HomeMy WebLinkAboutelectric.pdfIdaho Public Utilities Commission 2013
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Electrical Power in Idaho
Idaho residents consistently enjoy some of the least expensive electric service in the nation. According
to data compiled by the Energy Information Administration, Idaho ranked 49th of the 50 states and
District of Columbia in electricity rates during 2010. (See next page for state‐by‐state ranking.)
Idaho Power Company
2012 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
400,291 Residential Customers/$0.0855
77,437 Commercial Customers/$0.0634
112 Industrial Customers/$0.0457
Avista Utilities
2012 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
106,528 Residential Customers/$0.0883
16,727 Commercial Customers/$0.0850
468 Industrial Customers/$0.0533
2012 Average Number of Customers/Avg. Revenue/kwh
(Computed from data available in FERC Form 1 Annual Reports)
PacifiCorp/Rocky Mountain Power
57,891 Residential Customers/$0.1027
8,507 Commercial Customers/$0.0865
5,549 Industrial Customers/$0.0638
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Average Revenue by State
The information below is provided by the Energy Information Administration and reflects
average revenue by kilowatt‐hour by state in September 2013. While Idaho ranks 49th of 51 in
average revenue, its rate of increase from September 2012 to September 2013, ranks third at
15%, behind only Rhode Island (22%) and Louisiana (16%). The 5 states with the highest
average revenue are Hawaii, 32.24 cents per kWh; New York, 16.42 cents; Alaska, 16.22 cents;
California, 15.8 cents; and Connecticut, 15.71 cents. The 5 states with the lowest average
revenue are Washington, 6.99 cents; Wyoming, 7.62 cents; Idaho, 7.76 cents; West Virginia,
7.81 cents; and Illinois, 7.88 cents.
State Sept 2012 (cents per kWh) Sept 13(cents per kWh) Change
Alabama 9.49 9.6 1%
Alaska 15.46 16.22 5%
Arkansas 8.04 8.21 2%
Arizona 10.32 10.78 4%
California 15.77 15.8 0%
Colorado 9.8 10.26 5%
Connecticut 15.49 15.71 1%
D.C. 11.63 11.91 2%
Delaware 11.34 10.8 ‐5%
Florida 10.66 10.53 ‐1%
Georgia 9.71 10.01 3%
Hawaii 33.82 32.24 ‐5%
Iowa 8.03 8.58 7%
Idaho 6.72 7.76 15%
Illinois 8.48 7.88 ‐7%
Indiana 8.21 8.72 6%
Kansas 9.43 9.77 4%
Kentucky 7.49 7.89 5%
Louisiana 7.1 8.25 16%
Massachusetts 14.26 15.64 10%
Maryland 11.47 12.1 5%
Maine 11.68 11.46 ‐2%
Michigan 10.95 11.06 1%
Minnesota 9.37 9.84 5%
Missouri 8.73 9.28 6%
Mississippi 8.69 9.42 8%
Montana 8.34 8.66 4%
North Carolina 9.47 9.46 0%
North Dakota 8.32 8.81 6%
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State Sept 2012 (cents per kWh) Sept 13(cents per kWh) Change
Nebraska 9.02 9.48 5%
New Hampshire 14 13.94 0%
New Jersey 14.19 14.22 0%
New Mexico 9.19 9.39 2%
Nevada 9.69 9.91 2%
New York 16.34 16.42 0%
Ohio 9.32 9.25 ‐1%
Oklahoma 7.88 8.54 8%
Oregon 8.18 8.29 1%
Pennsylvania 9.76 9.85 1%
Rhode Island 12.86 15.63 22%
South Carolina 9.23 9.34 1%
South Dakota 8.9 9.3 4%
Tennessee 9.67 9.4 ‐3%
Texas 8.87 8.89 0%
Utah 8.34 8.73 5%
Virginia 9 9.27 3%
Vermont 13.69 14.41 5%
Washington 6.82 6.99 2%
Wisconsin 10.61 10.82 2%
West Virginia 8.2 7.81 ‐5%
Wyoming 7.25 7.62 5%
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Recent History of Base Rate Electric Cases
IDAHO POWER
Year Requested Granted
2004 14.5% 6.3%
2005* 6.3% 6.3% (not a base rate case, but
Increase granted due to tax
settlement and Bennett Mountain
plant)
2006 7.8% 3.2% (net was 14% decrease due to
expiration of tax adjustment.)
