HomeMy WebLinkAboutelectric.pdfIPUC Annual Report 2010
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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
2009 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
391,759 Residential Customers/$0.0778
76,494 Commercial Customers/$0.0620
120 Industrial Customers/$0.0452
Avista Utilities
2009 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
104,609 Residential Customers/$0.0828
16,484 Commercial Customers/$0.0802
486 Industrial Customers/$0.0518
2009 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
PacifiCorp/Rocky Mountain Power
56,430 Residential Customers/$0.0827
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8,082 Commercial Customer/$0.0700
5,545 Industrial Customer/$0.0536
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Summary of major electric rate cases
Case Nos. IPCE1006,07 and 08 and 12.
May 28, 2010
Idaho Power rates decline slightly with four adjustments
Rates for Idaho Power Company customers will decrease an average 5.2 percent as the result of
four rate adjustments approved today by state regulators.
The commission approved the annual Power Cost Adjustment, an average 6.5 percent decrease,
and three smaller increases. The percentage of decrease will vary because the adjustments
don’t apply to all customer classes and vary in size according to customer class. For residential
customers, the PCA decrease is 3.2 percent and the overall rate decrease, after the increases in
the three other cases, is 1.4 percent. The adjustments are effective June 1.
Below is a summary of the four rate adjustments.
Power Cost Adjustment (6.5 percent decrease) – Every year on June 1, customers receive
either a one‐year surcharge or credit, depending on streamflows and market conditions from
the previous year, a forecast of the next year’s conditions and a true‐up of the previous year’s
forecast.
This year’s power supply costs not included in base rates are anticipated to be $42.2 million, far
less than 2009’s $188.9 million, resulting in a PCA reduction of $146.7 million. As the result of a
stipulated agreement reached with Idaho Power in January, $88.7 million of that PCA reduction
will be included in permanent base rates, thus avoiding an Idaho Power rate case this year. The
January agreement stipulates that Idaho Power base rates will not increase again until January
2012 at the earliest. The remaining $58 million of the PCA reduction goes directly to customers.
The impact on the PCA surcharge is a reduction from 1.4 cents per kWh to 0.31 cents per kWh.
The power cost surcharge covers expenses, not already included in base rates, which Idaho
Power incurs to provide energy to its customers. During low water years, Idaho Power must rely
on more expensive sources of power than that generated from its 17 hydroelectric plants.
Power supply expenses vary due to the always fluctuating prices for natural gas or changing
market prices for wholesale power, thus the need for a yearly adjustment to rates. None of the
money collected from the PCA surcharge can go to increase company earnings, but can be used
only to pay off power supply and related expenses.
Automated meter installation (0.41 percent increase) – Idaho Power may include $2.36 million
in base rates for the second year of a three‐year installation of automated meters throughout its
territory. The company is replacing its existing meters with advanced metering infrastructure
(AMI) that will eventually allow customers to monitor electric prices and adjust their use to take
advantage of lower price‐periods. Idaho Power submitted a cost estimate of $71 million for the
project and will absorb any costs above that. At the end of the second year, expenditures are at
$47.3 million.
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In early 2009, the commission directed Idaho Power to "move forward with all deliberate speed"
with installation. The meters were installed last year in the Boise area and are being installed
this year in Canyon and Payette counties and surrounding regions. During 2011, meters will be
installed in the Magic Valley, Pocatello and Salmon areas.
The advanced meters can be read from a remote location, negating the need for an Idaho Power
representative to access customer properties. They can provide the company and individual
customers with hourly meter readings and inform customers of current electric prices, allowing
them to manage their use and reduce their bills.
“As we did in 2009 … we continue to find that both present and future public convenience will
be served through the enhanced outage management and billing accuracy, as well as reduced
operating and maintenance expenses,” the commission said. Implementation of AMI “will
inevitably benefit customers and lower the pressure for increased rates,” the commission said.
Fixed Cost Adjustment (1.85 percent increase) – The commission is allowing the company to
recover about $6.3 million in under collected fixed costs from residential and commercial
customers.
The FCA was implemented in 2007 as a pilot program. The FCA allows Idaho Power to recover
the fixed costs (but not to exceed 3 percent) it loses when conservation programs result in lower
power sales. Without a mechanism like the FCA, there is a financial disincentive for utilities to
promote energy efficiency and conservation programs because they lose money when those
programs are successful. The FCA allows Idaho Power to recover its fixed costs as established in
the most recent rate case. If the company under collects its fixed costs, customers get a
surcharge. Conversely, if the company over collects fixed costs, customers receive a credit, as
they did in the first year of the program.
This year, Idaho Power reports it under collected $5.17 million in fixed costs from the residential
class and $1.16 million from the small‐business class. This was due largely to a 7.6 percent
increase in energy savings during 2009 and a 28 percent reduction on the company’s energy
demand during peak‐use periods.
The Idaho Conservation League submitted comments supporting the FCA, but said the
commission should require Idaho Power to “better articulate the benefits customers receive
from the FCA mechanism.”
The expansion of conservation programs since implementation of the FCA help keep rates lower
than they would otherwise be. Reducing demand on a utility’s generating system, particularly
during times of peak‐use, is less expensive per kilowatt‐hour than building new power plants to
meet demand. By enrolling in conservation programs, customers can benefit by using electricity
more efficiently, reducing consumption and bills. Even customers who don’t directly participate
benefit because the cost of the electricity saved system‐wide through these programs is about
half the cost of electricity generated by a new power plant.
The FCA will continue as a pilot program for two more years to allow for more data to
accumulate and to correct problems.
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Pension Funding (0.77 percent increase) – The commission is allowing Idaho Power to increase
rates by 0.77 percent to allow it to collect $5.4 million over 12 months to replenish its pension
plan. The company’s contributions to its pension plan have always been included in base rates.
However, since 2003, Idaho Power was not required to contribute to the pension plan because
the market value of the plan’s assets was more than enough to cover future obligations. Recent
market conditions and increasing pension obligations require Idaho Power to begin funding the
plan again. The commission said this year’s amount due may be recovered over 12 months, but
cautioned Idaho Power that recovery of this year’s expense does not ensure the same level of
benefit in future years.
The commission suggested Idaho Power consider alternative pension plans. “It is unreasonable
for Idaho Power’s customers to be solely responsible for large contributions to the company’s
defined pension plan. Many employers in recent years have replaced their defined benefit plans
with pension programs that place greater responsibility and investment risks on employees.
Idaho Power must similarly consider changes to its retirement plan and address shareholder and
employee liabilities in the assignment of pension plan investment risk. The commission will not
approve additional pension plan contributions from customers without evidence that Idaho
Power has carefully reviewed alternatives to reduce the burden placed on customers.”
The commission’s orders in all four cases are final. Interested parties may petition the
commission for reconsideration by no later than June 18. Petitions for reconsideration must set
forth specifically why the petitioner contends that the order is unreasonable, unlawful or
erroneous. Petitions should include a statement of the nature and quantity of evidence the
petitioner will offer if reconsideration is granted.
Case Nos. AVU‐E‐10‐01, AVU‐G‐10‐01
September 21, 2010
Commission adopts settlement of Avista rate case
The commission adopted a settlement to the Avista Utilities electric and gas rate cases that
increases electric rates an average 9.25 percent over three years and gas rates an average 2.6
percent over two years. The first year electric increase is 3.59 percent and the first year gas
increase is 1.9 percent, both effective Oct. 1.
The commission said the settlement “represents a reasonable compromise to the positions and
we find it in the public interest.”
“In particular, we note the Stipulation and Settlement represents a significant reduction in the
request revenue increase. More specifically, the first year increase in electric rates contained in
the Stipulation and Settlement is 3.59 percent rather than the 14 percent originally proposed by
Avista,” the commission said.
The commission said it recognized “that initial disputes among the parties were numerous and
significant. This case has generated many customer comments opposed to the rate increases
originally requested by the company.”
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Avista originally requested a $32.1 million increase in annual electric revenue and a $2.6 million
increase in annual gas revenue. The settlement approved by the commission gives the company
$21.2 million spread over three years in electric revenue and $1.85 million spread over two
years in gas revenue. Helping to offset the increase was a $17.5 million deferred state income
tax benefit.
The three‐year phased rate increase effective dates are as follows:
‐‐ Oct. 1, 2010 ‐‐ 3.6 percent electric and 1.9 percent gas.
‐‐ Oct. 1, 2011 – 3.9 percent electric and 0.72 percent gas.
‐‐ Oct. 1, 2012 – 1.74 percent electric and 0 percent gas.
Parties to the case which supported the settlement included Avista, commission staff, Idaho
Forest Group, Clearwater Paper Association, the Idaho Conservation League, the Snake River
Alliance and the Community Action Partnership Association of Idaho, the latter which represents
customers on low‐ and fixed‐incomes. The Idaho Community Action Network did not participate
in settlement discussions, but submitted comments opposing any rate increase. North Idaho
Energy Logs also intervened in the case but did not file comments.
The rate case settlement is the first of two rate adjustments proposed this year. The second is
the company’s annual Power Cost Adjustment, (PCA) which would increase rates for one year an
average 2.6 percent. The commission is expected to rule on that request in the next few days.
