142002
ANNUAL REPORT
The company is permitted to require deposits from customers with no
credit history, from customers with a history of late payments, from customers
for whom an order for relief has been entered under bankruptcy laws or for
whom a receiver has been appointed in a court proceeding.
The second change approved is to compute the deposits based on the
electrical characteristics of the customer’s pump and motor rather than the old
formula of basing the deposit on one-and-one-half times the customer’s previ-
ous year highest monthly billing. According to Idaho Power, past bills are not
always indicative of projected use for the next year because factors like crop
rotation and weather may play a part in determining electrical use during the
next growing season.
Idaho Power asserts that the proposed changes are revenue neutral for
the company, although some customers will pay more under the new formula
while others pay less.
Feb. 12, 2002
HULET CASE APPEALED TO STATE SUPREME COURT
Case No. IPC-E-01-25, Order Nos. 28860 and 28950
BOISE – Jay Hulet, an Owyhee County farmer, will appeal an Idaho
Public Utilities Commission ruling that affirms Idaho Power Company’s decision
to bar Mr. Hulet from participating in the company’s irrigation buy-back pro-
gram. The Supreme Court is expected to hear oral arguments in early 2003.
Idaho Power did not allow Mr. Hulet to participate in the program
because he did not submit a bid by the Feb. 28, 2001 deadline. Mr. Hulet
claims he did not submit a bid because he was told by company representatives
that irrigation customers with past due balances would not be allowed to bid.
Company representatives claimed they informed Mr. Hulet that bids from
irrigators with past arrearages would not be accepted, but that farmers could
bid as long as they agreed to bring their accounts current. In fact, the company
stated, 40 farmers with past due balances did submit bids. Of those, 36 were
accepted into the program after their accounts became current. Mr. Hulet
claims he was forced to transfer responsibility for his meters on his Murphy
farms to his son so that his son could submit a bid. He also contends that
because of false information he received from the company, he did not submit a
bid on his Oreana farm and, as a result, has suffered serious financial harm.
After the commission dismissed Mr. Hulet’s complaint, he petitioned for
reconsideration. The commission granted reconsideration to Mr. Hulet and an
evidentiary hearing was conducted on Jan. 15, 2002. Following that hearing,
the commission again ruled that Mr. Hulet’s complaint be dismissed. Mr. Hulet
has appealed that ruling to the Supreme Court.
2002
ANNUAL REPORTPage 15 IDAHO PUBLIC UTILITIES COMMISSION
Jan. 31, 2002
WIND POWER RATE APPROVED FOR AVISTA CUSTOMERS
Case No. AVU-E-01-16, Order No. 28948
As of Feb. 1, customers of Avista Utilities were able to buy power
generated by wind.
The Idaho Public Utilities Commission approved an optional wind
power rate for Avista customers who volunteer to buy wind power. The
wind power option is priced in blocks. Each $1 block of wind will equal
55kWh of energy.
Avista’ customers have two options. They can purchase wind
power in set monthly amounts like $2 or $3 each month. That amount would
be set and not linked to monthly use. These customers, the company states,
may view this payment as a contribution to support alternative energy
production.
The second option is that customers can calculate and buy a se-
lected percentage of wind-generated power to serve their average monthly
load. For example, a customer who wants to volunteer half his 1,100 kWh
average monthly load to be served by wind power would pay $10 per
month (10 blocks at 55 kWh block multiplied by $1) and buy 550 kWhs of
wind power. The wind power should be delivered to the company within
one year of when the customer purchased the energy.
Avista will contract with PacifiCorp Power Marketing to buy the
wind power. PPM is the sole purchaser of energy from the wind farm, which it
then markets to customers throughout the West. The project, developed by
FPL Energy, LLC, is said to be the largest single wind-powered renewable
energy development in the world.
The optional wind power charge is in addition to all other charges
contained in the customer’s regular rate. The company maintains it will not
earn money from the program. It will pay a premium of 1.8 cents per kWh
for the wind power. The approximate $150,000 in revenue it anticipates to
get from the program will be applied to program costs. The Idaho commis-
sion also made clear that all costs and benefits of the program be allocated
Number of Customers
= 104,951
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
Avista generates most 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 2001, the average Avista household used 11,106 kWh, almost a
5.2 percent decrease from the 11,719 kWh used during 2000. 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 162002
ANNUAL REPORT
only to those customers who volunteer to participate so that the program is not
subsidized by other customers. All customer classes can participate.