March 2008 10.35% 5.2%
June 2008 Though not a base rate case, rates increased an average 10.7% due to a one-year
PCA surcharge and 1.37% added to base rates for Danskin plant.
2009 10% 4% (tiered-rates implemented)
2010 No base rate cases. Rates decreased an average 5.2%, due primarily to a Power
Cost Adjustment decrease.
June 2011 Three surcharge adjustments result in average 3% reduction for customers.
2012 10% 4.2% (but net increase was 3.44%
due to reduction in energy efficiency
rider.)
2013 No base rate cases. But the annual Power Cost Adjustment was an average 15.3%
increase effective June 1, the fourth-highest PCA on record.
AVISTA UTILITIES
Year Requested Granted
2004 11% 1.9%
2008 16.5% 11.9% (Also included 4% PCA
increase)
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Year Requested Granted
2009 12.8% base rate increase with 5% PCA 5.7% (but with 4.2% PCA reduction,
reduction, for net 7.8% net increase was 1.5 percent)
2010 14% 9.25% (but spread over 3 years)
2011 3.7% 1.1% (but with decreases in PCA and
other rate components, the net is a
decrease of 2.4 percent)
2013 4.6% 1.9% (with stay-out provision for
next rate adjustment no sooner than
Jan. 1, 2015. On Oct. 1, 2013,
Customers got a 1.3% decrease due
to reduction in Energy Efficiency
Rider.
ROCKY MOUNTAIN POWER (PacifiCorp)
2005 5.1% 5.1% (This increase only applied to
irrigation and industrial customers,
there was no increase to residential.)
2007 10.3% 6.4%
2009 4% 3.1%
2011 13.7% 6.8% (but net increase to customers
was 5.5% because of 1.3% reduction
to Energy Efficiency Rider)
2013 -- A settlement prior to a formal case
filed increased rates by an
average 0.77% effective Jan. 1,
2014, with stay-out provision
to Jan. 1. 2016. Effective Oct. 1,
2013, customers received a 1.3%
reduction due to increase in BPA
credit.
Idaho Public Utilities Commission 2013
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Summary of major cases
Commission rejects most of Idaho Power’s
proposed changes to net metering tariff
Case generates hundreds of comments; packed hearings
Case No. IPC‐E‐12‐27, Order No. 32846
July 3, 2013
The commission denied nearly all of an
Idaho Power Company application to
change how customers who generate their
own power should be treated. The utility
proposed that residential and small
commercial customers who net meter by
generating their own power be moved into
new customer classes and be paid
differently for the energy they generate.
Even though the commission denied most
of Idaho Power’s application, the
commission said the company raises valid
issues that are more appropriately
addressed in a general rate case.
Idaho Power has about 386 net metering
customers who offset their electrical use by
connecting their own generating resources
(such as solar panels or wind turbines) to
the utility’s transmission grid.
Capacity cap
Idaho Power proposed to double the
current capacity limit on the amount of
energy that can be generated from net
metering
customers
from 2.9 MW
to 5.8 MW.
Current
generation is nearing the 2.9 MW limit. The
commission said a cap “may disrupt and
have a chilling effect” on net metering.
However, the commission directed the
company to provide an annual appraisal of
net metering status and its impact on the
reliability of the company’s system.
Pricing
Idaho Power proposed to increase the
monthly service charge for residential net
metering customers from $5 to $20.92 and
for small‐business net metering customers
from $5 to $22.49. To more fully reflect the
cost of service associated with net metering
customers’ use of Idaho Power’s
distribution system, the utility proposed to
establish a basic load capacity charge of
$1.48 per kW for residential net metering
customers and $1.37 per kW for small‐
business customers. It also proposed to
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decrease the retail energy rates net
metering customers pay. (For example, a
residential net metering consumer would
pay a non‐summer rate of 4.85 cents per
kWh compared to a standard residential
customer’s rate of 7.23 cents per kWh for
the first 800 kWh of use.)
The pricing changes are needed, Idaho
Power said, because net metering
customers are credited at the full retail rate
and are able to avoid paying distribution
expense as well as other fixed costs, such as
billing, that other retail customers pay. As a
result, those costs are passed on to other
customers.