For a residential customer who uses the average residential consumption of 1,000 kWhs per
month, the rate effective Oct. 1 would increase a bill by about $3.50 per month from $80.90 to
$84.40. If the one‐year PCA is approved, an average residential bill would increase by another
$1.88 per month. The customer service charge for electric customers increases from $4.60 to $5
per month. The gas customer service charge of $4 per month does not increase. Avista originally
requested an increase to $6.75 per month for both customer service charges.
The adopted settlement ends a case that began last March.
The commission is well aware of the impact of rate increases in today’s economy, particularly on
customers with low and fixed incomes. “We do agree with those comments that Avista needs to
‘tighten its belt’ to reduce costs and improve its efficiencies,” the commission said. Avista and
other parties in the case need to be “diligent in finding efficiencies or instances where the
company’s costs may be unreasonable,” the commission said. The phased‐in rate increase and
tax credit help mitigate the impact of the increase given the current state of the economy.
“Understandably, most of the customers submitting comments oppose Avista’s initial double‐
digit rate increase,” the commission said. While the commission does all it can to find expense
reductions and other methods to mitigate the impact of rate increases, state law does not allow
the commission to outright reject rate increases. State statutes require that all regulated utility
rate requests be considered by the commission to determine whether the expenses the utility
seeks to recover through customer rates are needed to serve customers and if they are
prudently incurred. The commission may deny expense recovery if the utility fails to provide
evidence that adequately supports the new expenses as needed to serve customers and
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prudently incurred. All commission decisions can be appealed to the state Supreme Court by the
utility, intervenors or customers.
The settlement increases funding for low‐income weatherization from $465,000 to $700,000 per
year. The fund will permit more low‐income customers and senior citizens to weatherize their
homes resulting in lower energy bills. The settlement also provides $40,000 to Community
Action Partnership agencies for low‐income outreach and education programs about energy
conservation. Avista will conduct five energy conservation workshops for senior citizens in five
Idaho communities no later than Dec. 31, 2011.
When Avista filed the rate case in March, it said the increases are necessary because of
escalating power supply costs, increased costs to meet new federal requirements that ensure
reliability, and the need to replace aging infrastructure.
Power supply contracts that provide Avista customers with about 100 average megawatts,
about 10 percent of the company’s entire retail load, expire at the end of this year. The power
provided by these contracts is about 3 cents per kilowatt‐hour, which is well below the cost to
replace that power. Also included in this case were about $21 million in costs related to a
power purchase agreement with the owners of the Lancaster natural gas generating station
near Rathdrum. About 80 percent of Avista’s increase is attributable to the Lancaster
agreement, termination of the low‐cost power contracts and increased customer load.
Case No. AVU‐E‐10‐03
October 1, 2010
Avista PCA is 2.6 percent increase
Avista’s electric customers will pay an average 2.6 percent more for the company’s yearly Power
Cost Adjustment, which tracks the always changing costs of electric power supply. For an
electric customer who uses an average of 1,000 kWh per month, the increase is about $1.88 per
month.
Below‐normal hydro generation and costs associated with the Lancaster generating plant
resulted in more power supply expense than is already included in base rates resulting in
Avista’s one‐year 2.6 percent Power Cost Adjustment (PCA) surcharge.
The two major components of Avista customers’ electric bills are the base rate, which covers
primarily fixed costs that don’t change from year to year, and the PCA rate. The PCA increases or
decreases rates depending on conditions outside the company’s control that can dramatically
alter power supply expense. Those conditions include variations in hydroelectric generation
caused by lack of stream flows, unanticipated changes in fuel costs and changes in wholesale
market prices for energy.
During those years when power supply expenses are less than what is already covered in base
rates, customers receive a credit. During years when power supply expenses are greater than
included in base rates, customers get a surcharge. Both the surcharge and credit last for 12
months and then a new adjustment will be calculated to adapt to changing conditions and
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updated projections. The updated PCA is effective Oct. 1 of each year. Unlike a general rate
case, a PCA increase does not increase company earnings. The PCA surcharge is collected from
ratepayers, kept in a deferred account, and then passed directly to wholesale power and fuel
suppliers.
The PCA surcharge effective Oct. 1 increases from 0.34 cents per kWh to 0.53 cents per kWh.
Case No. AVU‐E‐10‐04, Order No. 32100
October 28, 2010
Change in BPA credit results in increase to Avista customers
The adjustment is the result of a settlement between the Bonneville Power Administration and
Avista regarding the size of a credit the BPA gives to residential and small‐farm customers of
investor‐owned utilities in four Northwest states. The commission has no role in determining
the size of the credit.
Effective Nov. 1, the credit is reduced from 0.289 cents per kWh to 0.147 cents per kWh. For a
residential customer whose electrical consumption is the company’s average, the result of the
reduced credit is about a $1.42 per month increase.
A 2007 federal court decision reallocated much of the credit to customers of publicly owned
utilities, after the court determined that customers of investor‐owned utilities, like Avista, have
been overpaid during the most recent years the credit had been in place. The settlement
reduces the credit to comply with that ruling and also to settle some outstanding accounts
Avista had with BPA.
BPA is a not‐for‐profit federal agency that markets power from 31 federal hydroelectric dams
and a nuclear plant in the Northwest. 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. Avista applies the benefits it receives, which usually fluctuate
annually, to customers as a credit on their monthly electric bill.
Case No. PAC‐E‐10‐07, Interlocutory Order No. 32151
December 27, 2010
Rocky Mountain residential customers get net 5.5 percent increase
Residential customers of Rocky Mountain Power will pay a net increase of about 5.5 percent in
electric rates effective January 1. For all customer classes combined, the average base rate
increase approved by the commission is 6.78 percent.
Rocky Mountain Power, serving 70,000 customers in eastern Idaho, filed last May with the
commission for an average 13.7 percent rate increase. In October, Rocky Mountain Power
lowered its request to 12.3 percent, seeking an additional $24.9 million in annual revenue. The
additional annual revenue requirement approved by the commission is $13.75 million.
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The commission adjusted the amount allowed in rates by reducing pension expanse and
eliminating wage increases which, the commission said, addresses some of the concerns of
customers and takes into account the economy in southeast Idaho. The commission also
reduced the company’s proposed investment it sought to include in rates for the Populus to
Terminal transmission line from eastern Idaho into northern Utah.
The commission conducted two public workshops, a three‐day technical hearing and five public
hearings during the six‐month investigation of the case and received hundreds of written
customer comments. The commission was pleased by the large turnout at the public workshops
and hearings where customers expressed concern about rate increases given the current state
of the economy and also about paying for wind and transmission projects they thought would
benefit other states and not Idaho. “Customers may rest assured that this commission will never
approve expenses for generation and transmission projects that do not benefit customers in
Idaho,’’ said Commissioner Marsha Smith, who chaired the hearings.
For residential customers, the average base rate increase is 6.8 percent. However, the
commission reduced customers’ Energy Efficiency Charge from 4.72 to 3.4 percent, resulting in a
net average increase for residential customers of about 5.5 percent.
Residential customers will actually pay less than the current rate for their first 700 kilowatt‐
hours of use in the summer months and their first 1,000 kWhs of use in the winter months. The
commission approved a two‐tiered rate structure that increases rates as consumption increases.
From May to October, standard residential customers will pay 9.58 cents per kWh for their first
700 kWh. The current May‐October rate is 10.4 cents. For use exceeding 700 kWhs during
summer, the new rate is 12.9 cents. From November through April, residential customers will
pay 7.33 cents per kWh for the first 1,000 kWhs. The current winter rate is 8 cents. For use
above 1,000 kWh, the rate is 9.9 cents.
The commission rejected a Rocky Mountain Power request to increase rates of residential
customers in the optional Time of Day program by 15.6 percent, while increasing standard
residential customer rates by 8 percent. Instead, the commission approved the same percentage
increase for all residential customers.
For the other major customer classes, the average increase with the company’s proposal in
parenthesis is as follows:
• General service (commercial) – 4.5 percent (9.7)
• General service (large power) – 7.4 percent ((13.3)
• Irrigation – 2.9 percent (7.6)
• Monsanto – 9.6 percent (18.2)
• Agrium – 9.4 percent (14.7)
The commission approved an upper limit of Return on Equity at 9.9 percent, less than the
company’s current ROE of 10.25 percent and its requested ROE of 10.6 percent. The utility is not
guaranteed an ROE, but an opportunity to earn a return of up to 9.9 percent on the investments
it makes to serve customers. Under its previous ROE of 10.25 percent, the company earned an
average 6 percent over the last 10 years.
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Addressing the continued needs of the low‐income sector in Rocky Mountain’s Idaho territory,
the commission increased the company’s annual funding level for low‐income weatherization
from $150,000 to $300,000.
A final order in this case will not be issued until late February. Issues related to the contract
between Rocky Mountain Power and its largest customer, Monsanto, will be further examined
over the next two months, with a technical hearing scheduled for Feb. 1. The final order will
determine what Monsanto should be paid for allowing Rocky Mountain to interrupt service
during certain times of the year.