The commission accepted a recommendation by intervenors in the
case, including Idaho Rivers United and the Land and Water Fund of the
Rockies, that Avista Utilities file a yearly report with the commission detailing
program participation, the total number of kilowatt-hours generated and the
amount spent on marketing. The intervenors also expressed hope that Avista
will work toward acquiring renewable energy resources as part of the rate-base
passed on to all customers. Voluntary programs, they contended, are good for
a start, but are no substitute for integrating renewable energy into the base
energy supply.
In Idaho, Avista serves about 90,000 residential customers and 60,000
commercial customers from about Grangeville north to Sandpoint.
October 3, 2002
COMMISSION APPROVES CONTINUATION OF SURCHARGE
Case No. AVU-E-02-6, Order No. 290130
The Idaho Public Utilities Commission approved continuation of a 19.4
percent surcharge that allows Avista Utilities to recover costs the company
spent buying electricity on the wholesale market during the energy crisis of
2000-01.
The commission denied Avista’s request to increase the interest on the
remaining debt to 6 percent, opting to leave the current 4 percent in place.
Rates won’t increase from current levels with the extension of the
surcharge, which was implemented a year ago to recover $23.6 million of a
total $78 million in power supply expenses accumulated during a two-year
period when water supplies were low and prices on the wholesale electricity
market reached record levels.
Avista’s request continues the surcharge until Oct. 11, 2003, allowing
the company to recover another $23.6 million of the current $48 million bal-
ance.
Very low stream flow conditions through the end of 2001 produced a
shortfall in generation for the Spokane-based utility. That forced the utility into
the expensive wholesale market to buy electricity to meet demand for its
customers in Washington and northern Idaho.
At this time last year, the company asked for a 27-month surcharge
through 2003 to recover the debt incurred in 2000 and 2001. Instead, the
commission approved a 12-month surcharge of 19.4 percent and directed the
company to report back in a year on the status of the account at which time the
commission would consider continuing the surcharge another 12 months.
Commission staff conducted a public workshop in Sandpoint to explain
the company’s proposal to legislators and customers.
“Even though I don’t like the idea of surcharges going on, we know
2002
ANNUAL REPORTPage 17 IDAHO PUBLIC UTILITIES COMMISSION
why they’re there and we understand what happened in the marketplace,” said
Commission President Paul Kjellander. “We recognize the hardship this creates
for customers, but I also think we need to recognize that by going this route we
have granted what some people wanted by spreading these costs out over a
number of years.”
Commissioner Dennis Hansen said the power purchase decisions the
company made at the time were prudent. “At the time Avista locked into the
forward-looking prices, it looked like a very good decision,” Hansen said. “But
the circumstances changed greatly,” Hansen said, referring to the rapid decline in
wholesale prices. “It was a twist of fate and not of mismanagement,” he said.
The commission disallowed about $1.5 million Avista wanted included in
the power cost recovery. That included about $900,000 in capital costs from
the company’s generation plants at Kettle Falls, Devil’s Gap and Othello. Those
costs may be deferred for consideration in a future rate case. The remainder
denied, pending additional investigation, was about $579,000 in fuel costs for
the Coyote Springs plant.
Avista claimed recovery of the power supply expenses will improve the
company’s credit ratings, which are below investment grade. Improved ratings
can help the company refinance long-term debt on more reasonable terms.
To mitigate the increased power costs, Avista said it increased operation
of its thermal resources and aggressively pursued conservation and load curtail-
ment programs. However, the company said the costs associated with the
hydroelectric conditions, the cost of short-term power market purchases and
increased thermal fuel costs exceeded the benefits these measures provided.
September 26, 2002
PURPA FORMULA ADOPTED FOR AVISTA, OTHER UTILITIES
Case No. GNR-E-02-2, Order No. 29124
The Idaho Public Utilities Commission approved an updated formula for
determining the rates that regulated utilities must pay small power producers for
the power produced at plants that generate up to 10 megawatts of renewable
energy.
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. Some cogenerators, such
as J.R. Simplot Co., produce power as a byproduct of timber or potato pro-
cessing or other types of manufacturing. 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 May, the commission agreed to a request by current and potential
IDAHO PUBLIC UTILITIES COMMISSION Page 182002
ANNUAL REPORT
PURPA developers to extend the contract length of PURPA projects from five
to 20 years and increase the size of projects that can qualify for PURPA rates
from one megawatt to five megawatts. (One megawatt, or one million watts, is
enough energy to power about 750 homes.)