Idaho Power said residential customers with
net metering systems differ from other
residential customers in that they produce
power, can offset their use of power, use
transmission and distribution facilities in a
different manner and require backup
services.
The commission agreed that net metering
customers “have some characteristics that
could justify moving them into a separate
rate class,” but is concerned that the
company’s proposal is inconsistent with
state energy policy, will discourage net
metering and encourage “rate‐gaming”
where large customers would install a small
solar system to qualify for lower retail
energy rates.
The commission also agreed that net
metering customers “do escape a portion of
the fixed costs and shift the cost burden to
other customers in their class.” However,
the commission said “more work needs to
be done to establish the correct customer
charge for those who net meter” and that
“dramatic changes such as those proposed
in this case ... should not be examined in
isolation but should be fully vetted in a
general rate proceeding.” Idaho Power
countered that this case presented a better
forum to focus on net metering issues than
would a general rate case addressing many
unrelated issues.
Excess net energy
For those net metering customers who
generate more power than they consume,
Idaho Power proposed to stop paying
customers and instead provide them with a
kilowatt‐hour credit that can be applied to
future billing periods. Those credits would
expire after the December billing period,
the company proposed, with the excess
applied against the annual Power Cost
Adjustment to benefit all customers.
The commission approved the proposal to
compensate net metering customers with a
kilowatt‐hour credit instead of a financial
credit or payment. “While we want to
encourage net metering, we believe a
financial credit or payment may incent
potential net metering customers to
overbuild their systems.” The net metering
tariff is designed for those customers who
wish to offset a portion of their load, not to
be wholesale power providers. There
already is a tariff schedule for small‐power
producers desiring to sell energy to the
company, the commission noted.
However, the commission denied the
company’s proposal to allow the credits to
expire at the end of December. The
commission said the credits should carry
forward to offset future net metering
customer bills for as long as the customer
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remains on the net metering service at the
same generating site.
The commission approved the company’s
proposal to modify the procedures net
metering customers use to interconnect to
Idaho Power’s distribution grid.
The case generated hundreds of comments
to the PUC and large attendance at
workshops and hearings. Many customers
said the changes proposed by Idaho Power
would make it difficult, if not impossible, for
net metering customers to recoup their
investment and that net metering
customers are such a small part of the
overall company’s revenue base that any
rate inequities are insignificant.
Idaho Power maintained that while the
current inequities in the pricing system are
not significant numerically, the current
provisions are not sustainable and that
delaying the changes until net metering
service expands will only increase the
inequities.
The commission said it appreciated the
extent of public participation in the case.
“The public input was especially thoughtful
and thorough and, based on the record
before us, we find that the public
overwhelmingly opposes the company’s
application,” the commission said.
“Moreover, we are concerned that the
company did not seek out or consider
customer input before proposing such
dramatic changes to the net metering
provisions,” the commission said. “We
applaud the company for bringing this case
and these issues to our attention. But we
advise the company that it would enhance
consideration of future program‐specific
changes if it informed and obtained
feedback from its customers and other
stakeholders before proposing them.”
Several parties intervened in the case
including the City of Boise, Idaho Clean
Energy Association, Idaho Conservation
League, Pioneer Power LLC, Powerworks
LLC and Snake River Alliance.
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Idaho Power granted CPCN for Bridger coal plant
upgrades, but preferred ratemaking denied
Case No. IPC‐E‐13‐16, Order No. 32929
December 1, 2013
Idaho Power is getting a certificate to allow
it to invest in emissions upgrades at a
Wyoming coal plant, but the Idaho Public
Utilities Commission declined a ratemaking
treatment that would have guaranteed the
utility recovery up to about $130 million of
the investment.
The preferred ratemaking treatment might
have made it more difficult for Idaho Power
to pull back from the investment at two
units of the Jim Bridger coal plant if even
more federal or state emission controls
make the upgrades no longer economical,
the commission said.
It is not inconceivable that during the
installation of the upgrades, “a tipping point
could be reached making them
uneconomic,” the commission said. “It is in
the best interest of the customers, the
company and the company’s shareholders
for Idaho Power to be continuously
analyzing the impact of changing
environmental regulations on its upgrade
project. As the project moves toward
completion over the next several years, we
direct Idaho Power to return to the
commission if viable alternatives to the
Bridger Units 3 and 4 become available.”