Case No. PAC‐E‐10‐01, Order No. 31033
April 2, 2010
First ECAM will raise Rocky Mountain rates about 1.3 percent
The commission has accepted the first Energy Cost Adjustment Mechanism (ECAM) for
PacifiCorp, which does business as Rocky Mountain Power in eastern Idaho.
The mechanism allows the utility to recover power supply expense not already included in base
rates. Rates for residential users will increase by about 1.29 percent, effective April 1, or about
90 cents per month. Irrigation rates increase by 1.55 percent and commercial rates 1.34
percent.
The annual adjustment will better match customer rates with the actual cost of providing power
and should reduce the frequency of filings by the company for general rate increases.
The ECAM will be adjusted up or down every April 1. If net power costs are higher than those set
in the most recent general rate case, the company collects the difference through a one‐year
surcharge listed as a separate item on customer bills. If net power costs are lower, customers
receive a one‐year credit. In this filing, Rocky Mountain claimed that net power costs for the
latter half of 2009 were $2.2 million higher than what was collected in base rates. The
commission accepted $2 million of those expenses.
Power costs include expenses for coal, natural gas and electricity that Rocky Mountain buys on
the wholesale market. Revenue the company makes from sales of electricity or natural gas on
the market is credited to customers. During those years when there is a surcharge, all the
revenue collected from the surcharge must go toward paying power supply costs. ECAM
revenue cannot be used to increase company earnings. Power supply costs are placed in a
deferred account audited by the commission.
A greater portion of PacifiCorp’s generation now comes from natural gas. The utility also gets
about 30 percent of its generation from hydropower. Changing water conditions and volatility in
the natural gas markets can cause fluctuations that sometimes result in power supply expense
that is greater than that already included in base rates and sometimes in power supply expense
that is less than that included in base rates.
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The yearly ECAM should also decrease borrowing costs for the company. Rocky Mountain Power
is in a period of increased generation and transmission investment to meet customer demand.
Assurances to financial markets of timely recovery of expenses allows for financing at lower
interest rates, benefitting both the company and its customers.
To encourage the company to be prudent in its power supply purchase decisions, the ECAM
requires that shareholders pay 10 percent of the power supply expenses not already included in
rates.
Case No. PACE1003, Order No. 32023
July 6, 2010
PUC approves part of efficiency services rate request
State regulators have allowed Rocky Mountain Power to increase its “Customer Efficiency
Services Rate,” from 3.72 percent of customer bills to 4.72 percent effective July 1.
The company originally sought an increase to 5.85 percent of customer bills, but the commission
said there are some issues that need further examination before Rocky Mountain will be able to
recover all its expenses related to funding programs that reduce demand on the utility
generation system (often referred to as “demand‐side management” or DSM programs). The
efficiency services rate also funds programs that promote efficient use of electricity.
The issues that need further examination will be addressed during the course of Rocky
Mountain’s base rate case pending before the commission. In that case, likely to continue
through this year, Rocky Mountain is requesting an average 13.7 percent increase to base rates.
The Customer Efficiency Services Rate is a separate item from the base rate on customer bills.
The revenue collected from this rate must be directed only to investment in DSM and energy‐
efficiency programs and, unlike the base rate, cannot be used to increase company earnings.
The commission said it “strongly supports” and commends Rocky Mountain Power “for its
commitment to providing its customers with DSM and energy efficiency options.” When
customers are able to reduce demand on Rocky Mountain Power’s generation through the
irrigation load control or the Home Energy Efficiency Program, the need for the utility to build
new generation or buy more costly power from other sources is delayed or eliminated, resulting
in lower energy costs for both the company and its customers. “All customers benefit from
deferring the costs of (the company) having to acquire new supply‐side resources,” the
commission said.
Rocky Mountain invests about $5.2 million in seven conservation programs, but the programs
generated $17.1 million in customer benefits during 2009. Due in part to increased customer
participation in the southeast Idaho utility’s conservation programs, Rocky Mountain sought to
increase its yearly investment in the programs from $5.2 million to about $8.3 million. The
increase approved by the commission results in a yearly investment of about $6.7 million.
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The Idaho Conservation League and the Idaho Irrigation Pumpers Association said the expenses
related to the irrigation load control program should be moved to base rates because of the size
of the program. Even though the energy efficiency rate funds seven programs, about half the
cost of the programs is related to the irrigation program.
The Idaho Conservation League said the irrigation program “most closely resembles a supply‐
side resource” operating much like a generation plant with a quantifiable amount of energy that
can be dispatched as irrigators simultaneously reduce their consumption. Participation in the
irrigation load control program provided Rocky Mountain with 285 megawatts of generation
during 2009. One megawatt is one million watts, enough electricity to power about 650 average
homes.
Moving the cost of the irrigation load control program to base rates would free up more
revenue from the efficiency services rate to be directed to residential programs, the Idaho
Conservation League said.
Residential efforts include the Home Energy Efficiency program, which offers financial incentives
to customers to invest in energy‐efficient washing machines; refrigerators; water heaters;
dishwashers; lighting; cooling equipment and services; ceiling, wall and attic insulation; and
windows. The lighting savings program resulted in a four‐fold increase in lighting savings from
2008 to 2009. There is also a low‐income weatherization program and a refrigerator recycling
program, the latter resulting in 725 units recycled during 2009.
The Idaho Irrigation Pumpers Association said the costs of the irrigation load control program
should be shared by other customers in Rocky Mountain’s region rather than solely Idaho
customers because there is a system‐wide benefit to reduced demand on generation. The
irrigators said there should be no increase to the efficiency services rate. That could be
accomplished, they argued, by removing expenses related to the irrigation control program and
fund the remaining programs at the previously existing 4.72 percent level.
Rocky Mountain countered by saying the ability to recover its expenses for DSM and energy‐
efficiency programs removes a disincentive to invest in the programs because the resulting
energy reduction could render the company unable to recover its prudent expenses and earn a
rate or return.
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Other major electric cases
Case No. IPCE0930, Order No. 30978
January 14, 2010
Commission adopts rate moratorium agreement
The commission is accepting a settlement between Idaho Power Company and a number of
customer groups that places a moratorium on general rate case increases until January 2012
while, at the same time, giving the utility a better opportunity to earn its allowed rate of return.
Idaho Power was in the early stages of filing a rate case last fall that could have resulted in a
base rate increase of between 10 and 20 percent effective this June. Instead, the utility and
parties to the settlement negotiations reached an agreement that allows Idaho Power to use
some of the anticipated reduction customers will get in the Power Cost Adjustment (PCA)
surcharge this spring and to accelerate investment tax credits it receives to bolster its earnings.
The agreement is signed by representatives of irrigation customers, industrial and major
commercial customers and representatives of low‐income residential customers. “It is notable
that all of Idaho Power’s major customers and customer groups participated in the discussions
leading to the stipulation, and all determined it presented a better alternative to the likely
results of a rate case,” the commission said.
One of the participants, the Snake River Alliance, said “the revenue sharing, PCA sharing, and
rate case moratorium components of the settlement in this case serve the company and its
customers as well as possible in our current economic times.”
The Community Action Partnership Association of Idaho (CAPAI), which represents low‐income
residential customers, said that “given the company’s recent substantial investments in
infrastructure … and given that the company had incurred relatively high costs during the test
year, CAPAI believes a general rate case would likely have resulted in an end‐result more costly
to Idaho Power ratepayers….”
An anticipated significant reduction in the annual Power Cost Adjustment made this a good year
for the agreement. Every year on June 1, Idaho Power customers get either a PCA surcharge or a
credit on their bills, largely depending on the previous year’s water levels and market
conditions. It is anticipated that this year’s PCA will be a significant decrease to customers,
though how much of a decrease won’t be known until after April 15. This agreement allows the
first $40 million of the anticipated PCA reduction to be shared equally between the customers
and the company. The PCA reduction between $40 million and $60 million will go directly to
customers as a rate reduction. The next block of up to $75 million will cover the company’s
permanent power supply expense account. Should the PCA reduction exceed the $60 million
and the amount applied to power supply expense, the next $10 million will be shared between
customers and company and any amount beyond that will go directly to reduce customers rates.
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The agreement also allows Idaho Power to accelerate its use of tax credits it receives on its
capital investments to shore up its earnings. The agreement allows the company to accelerate
up to $45 million of investment tax credits at $15 million a year for three years if its rate of
return falls below 9.5 percent. Idaho Power proposes to share earnings with customers through
rate reductions if the company’s ROE is higher than 10.5 percent. Idaho Power has not been
able to earn its authorized rate of return in either its Idaho or Oregon jurisdictions for the last
decade.
Improved earnings are important to maintain Idaho Power’s ability to finance ongoing plant
investments needed to serve customers, the commission said. “The company’s increased
financial stability benefits customers by enabling the company to delay rate cases and
potentially lower interest costs. It is beneficial to customers and to Idaho Power if the company
can enhance its ability to stabilize earnings in the near term, strengthening the company’s
position in the financial markets and enabling it to reduce the cost of borrowing funds for
operations or plant investment.”