After the commission expanded both the size limit and contract length
for PURPA projects, Idaho Power Co., Avista Utilities and PacifiCorp
asked the commission to delay the signing of any new PURPA contracts until
the commission could examine whether the formula the commission used to
determine the rates utilities were required to pay PURPA developers were still
reasonable. The data used in the formula to determine the rate was, until this
order, based on 1995 data. The power companies alleged that the longer
contract lengths and increases in project size would lead to purchase prices for
the utilities that exceed their avoided cost.
The commission granted a petition for reconsideration filed by the
regulated utilities and agreed to examine the reasonableness of the 1995 rates.
Fuel costs are a substantial component of the avoided cost rate. In
establishing a fuel component for generators that don’t use fossil fuels – such as
wind, solar or anaerobic digesters – a starting fuel price is computed that
reflects the average of natural gas prices during the previous calendar year at
Sumas, Wash, a major trading hub for natural gas. To account for inflation, that
starting fuel price was then increased at a 6 percent rate over the life of the
contract. The new formula adopted by the commission today decreases that
annual escalation to 2.6 percent. There is also an adjustable component of
avoided cost rates that, on July 1 of each year, captures changes in natural gas
fuel costs.
“It is the commission’s belief that in issuing this order we are establish-
ing a platform for avoided cost pricing that is reasonable and will appropriately
reflect the avoided cost of each utility into the future,” the commissioners said.
Responding to a petition for reconsideration by J.R. Simplot Co. and
Earth Power Resources, Inc., the commission agreed to increase the size of
projects that would be eligible for PURPA rates from 5 megawatts to 10 MW.
The 5 MW limit would prevent many wind, geothermal and biomass projects
from qualifying, Simplot argued. More than 60 percent of Idaho Power’s
capacity from PURPA developers is provided by projects between 5 and 10
MW in size.
The commission agreed that allowing larger-sized projects, combined
with the new 20-year contract length, will make it more possible for PURPA
developers to recover their capital costs and that “a larger eligibility size will
encourage development of alternative energy projects.”
2002
ANNUAL REPORTPage 19 IDAHO PUBLIC UTILITIES COMMISSION
January 31, 2002
BPA CREDIT TO RESULT IN AVERAGE 44 PERCENT CUT
Case No. PAC-E-02-1, Order No. 28946
Residential customers of PacifiCorp-Utah Power will see an average
reduction in their power bills of 44 percent as the result of an agreement be-
tween the Bonneville Power Company and Utah Power approved by the Idaho
Public Utilities Commission.
The BPA credit, which goes into effect Feb. 1, also benefits small-
farm customers of PacificCorp, who will see their bills go down by an
average of 63 percent.
“This reduction to residential customers will be a huge benefit in
southeast Idaho where there are a lot of total electric homes,” said Commis-
sioner Dennis Hansen. “It will also be a tremendous relief for farmers.”
The BPA credit comes as a result of extensive negotiations between BPA
and state commissions from Idaho, Montana, Oregon and Washington.
The 1980 Northwest Power Act required that residential and
small-farm customers in the Northwest share in the benefits of the federal
hydroelectric projects located in the region.
PacifiCorp’s previous exchange agreement with BPA expired in
2001, but a new settlement negotiated by the state commissions and BPA is
substantially higher than historical levels.
“There were multiple negotiation sessions,” said Paul Kjellander,
president of the Idaho commission. “We are grateful that these benefits
could come at a time that offsets some of the increases we’ve seen,”
Kjellander said.
The commission expressed its appreciation to BPA “for its
acknowledgement that the benefits of the federal Columbia River power
system should be spread to all residents of the Pacific Northwest.”
Utah Power has also filed an application with the commission to recover
$38 million in power supply costs the company incurred during the last two
Number of Customers
= 56,434
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.
Utah Power relies more heavily on thermal generation facilities than
any other electric utility in Idaho.
In 2000, the average UP&L residential customer used 12,599 kWh
of electricity, a 3.6 percent decrease from the 13,069 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.
IDAHO PUBLIC UTILITIES COMMISSION Page 202002
ANNUAL REPORT
years. The company requests to recover the amount over two years, $27
million in the first year and $11 million during the second. That, along with a
proposal to adjust customer rates to bring them closer to the actual cost of
serving each customer class, is still under review by the commission. Hearings
will be conducted on those matters.
If the commission were to grant Utah Power recovery of the full
requested amount, bills would still average 8 percent lower than current
amounts, according to the company.