The utility must file quarterly reports
updating the commission on any changes to
environmental policy or regulations until
the upgrades are placed in service.
Environmental groups urged the
commission to deny the certificate and,
instead, require Idaho Power to find the
approximate 350 megawatts of generation
(about one‐fifth of the company’s total
baseload capacity) from renewable
resources and increased use of energy
efficiency programs.
But the commission said Bridger opponents
were not able to outline a viable alternative
that could “reasonably and timely replace
the value of energy and capacity that
Bridger provides.”
“The suggestion ... that renewable
resources and energy efficiency could
somehow replace Bridger’s ability to
reliably provide energy and capacity is
simply not realistic in the near‐term,” the
commission said. Indeed, baseload plants
like Bridger and the Langley Gulch natural
gas plant make wind and solar generation
more reliable by balancing their
intermittent generation, the commission
said. The baseload plants are also “critical
to the reliable operation of the high‐voltage
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transmission system in that they provide
voltage and frequency support.”
The commission emphasized that the
“public interest is paramount,” in
considering Idaho Power’s application.
Without the upgrades, which are being
required to meet Clean Air Act regional
haze rules, the coal units would be forced
to cease operation by December 2016 and
that is not in the public interest, the
commission said. “Cost‐effective
replacement resources that are
dispatchable and reliable year‐round do not
presently exist nor could they be brought
on line before the required dates.”
The commission acknowledged the public’s
concerns about unnecessarily extending the
life of the coal plant. (More than 200
written comments were received and 30
people testified at a standing‐room‐only
public hearing.) “The detrimental effects of
long‐term coal use on human health, the
climate, wildlife, land and water are well‐
documented. However, Idaho Power’s
analysis presented and (commission) staff’s
investigation confirmed that investment in
selective catalytic reduction controls is
presently the least‐cost, least‐risk
alternative to both reduce environmental
effects and allow reliable electric service to
continue.”
While the commission granted the
certificate, denial of binding ratemaking
treatment means the commission will be
able to review costs as the project
progresses. “Because of the uncertain
future of coal‐fired generation, we find it
unreasonable to prematurely commit
ratepayer dollars to support Idaho Power’s
investment,” the commission said. Approval
of such treatment would provide the
company with economic, social and political
assurance it seeks, while leaving ratepayers
to “bear the risk of environmental
uncertainties,” the commission said.
PacifiCorp, which operates as Rocky
Mountain Power in eastern Idaho, is the
majority owner of the Bridger plant and is
moving forward with installing the controls,
receiving a certificate in both Utah and
Wyoming in May of this year. The Idaho
portion of the estimated $130 million would
be amortized over several years, increasing
Idaho Power’s annual revenue requirement
by about $18.8 million.
Idaho Power said it considered other
options, including replacing the Bridger
output with natural gas‐fired generation.
The utility argued the Bridger plant has the
lowest dispatch cost of Idaho Power’s
thermal generation fleet.
Several parties intervened in the case
including the Industrial Customers of Idaho
Power (ICIP), which did not oppose the
certificate, but did oppose pre‐approved
ratemaking treatment. The Snake River
Alliance and the Idaho Conservation League
opposed both, maintaining that Idaho
Power understated the cost of likely
environmental compliance measures and
didn’t examine other alternatives. They
said the risks associated with investing in
coal generation have not been adequately
characterized or compared to risks
associated with other options.
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March 27, 2013
National utility group expresses support for
IPUC position in wind cases
State Supreme Court decision in Grouse Creek case expected in late 2013
The National Association of Regulatory
Utility Commissioners (NARUC) criticized a
decision by a federal agency to sue the
Idaho Public Utilities Commission over a
matter already being litigated in the state
Supreme Court.
“We are deeply disappointed in the Federal
Energy Regulatory Commission’s action in
this case. It is not at all clear why FERC
would take this drastic and unprecedented
step at this time, ‘’ said NARUC President
Philip Jones, also a commissioner in
Washington state.
NARUC is responding to a decision by FERC
to pursue a federal court case over the
Idaho commission’s denial of power
purchase agreements between Idaho Power
Company and the developers of the Grouse
Creek and Murphy Flats wind projects.