The moratorium applies only to changes in base rates. It does not include possible increases or
decreases to the annual PCA or the annual Fixed Cost Adjustment. It also does not include
possible increases to energy efficiency riders or increases related to recovery of costs for
advanced metering infrastructure, pension expense or funding for low‐income weatherization.
Case No. IPCE1003, Order No. 30999
February 19, 2010
PUC plans workshop on competitive bidding guidelines
Staff from the commission will be conducting a public workshop regarding the possible creation
of commission‐established bidding guidelines for Idaho Power Company.
Independent power producers, as well as group representing industrial and irrigation customers,
last November filed a petition with the commission asking that it consider establishing
competitive bidding guidelines for the procurement of major generation projects by Idaho’s
three major electric utilities. However, Rocky Mountain Power, which operates in eastern Idaho,
and Avista Utilities in northern Idaho are already subject to guidelines established by other
states in which they operate. Because those utilities currently use those guidelines for projects
that serve Idaho, the original application was modified to include only Boise‐based Idaho Power
Company.
The groups petitioning the commission contend that Idaho Power is free to issue bid requests
that are “designed and administered completely without commission or other stakeholder
input.”
The petitioners pointed specifically to the $400 million, 330‐megawatt Langley Gulch natural gas
plant the commission approved last fall. The Idaho Power‐owned plant is under construction
near New Plymouth.
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In that case, Idaho Power initiated a bid process that was reviewed by a third party. Idaho Power
received five valid proposals that represented 13 alternative sources, including a proposal by the
company to build the plant itself. Idaho Power selected its own self‐build plan, claiming it will
have a revenue requirement impact of about $95 million less than the next competing proposal.
Some parties in the case argued the bid process was flawed, because, among other reasons, the
bid evaluator was hired by the company and there was not an independent scoring by the bid
evaluator. The parties also maintained that Idaho Power should have more seriously considered
a “build‐and‐transfer project.” which would allow a third party to build the plant and then turn it
over to Idaho Power to operate.
In approving the project, the commission acknowledged the bid process could have been more
transparent and that the “total universe of potential bidders was perhaps not realized.”
However, the commission said, “Based on the evidence presented, we cannot conclude that a
lower price and better project would have resulted” if the bid process had been better designed.
The commission said it was apparent that the competitors were “sophisticated bidders and that
the short list of projects were all competitive.”
As a result of the questions raised in the Langley Gulch case, the commission said it would open
a case to investigate bidding guidelines. “The actual and perceived flaws in the RFP (Request for
Proposals) process, we find, while not fatal to the company’s resource selection, clearly
demonstrate a need for a separate proceeding to consider RFP competitive bidding rules and
guideline,” the commission said.
Case No. PACE0907, Order No. 31021
March 23, 2010
PacifiCorp can assess slightly higher rate to wind producers
The commission is allowing PacifiCorp, which does business as Rocky Mountain Power in eastern
Idaho, to charge a higher wind integration rate to developers of small wind projects, but not as
large as requested.
Currently, PacifiCorp charges developers an integration rate of $5.10 per megawatt‐hour. Citing
increased costs to integrate wind into its overall generation portfolio, PacifiCorp requested a
rate of $9.96 per MWh. The commission granted $6.50 per MWh, which is the same as the
maximum amount allowed other utilities buying from small wind projects in Idaho, including
Avista Utilities and Idaho Power Company.
The wind integration rate is intended to capture from developers of small‐wind projects the cost
the utility incurs to integrate wind into its transmission grid. Included in those costs are
adjustments utilities make in their choice of generation options in order to accommodate wind.
Also, because wind generation is unpredictable, utilities must have back‐up generation in place
for those times when wind is not producing the output anticipated.
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The wind integration rate is discounted from the overall rate utilities must pay wind developers
who qualify under the provisions of the federal Public Utility Regulatory Policies Act of 1978
(PURPA). Under PURPA, qualifying generators of small‐power projects that generate up to 10
megawatts are paid a rate published by the commission. Wind integration costs are subtracted
from the published rate.
PacifiCorp claims an updated study shows that it costs the utility in the range of $9.96 to $11.85
per MWh to integrate wind into its system. However, the Portland‐based Renewable Northwest
Project, which promotes the development of renewable energy, recommended the increase be
denied because of flaws in the PacifiCorp study.
The commission noted there is no consensus on the methodology used to calculate wind
integration costs. This case is not the appropriate forum to select a methodology, the
commission said.
In setting the rate at $6.50, the commission acknowledged that PacifiCorp has added wind
resources since the original $5.10 rate was set and that “integration costs have likely increased.”
“We encourage PacifiCorp to continue to refine its wind integration cost analysis,” the
commission said. “We expect it to consider in its analysis and studies, the results of regional
efforts and studies.” PacifiCorp recently initiated a new integration study it expects to complete
in late summer.
Case No. IPC‐E‐09‐28, Order No. 31063
April 30, 2010
Decoupling mechanism will continue as “pilot” program
The commission is denying a petition by Idaho Power Company to make the pilot Fixed Cost
Adjustment (FCA) program permanent. The results of the program are “mixed” and there are
still too many unanswered questions, the commission said. However, the commission allowed
the program to continue for another two years as a pilot program.
“We are pleased with the company’s increased efficiency efforts,” the commission said.
“However, the issues and potential concerns with the FCA, as identified by the parties in this
case, support a conclusion that making the FCA permanent at this point is premature.”
Regulated utilities have a built‐in disincentive to invest in energy efficiency and conservation
programs because they lose revenue when consumption declines. To remove that disincentive,
the Fixed Cost Adjustment was implemented by the commission three years ago for Idaho
Power on a pilot basis. The adjustment is designed to ensure the company recovers its fixed
costs of serving customers regardless of the amount of energy conservation. Often referred to
as “decoupling,” the FCA decouples the link between energy efficiency and energy sales.
If the actual fixed costs recovered from customers by Idaho Power are less than the fixed costs
authorized in the most recent rate case, residential and small‐commercial customers get a
surcharge. If the company collects more in fixed costs than authorized by the commission,
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customers get a credit. After the program’s first year, customers received a credit (0.8 percent).
In the second year, there was a surcharge (.82 percent) and a surcharge (1.85 percent) is
proposed this year.
With implementation of the FCA, the commission expected Idaho Power to significantly increase
the size and availability of energy efficiency programs, which the commission said the company
has done.
There have been reductions in energy consumption, but commission staff and other groups who
intervened in the case argued that other variables such as economic conditions, high
unemployment, weather and adoption of building codes can all result in energy reduction
regardless of Idaho Power’s investment in energy conservation programs.
“Any approved decoupling mechanism should not reward the utility unduly for reductions in
consumption resulting from conditions the utility did not sponsor or create,” said the
Community Action Partnership Association of Idaho (CAPAI), which, along with commission staff
and the Idaho Conservation League, opposed making the program permanent. CAPAI also
expressed concern about impact on rates for customers on fixed and low incomes. While
commission staff and these groups did oppose making the program permanent, they did not
oppose allowing the program to continue on a pilot basis. AARP Idaho, however, said the FCA
should be discontinued entirely.
The commission agreed with comments from commission staff and the Idaho Conservation
League that disagreements remain about the accuracy of the amount of fixed cost identified for
recovery because a cost of service study that established that fixed cost is not recent and was
never approved by the commission. Some groups also argued that the FCA can send a conflicting
price signal to ratepayers when reduced energy consumption results in a rate increase as Idaho
Power proposed in two of the three years.
The Snake River Alliance and the Natural Resources Defense Council endorsed Idaho Power’s
petition to make the FCA permanent. The Snake River Alliance said the FCA has been an
“effective mechanism” to promote energy efficiency and that the nominal adjustments in rates
are “more than compensated by customers’ reduced energy use.”
The Natural Resources Defense Council noted the company’s “impressive growth in energy
efficiency and demand‐response programs.” In 2007, Idaho Power upped its investment in
conservation programs from $11.5 million to $15.66 million, resulting in an energy savings of
91,145 megawatt‐hours, a 29 percent increase from energy saved in 2006. In 2008, conservation
investment jumped from $15.66 million to $21.2 million and megawatt‐hours saved totaled
104,156, a 54 percent increase over 2007.
Idaho Power maintained the FCA is “performing as the parties and the commission intended
when it was implemented.” The company recognizes there are still questions to be answered,
but noted the FCA can continue to be adjusted even after it is made permanent. Not doing so
adds an element of uncertainty to the commission’s long‐running commitment to the FCA, the
company said.
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The commission acknowledged Idaho Power’s increased investment in efficiency programs, but
said that is not justification for making the program permanent until the company can show a
“demonstrable nexus” between the FCA and company investment in conservation programs.
“Evidence suggests that the FCA may have done little to spur Idaho Power’s increased
investment, as least for residential customers,” the commission said, noting that energy savings
were greater in customer classes that don’t have the FCA.
The commission ordered the program continue on a pilot basis for another two years, beginning
June 1, 2010, during which time further data can be developed and the issues raised by
commission staff and the parties addressed.