April 12, 2002
COST RECOVERY DOES NOT VIOLATE MERGER AGREEMENT
Case No. PAC-E-02-1, Order No. 28998
PacifiCorp’s application seeking recovery for costs the utility incurred
buying power on last year’s high-priced wholesale market is not a violation of a
two-year rate moratorium the commission imposed on the company before
approving its merger with ScottishPower in 1999, the commission ruled.
While this order said PacifiCorp is not violating the moratorium, com-
missioners stressed that the order does not mean PacifiCorp will be able to
pass any or all of those expenses to customers. That matter is yet to be decided
by the commission.
Before it approved the merger between PacifiCorp and
ScottishPower in 1999, the commission required the newly merged utility
to meet 46 merger conditions. The first two of those conditions were that
rates would not increase as a result of the merger and that ScottishPower
“shall not seek a general rate increase for its Idaho service territory effec-
tive prior to January 1, 2002.”
On Jan. 2, 2002, PacifiCorp filed an application with the commis-
sion seeking authority to recover about $38 million in extraordinary power
supply costs it incurred from Nov. 1, 2000, through Nov. 1, 2001.
Timothy Shurtz, a Firth resident and an intervenor in the PacifiCorp
cost recovery case, asked the commission for a clarification of the above
merger condition. Shurtz questioned whether PacifiCorp’s case to recover
power supply costs is “an attempt to avoid the moratorium agreed to in
inducing this commission to accept the merger then being considered.”
Shurtz petitioned the commission for a clarification of Merger Condition
No. 2.
The majority on the commission said PacifiCorp’s application does
not violate the merger condition because rates did not increase during the
two-year rate moratorium.
Commission President Paul Kjellander and Commissioner Marsha
Smith said PacifiCorp “did not seek any increase in rates to be effective before
2002, therefore the company has fulfilled that condition.” Further, the costs
PacifiCorp seeks to recover are not merger-related, the two commissioners
said, but are attributable to “extraordinarily high wholesale market prices
2002
ANNUAL REPORTPage 21 IDAHO PUBLIC UTILITIES COMMISSION
outside the control of the company.”
Commissioner Dennis Hansen dissented, saying that PacifiCorp’s
attempt to recover costs that were incurred during the rate moratorium
“undermines the benefits of this agreement to the ratepayers.”
“I believe ratepayers would not have supported the merger condition if
they had known that PacifiCorp could petition this commission for reimburse-
ment of costs incurred during the rate moratorium freeze,” Commissioner
Hansen said.
June 6, 2002
PACIFICORP ALLOWED SOME RECOVERY; BPA CREDIT
KEEPS RATE DOWN
Case No. PAC-E-02-1, Order No. 29034
PacifiCorp will be allowed to implement a two-year surcharge on
its southeast Idaho customers to recover about $22.7 million in power
supply expenses incurred from Nov. 1, 2000 through Oct. 31, 2001.
The total amount of power supply costs incurred by the company
attributable to its southeastern Idaho territory was originally $49 million.
However, $11 million of those costs were incurred before PacifiCorp’s
authorized period of deferral began on Nov. 1, 2000. In January of this year,
PacifiCorp applied for recovery of the remaining $38 million.
Settlement negotiations between PacifiCorp, commission staff, the
Idaho Irrigation Pumpers Association and Monsanto Company resulted in a
settlement of $25 million. “When viewing the company’s total power
purchases, the settlement represents a 50/50 sharing between customers and
the utility,” the commissioners said.
However, the actual surcharge will recover $22.7 million as the
result of the acceleration of a credit allowed customers when PacifiCorp
merged with ScottishPower in 1999. The last two years of the four-year
credit were accelerated to provide a benefit of $2.3 million to customers.
Accelerating the credit is not loss of the credit, commissioners emphasized,
but ensures customers will get the full value of the credit earlier.
Commissioner Dennis Hansen dissented on portions of the order
dealing with the confidential nature of the settlement discussions.
This order completes a case that was handled in two parts.
Last February, PacifiCorp’s residential and small-farm customers
received a credit from the Bonneville Power Administration that resulted
in decreases of about 44 percent to residential bills and 63 percent for small-
farm customers.
The second part of the case dealt with, among other issues, PacifiCorp’s
request to recover $38 million in power supply costs. The negotiated settle-
ment of a $22.7 million surcharge, combined with the BPA credit, has the net
effect of reducing average residential rates about 28.2 percent from customer
bills a year ago. Small-farm customers net a 28 percent decrease from a year
IDAHO PUBLIC UTILITIES COMMISSION Page 222002
ANNUAL REPORT
ago, including the BPA credit, and will get an additional 11 percent next year.