The Grouse Creek case was argued in
August before the Idaho Supreme Court
and a decision was expected late in the
year.
The Murphy Flats project owners did not
seek relief from the Idaho Commission’s
order denying the sales agreements until 14
months later, well beyond the Idaho
Commission’s statutory 21‐day window
during which parties can file petitions for
reconsideration and the 42‐day period
during which parties can appeal to the
Idaho Supreme Court.
“Historically FERC has allowed the parties in
such a dispute to resolve their differences
either through settlement or litigation
between the parties themselves,” Jones
said. “FERC’s decisions here seem to ignore
its own longstanding practice.”
FERC alleges the Idaho PUC is not complying
with the federal Public Utility Regulatory
Policies Act (PURPA) that requires utilities
to enter into sales agreements with small
renewable power developers at rates
determined by state commissions.
In November 2010, Idaho’s three largest
electric utilities filed a petition to the Idaho
commission asking that the size of the
projects that qualify for published rates be
lowered and the price the commission sets
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be investigated. The utilities said they were
buying power they did not need at prices
that were too high for their customers.
Idaho Power has 104 active PURPA
contracts generating 783 megawatts. Idaho
Power’s average total system load is about
1,800 MW, meaning about 43 percent is
PURPA generation. Meanwhile, PURPA
developers are requesting contracts for
another 188 MW and another 212 MW are
in dispute or litigation, according to Idaho
Power. The utility’s customers have paid
$1.2 billion for PURPA projects under
contract and the utility’s obligations for
future payments on existing contracts is
another $2.4 billion, Idaho Power claims.
In December 2010, the Idaho PUC lowered
the size cap under which projects could
qualify for the commission’s published
rates, from 10 average megawatts to 100
kilowatts. The obligation under PURPA for
utilities to buy from qualifying projects
larger than 100 kW remains, but the
projects must negotiate a rate with the
utility under a formula approved by the
commission. Much of the 576 MW of wind
energy Idaho Power buys is from wind
projects developed by large‐scale
developers who positioned several 10 MW
projects a mile apart (the FERC minimum)
to qualify for the commission’s published
rates.
In June 2011, the Idaho commission denied
approval of several wind projects, including
Murphy Flats and Grouse Creek. The
commission expressed concern about
customers being “forced to pay for
resources at an inflated rate and,
potentially, before the energy is actually
needed by the utility to serve its
customers.”
In an earlier FERC order stating its intent to
pursue legal action against the Idaho PUC in
the Murphy Flats case, FERC Commissioner
Tony Clark dissented, writing, “More
broadly, while PURPA was designed as a
foot in the door for emerging renewable
resources and small generators, I
sympathize with concerns that PURPA is
increasingly being used as a cudgel that
would force consumers to bear undue
burdens. ... (FERC) has now put itself in an
awkward position. It will invoke the power
of the federal government to proactively
champion a private interest that may
contradict the best interests of the
consumers of a state.”
NARUC’s Jones said the states and the
federal government have been able to work
out their disagreements without court
action. “For the better part of the last ten
years, FERC and the states have worked
well on several issues ... Given the
challenges the utility sector is facing, FERC
and the states should be working as
cooperatively as possible. We understand
there will be times when we disagree, but it
is not at all apparent what FERC intends to
achieve by taking a single state to federal
court, particularly when other options are
available.”
The proposed Grouse Creek agreements
were two 10 aMW projects near Lynn, Utah.
The cost of the contract was $230 million
over 20 years. The three 10 aMW Murphy
Flats projects in Owyhee County were for
$299 million over 20 years.
Idaho Public Utilities Commission 2013
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Grouse Creek Wind case timeline
On November 5, 2010, Idaho Power, Avista and Rocky Mountain Power asked the PUC to
investigate issues related to small‐power (primarily wind) projects that qualify for the
commission’s published rates. The utilities asked that the cap on the size of projects that qualify
for the published rate be reduced from 10 average megawatts to 100 kilowatts. The utilities said
a rapidly expanding number of wind projects were having a profound price impact on customers
and transmission systems. The utilities claimed the small‐power projects PURPA was originally
intended to encourage are now developed by sophisticated large‐scale wind farms that break
down several projects in order to fall under the 10 aMW limit and qualify for the more attractive
published (or avoided‐cost) rate.