Case No. IPCE1004, Order No. 31080
May 17, 2010
IPC participation in NEEA approved; but funding to be reviewed
Idaho Power Company’s application for authority to fund its continued participation in the
Northwest Energy Efficiency Alliance has been approved. However, the commission made clear
it will require the company to demonstrate a “sufficient benefit to customers,” before it will
include NEEA funding in customer rates.
NEEA is a non‐profit organization working to accelerate market adoption of energy‐efficient
products, technologies and practices within homes, businesses and industries. It is funded by
Northwest utilities, the Bonneville Power Administration and the Energy Trust of Oregon.
NEEA is asking that Idaho Power pay 8.62 percent of its overall 2010‐14 budget. That totals
$16.5 million, which is $3.3 million per year over five years. Idaho Power’s share of NEEA
funding is included in the 4.75 percent energy efficiency rider paid by customers.
While the commission approved Idaho Power’s continued participation, the company will yet
need to show that customers benefitted sufficiently when the company files an annual report of
its conservation related program. “The commission expects rider funds to be used judiciously to
ensure customers receive tangible benefits from their payments to support energy efficiency
programs,” the commission said.
Idaho Power said NEEA helps fund these activities that benefit customers:
• a commercial new construction initiative that includes an integrated design lab in Boise;
• an energy management program that works with large commercial customers to
improve building operations and maintenance to save about 10 to 20 percent of electric
energy use;
• the development of energy building codes;
• the evaluation of Idaho Power’s energy efficiency programs to increase their cost
efficiency; and
• promotion of increased market adoption of energy efficiency programs in rural markets.
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The Idaho Conservation League and the Snake River Alliance supported Idaho Power’s continued
participation, although ICL expressed concern that participation could reduce funds available for
other efficiency programs that may have more immediate results. The Snake River Alliance said
it believes Idaho Power’s participation “resulted in energy efficiency gains that would not have
occurred absent NEEA’s role in Idaho.”
The Industrial Customers of Idaho Power opposed the application, maintaining an increase in
NEEA funding would result in a decrease of money available for other conservation programs.
The industrial customers said Idaho Power should spend rider funds on programs that provide
“easily measureable reductions in demand on Idaho Power’s system, not on increased funding
of NEEA’s broadly focused, regional market transformation programs.”
Case No. IPCE0824, Order No. 32002
June 16, 2010
Commission accepts Idaho Power green tag plan
The commission is accepting a business plan filed by Idaho Power Company spelling out how the
utility intends to treat the renewable energy credits (RECs) it earns from its renewable energy
sources. Customer groups have differed over whether the RECs, or “green tags,” should be sold
to benefit customers or “retired” to meet possible future renewable energy standards.
A Renewable Energy Credit is issued to each utility for every megawatt‐hour of electricity
generated by an eligible renewable energy resource. The RECs represent a currency that can be
traded on an active market to entities wishing to support renewable energy.
RECs are becoming more valuable as a growing number of states require their regulated utilities
to buy or generate a certain amount of power from renewable sources. Idaho Power’s 101‐
megawatt Elkhorn Wind project in Oregon and its 13MW Raft River geothermal project in south‐
central Idaho generated more than 320,000 MWh of RECs for Idaho Power in 2007 and 2008.
Last year, after reconsideration, the commission directed Idaho Power to sell its 2007 and 2008
RECs and use the approximate $1.7 million in proceeds to benefit ratepayers. Idaho Power
originally requested that it be allowed to retire, rather than sell, the RECs in anticipation of
federal or state renewable mandates. By retiring the RECs, Idaho Power said it could represent
to renewable energy certification programs and to customers that it is meeting customer
expectations for increased use of renewable energy.
Standards established by Green‐E Energy, the nation’s leading independent certification and
verification program for renewable energy, say that green tags sold by utilities from a renewable
project cannot be counted twice – by the utility doing the selling and the purchaser. Thus, when
Idaho Power sells its green tags, the company maintains it can no longer represent to customers
that customers are receiving the benefits of renewable energy projects that carry green tags.
According to Idaho Power, the Green‐E standards prohibit the utility from using visuals of its
wind or geothermal projects in charts, graphs or line art as part of the green resources delivered
to customers if the green tags that accompany those projects are sold.
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Idaho, unlike many other states, does not require its regulated utilities to generate a certain
amount of its power from renewable sources. However, retaining the green tags would allow
Idaho Power to satisfy any future state or federal laws imposing renewable portfolio standards,
the company claimed in its original filing.
After the commission granted Idaho Power’s request to retire the tags, the Industrial Customers
of Idaho Power petitioned for reconsideration, arguing the value associated with the RECs
belongs to the ratepayers and should be sold to benefit them. On the other side of the issue, the
Idaho Conservation League and the Renewable Northwest Project argued that the commission
allow the utility to retire the RECs.
After reconsideration, the commission directed the company to sell the RECs. But the order
allowing them to be sold also required the company to submit a business plan on how it intends
to treat REC sales in the future.
In April, Idaho Power submitted that plan which proposes that, in the short term, the RECs be
sold and the customers’ share of the proceeds be returned to customers in the annual Power
Cost Adjustment process. In the longer term, Idaho Power plans to continue acquiring and
holding contractual rights to own the RECs to meet any possible future renewable energy
standards.
Idaho Power states there is a “reasonable likelihood” that a federal renewable standard will be
passed by Congress that will require the company to obtain and retire RECs for compliance.
“However, because of current economic conditions and recent increases in costs and customer
rates, the basic philosophy of Idaho Power’s REC Management Plan is to sell its RECs in the near‐
term,” the company stated.
The Idaho Conservation League and the Renewable Northwest Project also opposed the
company’s plan for handling future RECs. They said the plan fails to consider the value of REC
retirement and that it should explain how Idaho Power intends to sell its RECs and still comply
with REC market guidelines.
Idaho Power customer Annie Black said the environmental benefits that should be accorded the
company and its customers are stripped away when the REC is sold, contrary to the state’s
energy policy requiring a diversified energy portfolio. Black requested a hearing to review the
implications of Idaho Power’s proposed plan or, if a hearing is denied, that the commission not
accept the plan.
The commission, denying requests for further hearings or that the plan not be accepted, noted
that accepting the plan as filed does not mean the commission endorses its specifics.
“As noted by the commenters in this case, the REC system is a complicated market that is still
developing and varies from state to state,” the commission said. “We expect Idaho Power to
remain fully engaged in REC market developments and to comply with proper procedures
regarding representations of renewable energy. We further direct the company to submit a
modified REC management plan when a change in state or federal energy policy warrants such
actions.”
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Case No. AVUE1002
June 4, 2010
Avista wants to expand net metering program
The commission has approved a request from Avista Utilities to let larger‐sized, customer‐
owned generation projects qualify for the company’s net metering program.
Currently, customers owning projects up to a capacity of 25 kilowatts are eligible to receive
credits for the generation they produce on solar, wind, biomass or hydropower projects. Avista
has received commission approval to increase the size of projects that can qualify for the net
metering rate to 100 kilowatts.
Customers who generate their own electricity can have their generation credited from their
monthly billings. Those who produce more than they consume, can have their excess kilowatt‐
hours applied to future billing periods to reduce their bills. At the end of the calendar year, any
unused kilowatt‐hour credits are granted to the company without compensation to the
customer‐generator.
Avista allows customers to enroll as net metering customers on a first‐come, first‐served basis
until the cumulative generating capacity of all customers equals 1.52 megawatts or about 0.1
percent of Avista’s retail peak demand.
Avista serves about 120,000 electric customers in northern Idaho.
Case No. IPCE0933, Order No. 32042
August 6, 2010
Commission accepts Idaho Power planning document
Idaho Power Company has fulfilled a requirement to file with state regulators every two years a
plan that sets forth how the company intends to serve the electric requirements of its
customers over the next 20 years. The plan, called an Integrated Resource Plan (IRP), says the
company plans to add about 3,000 megawatts of capacity over the next 20 years to meet
anticipated load growth.
The plan also spells out how the company plans to reduce summer peak load by 323 megawatts
by 2012, due largely to demand reduction programs aimed at commercial, industrial and
irrigation customers. Energy efficiency programs are forecast to reduce load by 127 average
megawatts by 2029, a 53 percent increase over measures included in Idaho Power’s 2006 IRP.
Acceptance of the plan by the commission does not necessarily mean the commission endorses
all the projects outlined in the plan. Circumstances change, which require updating the
document every two years.
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Idaho Power’s southern Idaho and eastern Oregon territory serves about 486,000 customers,
but those numbers are expected to increase to 680,000 at the end of the 20‐year plan in 2029.
Idaho Power anticipates that summertime peak‐load hours will increase by 53 megawatts over
the next 20 years and average load by 13 megawatts.
To accommodate the load growth over the next 10 years, Idaho Power continues to rely on
expanding its demand reduction programs. It also plans to add 540 megawatts of new
generation, including the 300‐MW Langley Gulch natural gas plant now under construction near
New Plymouth. The company plans to add 150 megawatts of wind generation and 40 MW of
geothermal generation. Completion of a proposed major 500‐kv transmission line from the
Boardman Substation near Boardman, Ore., to the Hemingway Substation near Melba will make
available another 425 MW of capacity to Idaho Power’s customers. An upgrade of the Shoshone
Falls hydroelectric facility will make another 20 MW available by 2015.