Large commercial customers net a 34 percent decrease from last year’s rates
while some customers in commercial and industrial classes will receive, at most,
a 4 percent increase.
The drought and the volatile energy market, combined with the
failure of one of the company’s major generation units at Hunter, Utah,
caused the company to be short on power supply. That forced the company
into the high-priced wholesale market to purchase power. After sharehold-
ers had borne $11 million of those costs, the company asked the commis-
sion to begin a deferral period. The deferred amount of about $38 million
was considered in this case.
PacifiCorp customers, unlike any others in the Northwest, actually
received some benefit as the result of last year’s drought and extremely high
wholesale market prices.
That same volatile market compelled BPA, also short on power, to
offer PacifiCorp a cash settlement instead of providing PacifiCorp the
power it was due from BPA. PacifiCorp’s quick response resulted in an
additional $11.5 million for PacifiCorp’s Idaho customers. No other Idaho
electric utility was able to secure this additional benefit for its customers
because the market prices for power fell and BPA withdrew the settlement
offers. “The settlement came about as a result of the very same market
conditions that were responsible for PacifiCorp’s unprecedented level of
purchased power expenses,” the commissioners said.
The commissioners cautioned PacifiCorp’s customers to not be-
come accustomed to the size of the BPA credit. “This exchange benefit is
temporary and customers would be wise to explore options” to reduce their
future use, the commissioners said. “In doing so, they will be prepared
when the BPA credit no longer includes the additional financial benefits
that resulted from the volatile wholesale market.”
While supporting the portion of the application that includes the
BPA credit, nearly all of the PacifiCorp customers attending public hear-
ings and workshops in Rigby and Preston opposed the power purchase
cost recovery portion of the company’s application.
In written comments and in oral testimony, many customers ex-
pressed the view that executives of the utility promised not to raise rates for
three to five years after the 1999 merger of PacifiCorp with ScottishPower.
At hearings, customers repeatedly referred to a cabin meeting with
PacifiCorp executives and elected officials during which utility officials allegedly
made significant promises regarding future treatment of expenses.
“However, because these promises from the cabin meeting were never
made known to the commission and placed in the merger case record, they
were not considered then, and we are legally unable to consider them now,” the
commissioners said. The commission, as a quasi-judicial body, must confine its
decisions to the record produced at hearings. “Failing to do so, we violate
2002
ANNUAL REPORTPage 23 IDAHO PUBLIC UTILITIES COMMISSION
procedural due process of law,” the commissioners said.
“While this commission can appreciate the anger of the company’s
customers, we are bound by previous orders and the evidence of record that
these decisions rested upon.”
The company could not have anticipated the unprecedented price
spike in the wholesale market in late 2000 through mid-2001, the commis-
sioners said. “Similar expenses were incurred by every utility in the West-
ern interconnection, both public and private, including Idaho Power Com-
pany and Avista Utilities.”
In his dissent, Commissioner Dennis Hansen said the negotiated
settlement is not specific enough about how much in costs are allocated to
the failure of the Hunter unit, nor does the settlement provide details on any
other costs that led to the agreed upon amount of $25 million.
“I cannot, in all honesty, determine that this settlement is in the
public interest when so very little information was provided to the commis-
sion regarding what constitutes the settlement,” Hansen said. “I believe this
settlement amount was taken out of the hands of the commission and I cannot
accept this proposal on blind faith.”
Hansen also stated that PacifiCorp could have done more to reduce
the deferred amount, such as interrupting service to its largest customer,
Monsanto Company.
In their majority opinion, Commission President Paul Kjellander and
Commissioner Marsha Smith said the settlement does not attempt to assign
blame or allocate a specific percentage of cost sharing for Hunter. “The
settlement provides a negotiated recovery figure and not a road map to
determine how the figure was determined,” the majority opinion stated.
“Settlement negotiations of parties, under commission procedural
rules are, by their very nature, confidential,” commissioners said.
Many who testified at the hearings criticized the negotiations that re-
sulted in the proposed settlement as a process that failed to provide an opportu-
nity for public participation. Even though the settlement was completed before
the public hearings, the commission reserved making judgment as to the reason-
ableness of the settlement until after the public hearings concluded.
Those parties involved in the settlement negotiations, including represen-
tatives for irrigators, Monsanto and commission staff, supported the final result.
One intervenor, Tim Shurtz, did not sign the stipulation.