On December 3, 2010, the commission denied the utilities’ request to lower the size limits of
projects that can qualify for the published rate pending further investigation. However, the
commission did say that any decision it makes in regard to lowering the limit would become
effective December 14, 2010.
On December 28, 2010, Idaho Power Company and Grouse Creek executed sales agreements for
two 10 average‐megawatt projects near Lynn, Utah. The projects were to have been paid the
Commission’s published rate effective before December 14, 2010.
On February 7, 2011, the Commission reduced the size of wind and solar projects that can
qualify for published rates from 10 aMW to 100 kW. The commission said it is not its intent to
push small wind and solar QFs out of the market. However, the Commission said federal rules
regulating PURPA development insist that rates for purchases from QFs be “just and reasonable
to ratepayers and in the public interest – not in the interest of the QFs.”
On June 8, 2011, the Idaho Commission determined to leave the eligibility cap under which wind
and solar projects can qualify for commission published rates at 100 kilowatts. As a result,
developers of 12 Idaho Power Company wind projects and five Rocky Mountain Power projects
whose contracts were executed after the Dec. 14 deadline will not be eligible for published
rates. However, the wind projects could still be developed under a rate negotiated between the
project developers and the utilities. Ten Idaho Power wind projects submitted just before the
deadline have already been approved by the commission. Continuing to allow wind projects
larger than 100 kW to be paid the published rate does not benefit ratepayers, the commission
said. “If we allow the current trend to continue, customers may be forced to pay for resources at
an inflated rate and, potentially, before the energy is actually needed by the utility to serve its
customers,” the commission said. “This is clearly not in the public interest.”
On July 27, 2011, the Commission denied Petitions for Reconsideration from 14 wind projects,
including the Grouse Creek projects.
On September 7, 2011, Grouse Creek appealed to the Idaho Supreme Court.
On October 4, 2011, the Federal Energy Regulatory Commission (FERC) issued a Declaratory
Order in a similarly situated case (the Cedar Creek projects) that said the PUC’s decision not to
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approve the Cedar Creek projects was inconsistent with PURPA, but FERC declined to pursue an
enforcement action against the PUC. The Cedar Creek and Grouse Creek projects were
remanded to the PUC for further discussion. On December 2011, the PUC approved a settlement
of the Cedar Creek projects proposed by the parties.
On September 7, 2012, on remand, the PUC affirmed its decision disapproving the Grouse Creek
agreements. By their very terms, the Agreements were not effective until December 28, 2010.
Grouse Creek changed the configuration of the projects numerous times and did not agree to
standard contract terms and negotiations until December 9. On December 14, Idaho Power
asked Grouse Creek to provide missing information necessary to complete the agreement. The
projects failed to name the transmission entity (BPA or PacifiCorp) to transmit the energy and
failed to provide a legal description of the projects’ locations. Grouse Creek signed the
agreements on Dec. 20. Idaho Power reviewed and signed on Dec. 28. The agreements were
filed with the Commission on Dec. 29, 2010.
On Oct. 19, 2012, the Grouse Creek projects amended their appeal to the Idaho Supreme Court
to include the PUC’s Sept. 7, 2012, Order on Remand and on Feb. 1, 2013, the record was lodged
at the Idaho Supreme Court and the projects moved that the Court hear arguments during
August 2013 and the court agreed.
On January 15, 2013, during the process of the Grouse Creek appeal to the Idaho Supreme
Court, the projects petitioned FERC to initiate an enforcement action against the Idaho PUC.
On Feb. 4, 2013, the IPUC filed a motion to dismiss Grouse Creek’s FERC petition, arguing that
Orders on Remand are more appropriately tested at the state level. The Grouse Creek petition
to FERC makes no mention of its pending appeal before the Idaho Supreme Court, the
established briefing schedule or their intent to seek an expedited oral argument in August. A
FERC enforcement action against the Idaho PUC would have to be brought in Boise, the same
location as the Idaho Supreme Court. But there is no case remaining at the Idaho PUC that
could be subject to a PURPA enforcement proceeding since the Idaho Supreme Court has
already obtained jurisdiction where the appeal record has been lodged. The IPUC further argues
that the main questions to be addressed are questions of state contract law, thus more
appropriately addressed at the State Supreme Court level.