Looking beyond 10 years, the company plans another 1400 MW of generation from natural gas
plants and 500 MW from wind. The additional wind assumes completion of the Gateway West
Transmission Project, a joint transmission project proposed by Idaho Power and Rocky Mountain
Power that would pass through southern Wyoming and southern Idaho.
In 2008, 78 percent of Idaho Power’s electricity came from existing, low‐cost hydroelectric and
coal resources. These resources are the primary reason Idaho Power has historically had some
of the lowest retail electric rates in the nation. As Idaho Power adds new resources in the future
due to load growth and reduced generation from coal, the company asserts that power supply
expenses and rates are going to increase.
In fact, the Boardman coal plant in Oregon, from which Idaho Power gets about 64 megawatts,
is expected to cease operating within 10 years. Groups filing comments in the case, including the
Snake River Alliance and the Idaho Conservation League, said the company needs to be more
specific about how it intends to meet demand with the elimination or drastic curtailment of coal
generation. The commission agreed, asking Idaho Power to include more details in its next plan.
The Renewable Northwest Project, along with the Snake River Alliance, expressed concern that
Idaho Power may yet include coal in its long‐range planning if the cost of any future federal
carbon regulation is less than $30 per ton. The groups also oppose too much reliance on new
natural gas peaker plants given the price volatility of natural gas.
The parties to the case commended Idaho Power for its plans to increase wind and geothermal
development and its added reliance on conservation programs to reduce demand on the
company’s existing generation. The Snake River Alliance said the recent increase in the customer
rider to fund conservation programs ‐‐ to 4.75 percent – may not be enough to capture all the
potential energy conservation. The commission agreed the conservation programs are
necessary, but the issue of what is a fair and reasonable charge for customers to fund those
programs is “never black or white. For a regulator, there are considerations of equity and timing
and affordability. It is a pocketbook issue for many of the state’s unemployed and economically‐
challenged.”
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All the groups encouraged Idaho Power to pursue solar‐powered generation. The commission
said the recently announced Boise City solar project may provide Idaho Power an opportunity to
assess the merits of solar resources.
Case No. IPCE1023
October 22, 2010
Utility given more flexibility to negotiate with large customers
The commission has approved a request by Idaho Power Company to allow it to negotiate
contracts with new large industrial customers rather than having the new customers pay the
standard tariff rate.
Idaho Power claims it has received inquiries from as many as 75 potentially new large industrial
and irrigation customers. Due to generation and transmission constraints, Idaho Power said it
would not be able to serve the new customers if it cannot negotiate provisions that allow the
utility to adapt its transmission system to accommodate new load.
All Idaho Power industrial customers with a load between 1 and 25 megawatts are served under
a tariff – Schedule 19 – that that has the same rates and delivery requirements. Four industries
that have a load of 25 megawatts or more are classified as “special contract” customers. That
classification gives Idaho Power the price and delivery flexibility to accommodate the
requirements of these large customers without negatively impacting other customers. The four
special contract customers are Micron, the Idaho National Laboratory, JR Simplot Company and
Hoku Materials.
In this case, Idaho Power sought commission approval to lower the load requirement for
customers to qualify as special contract customers from the current 25 megawatts to 20
megawatts. The commission has granted that request and it becomes effective Jan. 1, 2011.
The commission said it recognizes that the ability of Idaho Power’s generation and transmission
system to serve new large load customers is constrained. “We find that the company’s proposal
will enable it to better manage the impacts of potential new large loads on its system,” the
commission said.
For example, a special contract would permit Idaho Power and the industrial customer to reach
an agreement to curtail power or exercise other options to the customer if Idaho Power is
unable to provide service. Further, a special contract could lessen the rate impact on other
customers by including a rate structure for contract customers that has a marginal cost
component for an initial period. The contract could also require the large customer to make
upfront contributions for new or upgraded distribution or transmission needed to serve the new
customer.
Because of constraints on its power supply and transmission, Idaho Power would not have been
able to serve Hoku Materials, Inc., a new polysilicon production facility in Pocatello, without a
special contract. Hoku requested 82 megawatts of year‐round capacity. The two entities last
year agreed on a four‐year seasonally‐shaped contract that requires Hoku to reduce its demand
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during the peak summer months through 2012, the year Idaho Power expects to have enough
power supply and transmission to serve Hoku at full capacity. During those peak months, Hoku
will reduce its demand by performing annual maintenance on its systems.
The agreement also allowed Idaho Power to charge Hoku a special rate rather than the standard
rate for the entire load, which would have likely placed upward pressure on all of Idaho Power’s
customer rates. Hoku is paying the costs for Idaho Power to build the transmission and
substation upgraded needed to enable delivery of energy to Hoku’s facilities.
PURPA‐related cases
In 1978, Congress passed the Public Utility Regulatory Policies Act (PURPA) to promote
the development of renewable energy technologies as alternatives to fossil fuels. PURPA
requires electric utilities to buy power generated by qualifying small‐power producers at
a rate that is set and posted by state commissions. The rate is called the avoided‐cost
rate because it is to be based on the cost the utility avoids by not having to generate the
power itself or buy it from other sources. In Idaho, the avoided‐cost rate is based on the
estimated cost a utility would incur in building a combined‐cycle natural gas power
plant. Currently, only qualifying projects 10 MW or smaller qualify for the posted rate.
The commission must ensure the avoided‐cost rate is reasonable for utility customers
because 100 percent of the price utilities pay to qualifying producers is included in
customer rates.
Case No. GNR‐E‐10‐04, Order No. 32131
December 6, 2010
Commission to examine renewable power issues
Idaho’s three major investor‐owned utilities are petitioning the commission to investigate a
number of issues related to small‐power projects that qualify for a rate published by the
commission. The utilities are also asking that the eligibility cap on the size of projects that
qualify for the posted rate be reduced from 10 average megawatts to 100 kilowatts while the
investigation is under way.
The commission set Dec. 17 as the deadline for parties who want to intervene in the case, is
taking public comments through Dec. 22 and is hearing oral arguments on Jan. 27. Several
parties, representing primarily wind developers, have already filed petitions to intervene.
The three utilities – Idaho Power Company, Avista Utilities and PacifiCorp – all contend that a
rapidly expanding number of wind projects is having a profound impact on customers and on
utility transmission systems. The utilities further contend that large‐scale wind farms are
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breaking up their projects into smaller 10‐MW increments to qualify for the published avoided‐
cost rate, which may be more attractive than rates for projects larger than 10 MW.
In its petition, the three utilities are claiming that the small‐power projects PURPA was originally
intended to encourage are now developed by sophisticated large‐scale wind farms that
aggregate several projects within a mile apart from each other to qualify for the avoided‐cost
rate. When combined, these projects can total up to 100 or 150 MW interconnecting at one
delivery point, the utilities claim. For example, Idaho Power claims it now has 208 MW of wind
generation and another 264 MW of approved wind contracts scheduled to be online by the end
of this year. The utility claims it could have 1,100 MW of wind generation on its system in the
near term, which exceeds the amount of power used in Idaho Power’s total system on the
lightest energy‐use days. The rapid expansion of these projects is causing a strain on utility
transmission systems, the utilities claim.
The commission denied a request of the utilities to lower the size limits of projects than can
qualify for the post rate within 14 days of its Nov. 5 application. However, the commission did
say that any decision it makes next year in regard to lowering the limit will become effective
Dec. 14, 2010.
Parties intervening in the case claim the utilities’ petition is not backed up by evidence and will
have an adverse impact on PURPA development in Idaho. “Once in place, such a drop in the
eligibility cap is likely to remain in place for many months, likely years,” said the Northwest and
Intermountain Power Producers Coalition. “The implications on the renewable energy industry
will be widespread and have impacts on the entire economy of Idaho.”
The J.R. Simplot Company said it “fears the investment climate in Idaho will be, and may have
already been, tainted from the perspective of sophisticated investors who undoubtedly have
many other more favorable jurisdictions in which they may invest their renewable energy
dollars.” The J.R. Simplot Company and the Milk Producers of Idaho, among others, asked that a
lowered eligibility cap apply only to wind projects and not other renewable projects, such as
anaerobic digester, small‐hydro and solar projects.
The commissions is seeking comment on three matters: 1) the advisability of reducing the
published avoided cost eligibility cap; 2) if the eligibility cap is reduced, the appropriateness of
exempting non‐wind projects from the reduced eligibility cap and 3) the consequences of
dividing larger wind projects into 10 average megawatt projects in order to qualify for the
published rate.
Case No. GNR‐E‐10‐01, Order No. 31025
March 18, 2010
Rates paid smallpower producers decline
The rates that regulated utilities pay small‐power producers have decreased significantly due to
declining natural gas prices, according to a new price forecast by the Northwest Power and
Conservation Council.
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Under the provisions of the federal Public Utility Regulatory Policies Act (PURPA), regulated
electric utilities are required to buy power from qualifying small‐power producers or co‐
generators, such as wind or anaerobic digester projects. The rate to be paid the developers of
projects 10 megawatts or smaller is determined by the commission and is called the “avoided
cost rate” because it is to be equal to the cost the electric utility avoids if it would have had to
generate the power itself or purchase it from another source.