Representatives of the Idaho Irrigation and Pumpers Association said, “The
agreed upon net recovery of approximately $22.7 million in excess power costs
is reasonable and appropriate given the risks of a less favorable result, the
Irrigators limited resources, and in light of other settlements reached in other
jurisdictions on this issue.”
Commissioners did agree with customers that the company failed to
provide adequate notice of its application, leaving some with little time to
prepare for hearings. Commissioners noted that the company did not comply
IDAHO PUBLIC UTILITIES COMMISSION Page 242002
ANNUAL REPORT
with a commission rule to provide each customer with individual notice through
bill stuffers or a comment page with the customer’s bill.
The final settlement also includes modifications to the revenue
requirement from irrigation customers that bring those customers closer to
their actual cost of service. Because the cost-of-service study came at the
same time as the BPA credit, irrigation rates will not increase even though
the revenue requirement from that class of customers is higher.
A “rate mitigation adjustment,” that is also part of the settlement,
reduced the impact of the power supply cost by spreading recovery over
two years.
October 25, 2002
IPUC UPHOLDS VIOLATION, BUT DECREASES PENALTY
Case No. PAC-E-02-1, Order No. 29136
The Idaho Public Utilities Commission unanimously upheld its earlier
finding that PacifiCorp violated a customer service rule by not providing cus-
tomer notice of a proposed change in rates. But the commission agreed with the
company that the penalty the commission affixed – a $20 per customer credit –
is excessive and contrary to state statute. Instead, the commission assessed a
civil penalty of $10,000 to be paid to the State of Idaho General Fund.
Rule 102 of the commission’s Utility Customer Information Rules
require gas, electric and water utilities to give each customer notice,
usually through a bill stuffer, when the utility applies to the commission for
a change in rates or charges. PacifiCorp contended the rule did not apply
because its January application to recover $38 million in power supply
costs was not a permanent rate increase, but only a temporary surcharge.
The company said it did issue press releases and took other steps to
notify customers once public hearings on PacifiCorp’s application were
scheduled in Rigby and Preston last May.
On June 7, the commission accepted a settlement that allowed the
company to recover $22.7 million of the original $38 million requested. The
commission also ordered the company to credit each of its 55,000 Idaho
customers $20 for failure to notify customers according to commission rules.
PacifiCorp filed a motion for reconsideration, contesting the applica-
bility of the rule and the amount of the customer credit. The commission granted
reconsideration and conducted a hearing in September. At that hearing,
PacifiCorp officials testified providing each customer notice is difficult because
multiple communications to customers are interpreted as multiple rate changes.
The commissioners disagreed. “Customers should not be kept uninformed
merely because a case is complex and difficult to describe and the notice may
be misunderstood,” the commissioners said. “It is the company’s responsibility
to craft a clear description of the filing so that customers can distinguish be-
tween what is proposed and what is approved.”
The company argued that the rule regarding customer notice is ambigu-
2002
ANNUAL REPORTPage 25 IDAHO PUBLIC UTILITIES COMMISSION
ous when it comes to cases that are not permanent rate increases or annual rate
tracker cases. The commission’s order responds by saying, “As a general
practice, we find that when a company perceives some definitional ambiguity or
a similarity to cases where notice is required, it should err on the side of provid-
ing notice.”
PacifiCorp further argued that because it issued press releases and
met with customer groups, there was significant public comment on its filing
and participation in the two public hearings. However, that still does not
justify lack of notice, commissioners said. “This commission will not
countenance an attempt by the company to establish a principle that it may
disregard commission rules if it can later demonstrate a lack of injury or
harm to the public.” Many customers complained, the commission said, of
not being given enough advance notice to prepare for the Rigby and Preston
hearings. And: “The overall tenor of written comments submitted in this
case instead, if anything, indicates that the public was confused as to what
was at issue.”
The commission agreed with the company that the $20 credit to each
customer, which would amount to about $1.1 million, was excessive when
compared to past penalties against utilities for similar violations.
Commission rules allow a $2,000 penalty for each rule violation. The
commission determined to assess a civil penalty of $2,000 for each month
from the time the company applied in January until public hearings in May,
or $10,000.
“While the company contends that the commission should regard the
company’s failure to provide Rule 102 notification notice as simply a good
faith mistake, it is troubling that the company appears to discount the value of
individual notice, and the value of getting information with the monthly bill,” the
commissioners said.
IDAHO PUBLIC UTILITIES COMMISSION Page 262002
ANNUAL REPORT