On March 15, 2013, FERC issued a Notice of Intent that will initiate an enforcement action
against the IPUC, stating that Idaho Commission’s June 8, 2011, and September 7, 2012, orders
are inconsistent with PURPA.
On March 22, 2013, FERC filed a complaint in the United States Court for the District of Idaho asking the
Court to enter an order finding that the Idaho Commission violated PURPA, enjoining the IPUC from
imposing conditions on the sales agreements between Idaho Power Company and the developers of the
Grouse Creek and Murphy Flats wind projects, and directing the IPUC to issue orders approving the power
purchase agreements.
On August 28, 2013, the case was argued before the Idaho Supreme Court and a decision is expected by
the end of the year.
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Murphy Flats wind case timeline
On Nov. 20, 2012, the Federal Energy Regulatory Commission (FERC) announced it would
initiate an “enforcement action” in federal district court against the Idaho Public Utilities
Commission for the PUC’s denial of power purchase agreements between Idaho Power
Company and the developer of three wind projects near Murphy. It is the IPUC’s view that this
action by FERC is an unprecedented challenge to longstanding PUC legal process and could
impose unreasonable cost on Idaho Power ratepayers.
On November 5, 2010, Idaho Power, Avista and Rocky Mountain Power asked the PUC to
investigate issues related to small‐power (primarily wind) projects that qualify for the
commission’s published rates. The utilities asked that the cap on the size of projects that qualify
for the published rate be reduced from 10 average megawatts to 100 kilowatts. The utilities said
a rapidly expanding number of wind projects were having a profound price impact on customers
and transmission systems. The utilities claimed the small‐power projects PURPA was originally
intended to encourage are now developed by sophisticated large‐scale wind farms that break
down several projects in order to fall under the 10 aMW limit and qualify for the more attractive
published (or avoided‐cost) rate.
On December 3, 2010, the commission denied the utilities’ request to lower the size limits of
projects that can qualify for the published rate pending further investigation. However, the
commission did say that any decision it makes in regard to lowering the limit would become
effective December 14, 2010.
On February 7, 2011, the Commission reduced the size of wind and solar projects that can
qualify for published rates from 10 aMW to 100 kW. The commission said it is not its intent to
push small wind and solar QFs out of the market. However, the Commission said federal rules
regulating PURPA development insist that rates for purchases from QFs be “just and reasonable
to ratepayers and in the public interest – not in the interest of the QFs.”
On June 8, 2011, the PUC disapproved three purchase power agreements between Idaho Power
and the former developer of the Murphy Flats projects. The Murphy projects did not petition
the PUC for reconsideration within 21 days, nor did it appeal to the Idaho Supreme Court within
42 days, as provided in Idaho law. Consequently, the PUC order became final and no longer
subject to appeal.
On Aug. 16, 2012, nearly 15 months after the IPUC denied the Murphy Flat projects, the new
developer of the projects, First Wind, which acquired the assets of the projects in June 2012,
petitioned the PUC to modify its order due to previously issued FERC orders filed by two
developers of seven other wind projects. First Wind claimed the FERC orders related to the
other projects “constitute new facts or information justifying modification of the (Idaho)
commission’s order.”
Idaho Public Utilities Commission 2013
30 | P a g e
On Oct. 12, 2012, the IPUC declined to modify its original order because First Wind failed to
timely seek reconsideration or appeal the PUC’s order. First Wind’s petition, filed nearly 15
months after the reconsideration deadline, represents an attempt by new owners to resurrect a
long‐dead claim.
On Nov. 20, 2012, the Federal Energy Regulatory Commission (FERC) announced it would
initiate an “enforcement action” in federal district court against the Idaho Commission for the
PUC’s denial of power purchase agreements.
On March 22, 2013, FERC filed a complaint in the United States Court for the District of Idaho
asking the Court to enter an order finding that the Idaho Commission violated PURPA, enjoining
the IPUC from imposing conditions on the sales agreements between Idaho Power Company
and the developers of the Grouse Creek and Murphy Flats wind projects, and directing the IPUC
to issue orders approving the power purchase agreements.