One of the key factors the commission uses in determining the published avoided‐cost rate is a
long‐term natural gas forecast by the Northwest Power and Conservation Council. A change in
the forecast automatically triggers a recalculation of the published avoided cost rates.
Under new rates effective immediately, a qualifying PURPA project developer who signs a 20‐
year levelized contract this year would be paid $79.19. Under the previous rate, a developer
would have been paid $90.90 per MWh.
According to NPCC data, the price for natural gas at the Sumas trading hub in Washington state
including delivery averaged $7.68 per/MMBtu, but had dropped to $3.91 in 2009 and is
projected to be about $4.56 this year.
Case No. IPCE1002, Order No. 31034
April 5, 2010
Commission accepts agreement with anaerobic digester
The commission approved a contract between Idaho Power Company and Cargill, Inc., the
developer of an anaerobic digester near Hansen. The agreement is for 2.25 megawatts of
output from Cargill’s Bettencourt Dry Creek Biofactory.
The anaerobic digester has been producing electricity on a non‐firm basis since August of 2008.
This 10‐year agreement is for firm delivery.
Commission staff noted this agreement contains significantly higher delay penalties than past
PURPA contracts. The delay security is $45 per kW or about $101,250, compared to about $25
per kW in previous contracts.
Idaho Power maintains the higher penalty is needed because several PURPA projects have failed
to meet their scheduled operation date.
Although this project is already operating, commission staff believes Idaho Power included the
$45 per kW penalty partly because the company is seeking an endorsement of the higher
security requirement with the intent of including it in future contracts. The commission said
delay provisions should not be too much so as to be punitive, but should be high enough to be
an incentive for project owners to complete their projects on time. Further, the commission
said, the delay provisions mitigate any additional costs to the company and its customers when
the utility is forced to buy substitute power on the market due to a project not coming on line.
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Case No. IPCE1005
April 27, 2010
PUC approves Idaho Power agreement with smallhydro developer
The commission approved a 20‐year power purchase agreement between Idaho Power Co. and
the developer of a small hydro‐generation facility near Parma.
Riverside Investments LLC, based in Adrian, Ore., is the owner of the 450‐kilowatt Arena Drop
hydro project. The project is scheduled to be in operation by July 15.
Case No. IPCE0934, Order No. 31087
May 20, 2010
Contract with geothermal project is approved
The commission approved an Idaho Power Company sales agreement with the developer of
geothermal generation project 12 miles northwest of Vail, Oregon. The project is within Idaho
Power’s service territory.
The Neal Hot Springs Unit No. 1 is expected to produce about 22 megawatts of power by late
2012. The project is owned by USG Oregon LLC, a subsidiary of U.S. Geothermal based in Boise.
The agreement provides that Idaho Power will receive the rights to the renewable energy
credits now available or created during the 25‐year term of the agreement.
Beginning in 2012, the flat energy price, under the agreement, is $96 per megawatt hour. The
price escalates annually by 6 percent in the initial years and by 1.33 percent during the latter
years of the agreement. The approximate 25‐year levelized price is $117.65 per MWh.
Idaho Power asserts that while the price of energy under this agreement is higher than most
sales agreements, there are benefits that bring value to Idaho customers. Those include Idaho
Power’s right to the renewable energy credits, the utility’s ability to curtail energy output from
the project when needed, Idaho Power’s first right to ownership of possible future site
development and the right to extend the terms of the contract.
Because the projected output is more than 10 average megawatts, the project is too large to
qualify for posted PURPA rates. Instead, the proposed rates were negotiated between the
company and the project developer.
Initially, Idaho Power sought bids for a geothermal source, but received only three. Two of those
bids were later withdrawn and the third was too speculative, the company said. The company
then decided to actively pursue negotiations with developers of five potential geothermal sites,
including the Neal Hot Springs site.
The commission noted that a bid process is the preferred method for getting competitive
proposals for energy purchases. But when the bid process is not successful, Idaho Power is not
precluded from directly negotiating contract terms with a single provider. However, Idaho
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Power “always bears the burden” in demonstrating that a purchase agreement’s terms “are fair,
just and reasonable,” the commission said.
All payments Idaho Power makes for the purchase of energy from the site will be included in the
company’s annual Power Cost Adjustment process until the next rate case at which time costs
are included in base rates.
Case No. IPCE1016, 17, 18
July 6, 2010
Idaho Power agreements with anaerobic digester projects OK’d
The commission approved Idaho Power Company requests to enter into power sales
agreements with the developer of three Magic Valley anaerobic digester power projects.
The 15‐year contracts are all with a Middleton‐based developer. Two of the projects are in Twin
Falls County. They are the 4‐megawatt Rock Creek Dairy project near Filer and the 2‐megawatt
Swager Farms Dairy project near Buhl. The 2‐megawatt Double B Dairy project is near Murtaugh
in Cassia County.
All three of the projects contain purchase rates that on the May 24 date of their contract signing
had been replaced by lower rates approved by the commission on March 16. However, the
commission determined that the projects were entitled to be grandfathered and paid the higher
rate in place before March 16. An internal review process by Idaho Power delayed contract
signing until May 24 even though all the contract issues had been resolved before March 16.
For all three of the proposed projects, the rate in the first year is $75.65 per megawatt‐hour.
The rate gradually increases over the 15 years of the contracts to $128.31 per MWh. That rate is
adjusted for heavy‐ and light‐load seasons as well as heavy‐ and light‐load hours. The proposed
Rock Creek Dairy project intends to deliver 1,296 megawatt‐hours per month, while the Swager
Farms and Double B project are anticipating an output of 648 MWh per month.
Anaerobic digestion is a biological process that produces a gas principally composed of methane
and carbon dioxide otherwise known as biogas. These gases, produced from organic wastes such
as livestock manure and food processing waste, are converted into electric energy.
Case No. IPCE1019
September 17, 2010, Order No. 32068
Commission approves first solar PURPA project
The commission approved a sales agreement between Idaho Power Co. and Grand View Solar
PV One, the utility’s first PURPA agreement with a solar power project.
The project, 16 miles west of Mountain Home, is a qualifying facility under the provisions of
PURPA, the federal Public Utility Regulatory Policies Act of 1978.
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Idaho caps the size of projects that can qualify for the published avoided‐cost rate at 10 MW.
Even though the Grand View Solar project capacity is 20 megawatts, the project is not expected
to exceed 10 average megawatts on a monthly basis given the fact that solar power cannot be
generated around‐the‐clock. Should the project exceed 10 average megawatts, Idaho Power will
accept the energy but will not be required to pay for it.
The sales agreement is for 20 years with a scheduled online date of Jan. 1, 2011. The agreement
is “non‐levelized,” meaning the price for the electricity generated gradually increases through
the life of the contract. The rate is $77.77 per megawatt‐hour in 2011 escalating to $128.31 per
MWh in 2031. That rate is adjusted for heavy‐ and light‐load seasons as well as heavy‐ and light‐
load hours. The planned monthly output for the project varies from 1,326 megawatt‐hours in
January to 4,816 megawatt‐hours in July.
Idaho Power has a number of net metering agreements with customers who own small primarily
residential solar projects, but this project is the first solar sales agreement with a larger
provider.
The manager of the Grand View Solar PV One project is Robert Paul of Deseret Hot Springs, Calif.
Case No. PAC‐E‐10‐05, Order No. 32084
October 13, 2010
Agreement between PacifiCorp, east Idaho wind projects approved
The commission approved a sales agreement between PacifiCorp and the developer of two wind
projects near American Falls. PacifiCorp does business in eastern Idaho as Rocky Mountain
Power.
The two projects, called Power County Wind Park North and Power County Wind Park South,
will deliver up to 10 average megawatts per month. The scheduled online date is Dec. 31, 2011.
The developer is Boise‐based Windland, Inc.
Case No. IPCE1022, Order No. 32104
November 3, 2010
Idaho Power agreement with biomass project approved
The commission approved an energy sales agreement between Idaho Power Company and the
developers of a biomass power project at an Emmett sawmill.
The project, called Yellowstone Power, is a biomass‐fueled combined heat and power project to
be co‐located with the recently commissioned Emerald Forest Sawmill, which employs up to 47
workers in Gem County. Power is generated using steam created from the controlled burning of
the woody biomass fuel.
Idaho Power and Yellowstone Power agreed on a 15‐year contract under which the project
would generate an average 10 megawatts per month. Projects that generate 10 megawatts or
less qualify for a rate posted by the commission under the provisions of the federal Public Utility
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Regulatory Policies Act, or PURPA. At issue in this case was whether the project was far enough
along in development that it could be “grandfathered” under an older PURPA rate that expired
on March 15 and was replaced by a rate that is about 15 percent lower. Because the costs of
PURPA projects are included in customer rates, the commission must ensure that customers are
not paying an unreasonable rate for the power.
Because there was no written evidence of an agreement before the rates were lowered in
March, commission staff could not recommend approval of the agreement under the older,
higher rates. However, in approving the agreement, the commission, which operates separately
from commission staff, said, “There is no reason to question the representations of Idaho Power
and Yellowstone as to when contract negotiations of the parties occurred.” Both Idaho Power
and Yellowstone maintained an agreement was essentially in place before the rates that Idaho
Power must pay Yellowstone were lowered.
A key factor the commission uses in calculating the avoided‐cost rate is a long‐term natural gas
forecast issued by the Northwest Power and Conservation Council. A change in the forecast
automatically triggers a recalculation of the published avoided cost rates. In March, the NPPC
issued an updated forecast that resulted in a lower rate that the company must pay developers
because of declining natural gas prices.
However, projects that were under development at the time the rates were lowered can be
grandfathered under the older rate if: 1) the developer has executed a power sales agreement
before the new rate became effective and 2) the developer has filed a meritorious complaint
alleging the project was sufficiently mature and far enough along in the contracting process that
a contract would have been signed had not the utility delayed the process.
Idaho Power argued the agreement should be approved because it was engaged with the
developer in discussions throughout 2009. Yellowstone Power argued that the facts that the
purchase of property for the project was complete and that it had been issued a permit to
construct by the Idaho Department of Environmental Quality are evidence of the project’s
maturity.
While the commission approved the agreement based “on the totality of circumstances,”
commissioners said they were “troubled by the apparent lack of any written documentation”
that a power purchase agreement was materially complete. The commission said it expects
Idaho Power and other regulated utilities to document oral communications and to “assist the
commission in its gatekeeper role of assuring that utility customers are not being asked to pay
more than the company’s avoided cost,” in power purchase agreements.
The commission noted the cogeneration project will provide “steady, predictable generation for
Idaho Power around the clock.” The biomass project is a “valuable addition to help diversify
Idaho Power’s resource portfolio,” and will inject jobs and revenue into an Idaho county hit hard
economically over the last 10 years, the commission said.
The project developer is Dick Vinson of Thompson Falls, Montana.
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Case No. IPCE1024
November 26, 2010
Idaho Power’s first large PURPA project approved
The commission has approved an Idaho Power Company sales agreement with a 44‐turbine
wind project near American Falls in eastern Idaho.
The 80‐megawatt Rockland Wind Project is a PURPA project with a scheduled operation date of
Dec. 31, 2011. PURPA is the federal Public Utility Regulatory Policies Act passed by Congress
during the energy crisis of the late 1970s. The act requires electric utilities to offer to buy power
produced by small power producers or cogenerators who obtain Qualifying Facility (QF) status.
The proposed agreement has many unique characteristics because of its size. All Idaho Power
PURPA wind projects to date are 10 megawatts or smaller, which is as large as a project can be
for developers to be paid an “avoided cost” rate that is determined and published by the
commission. The avoided cost rate is to be equal to the cost the electric utility avoids if it would
have had to generate the power itself or purchase it from another source. However, projects
larger than 10 MW can still qualify as PURPA projects if the developer and the utility are able to
negotiate a cost that closely matches the utility’s avoided cost. Because customers ultimately
pay for the power generated by PURPA projects, it is not in the public interest for the
commission to approve sales agreements that result in customers paying more for electricity
that could have been generated or purchased elsewhere at lower cost.
The negotiated levelized energy price in the 25‐year agreement is $71.29 per megawatt‐hour,
lower than the published avoided cost rate of $75.88 for projects 10 MW or smaller. Blue
Ribbon Energy LLC, which develops PURPA projects smaller than 10 MW, did not oppose the
agreement, but noted that Rockland was able to accept a lower payment because of tax credits
and benefits it received. Blue Ribbon Energy said Idaho Power or any other utility should not be
allowed to treat this agreement “as establishing a precedent for rates.”
The commission praised Idaho Power and Rockland for negotiating an agreement “that we find
sets forth a creative solution to resource issues that have heretofore often resulted only in
impasse and the filing of complaints.”
Some of those issues resolved include not only price, but items such as delay and security
provisions, mechanical guarantees and the treatment of renewable energy credits or “green
tags,” created by the project.
The agreement contains financial damage and security provisions for the benefit of customers in
the event of the project’s default or failure to meet its completion date as well as mechanical
availability guarantees. The developer would retain the renewable energy credits (green tags)
for the first 10 years which will help offset the development cost. Idaho Power would retain the
renewable energy credits for the final 15 years when the utility may have to comply with federal
or state renewable portfolio standards.
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Case No. IPCE0925, Order No. 32136
December 13, 2010
Transmission agreement between IPC, wind developer OK’d
State regulators have approved a $2.17 million agreement between Idaho Power Company and
Idaho Winds LLC that would allow a wind project near Glenns Ferry to interconnect with Idaho
Power’s transmission system without requiring a larger, more costly upgrade to the system.
The 21‐megawatt Sawtooth Wind project six miles northwest of Glenns Ferry is scheduled to be
in operation by Dec. 31, 2012, but will require substantial upgrades to Idaho Power’s
transmission system. Construction of the upgrades is expected to be completed by Juny 22,
2011.
The agreement is that 25 percent of upgrade costs will be paid by Idaho Power and included in
customer base rates and 25 percent will be paid by Idaho Winds. The remaining 50 percent will
be advanced by Idaho Winds, but subject to refund by Idaho Power over 10 years if the project
meets its output requirements. That 50 percent of the upgrade cost will be included in customer
rates over time as refunds are made.
The agreement also includes “redispatch,” provisions included in agreements with other wind
projects in the same area. Those provisions allow Idaho Power to direct Sawtooth Wind to
forcibly reduce its generation output in the event of outages on specified transmission lines.
Those provisions prevent Idaho Power from having to make even more costly upgrades to its
transmission system.
Both Idaho Power and commission staff agreed that the chances of such outages during peak‐
use times on Idaho Power’s system are unlikely because wind projects are not expected to be
generating at or near capacity during extremely hot times of the year when transmission
congestion usually occurs. Idaho Power believes the need for redispatch provisions will be
relieved after 2015 if the proposed Gateway West transmission project is built.
Case No. IPCE1026, Order No. 32138
December 20, 2010
Utility agreement with anaerobic digester approved
State regulators have approved a sales agreement between Idaho Power Company and AgPower
Jerome LLC, a 4.5 megawatt anaerobic digester project to be built near Jerome.
The project, which includes three 1.6 MW turbines, is a Qualified Facility under the provisions of
the federal Public Utility Regulatory Policies Act (PURPA).
Project developers, based in Colorado, asked that the project be grandfathered under an older,
higher posted rate because the sales agreement was substantially complete before the avoided‐
cost rate was lowered by the commission on March 16. The agreement was not signed in time
because the parties disagreed over liquidated damages and security provisions. When AgPower
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agreed to drop its opposition to those provisions, Idaho Power did not object to the project
being grandfathered under the former avoided cost rate.
Under the agreement, AgPower will be paid about $80.05 per megawatt‐hour in the first year of
operation, with a project online date of Jan, 1. 2012. By the 20th year of the agreement, project
developers would be paid about $128.31 per MWh. That amount varies during heavy‐ and light‐
load seasons of the year and heavy‐ and light‐load hours of the day.
Case No IPCE1038, 39, 40, 41, 42, 43
December 28, 2010
Commission approves agreements with six wind projects
The commission accepted sales agreements between Idaho Power Company and a San Francisco
developer for six wind projects near Mountain Home. The developer is the same for all six
projects with Maurice Miller and Glenn Ikemoto listed as project managers.
All six wind farms – Cold Springs, Desert Meadow, Hammett Hill, Mainline, Ryegrass and Two
Ponds – qualify for the commission’s posted Avoided Cost Rate under the provisions of PURPA.
Each of the projects has a capacity of 23 megawatts, but because wind is intermittent, the
agreements call for delivery of 10 average megawatts per project per month to Idaho Power.
Should the projects exceed 10 average megawatts, Idaho Power may accept the energy but will
not pay for it.
While the commission adopted the sales agreements, it expressed concern about the
transmission capacity available on Idaho Power’s system at the single point of interconnection, a
230‐kilovolt line in Elmore County, which is also near two other projects – Bennett Creek and
Hot Springs – owned by the same developer. A system impact study was performed that
indicated the existing transmission system can accommodate output from the projects without
transmission network upgrades. However, when that study was completed it was for projects
with a nameplate capacity of 20 MW. Since the study was completed, the project evolved with
the developer’s turbine choice resulting in projects with a nameplate capacity of 23 MW.
Consequently, the commission is ordering the developer to request additional transmission
capacity and be responsible for all costs associated with the request.
All the agreements include a mechanical availability guarantee, a reduction in the price paid to
the developer to allow for integrating the wind into Idaho Power’s transmission system and a
wind forecasting cost assessed the developer. The parties also agreed to damages and security
provisions in the event the projects do not meet their operation date of Dec. 31, 2012.
The rate for these projects is a non‐levelized rate that increases through the 20‐year contract. In
2013, the rate for normal load hours during normal seasons of the year is $61.93 per megawatt‐
hour (6.19 cents per kWh), escalating to $121.76 per MWh in 2032. That rate varies to account
for heavy and light load hours of the day and heavy and light load seasons of the year.
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