Effect on Idaho Power ratepayers
The lack of a timely appeal disrupts the regulatory
process, introduces uncertainty, and is contrary to
the interests of ratepayers and utilities. In its order,
FERC compares the Idaho Commission’s action in
First Wind with that of another wind project that
timely appealed, but the two are not the same. In
the case of the project that timely appealed, a
settlement between all the parties was subsequently
approved by the PUC and that project is going
forward.
The Murphy projects, as is the case with many wind
projects, were proposed under the provisions of the
federal Public Utility Regulatory Policies Act (PURPA).
Under PURPA, regulated utilities must buy from
qualifying small‐power producers at a rate published
by state public utility commissions or negotiated
between the utility and the project. One‐hundred
percent of the costs regulated utilities incur buying
power from a PURPA project is passed on to
ratepayers.
The total payment Idaho Power would have made to
the developer and passed on to ratepayers over the
three 20‐year contracts is almost $300 million.
The PUC supports renewable development and, to
date, has approved 139 renewable projects under
PURPA, including 26 wind projects totaling 706 MW
in just the last four years. However, the PUC’s first
priority is to meet its statutory obligation to provide
adequate and reliable service at just and reasonable
rates. In its June 8, 2011, order denying approval of
several wind projects, including the Murphy projects,
the PUC expressed concern about customers being
“forced to pay for resources at an inflated rate and,
potentially, before the energy is actually needed by
the utility to serve its customers. This is clearly not in
the public interest.”
FERC Commissioner Tony Clark’s dissent to the FERC
order expresses that same concern: “More broadly,
while PURPA was designed as a foot in the door for
emerging renewable resources and small generators,
I sympathize with concerns that PURPA is
increasingly being used as a cudgel that would force
consumers to bear undue burdens. ... (FERC) has now
put itself in an awkward position. It will invoke the
power of the federal government to proactively
champion a private interest that may contradict the
best interests of the consumers of a state.”
Idaho Public Utilities Commission 2013
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PUC denies developer’s motions in solar power case
Case No. IPC‐E‐11‐15, Order No. 32913
October 29, 2013
The Idaho Public Utilities Commission ruled
that the developer of a proposed solar
project near Grand View failed to present
persuasive evidence that it is entitled to
ownership of all the Renewable Energy
Credits or that it ever completed a legally
enforceable obligation (LEO) that would
have required Idaho Power Company to buy
from the project. As of publication time for
this report, the project developer had filed
a Petition for Reconsideration with the
Commission.
The federal Public Utility Regulatory Policies
Act, or PURPA, requires utilities to buy
energy from qualifying small renewable
power projects at rates to be determined by
state commissions.
The developer of the Grand View PV Solar
Two project in Elmore County claims his
project was ready to provide energy to
Idaho Power, but the parties did not sign a
sales agreement because they could not
agree on who should receive the financial
benefits of the Renewable Energy Credits
(RECs) associated with the project. RECs
are tradable environmental commodities,
which represent proof that 1 megawatt‐
hour of electricity is generated from an
eligible renewable energy resource. (In a
separate case, the commission determined
that revenue from REC sales be split 50‐50
between the utility and the renewable
energy provider for wind and solar projects
that are 100 kilowatts or larger unless the
parties mutually agree to treat REC sales
differently.)
Grand View maintains that the dispute as to
who should keep the revenue from the
RECs is separate from whether Idaho Power
is obligated under PURPA to buy output
from the solar plant. The commission
denied Grand View’s motion for a
declaratory order, stating that the manager
of the project admitted that RECs are an
integral part of the project’s financial
viability and that without the revenue from
the RECs, the project was not ready to sell
energy to Idaho Power.
In an affidavit filed with the commission,
Grand View manager Robert Paul said the
project’s business plan is based upon selling
all the RECs associated with the project and
that without the ability to sell the RECs, the
“project’s financial viability will be
compromised.” He also said the project’s
profitability and his ability to raise the
capital necessary to build the project would
also be compromised.
“We find these statements undermine
Grand View’s argument that it was willing
Idaho Public Utilities Commission 2013
32 | P a g e
and able to mutually obligate itself to
supply power,” the commission said.
The commission denied another request by
Grand View Solar Two that the December
2012 commission decision to split RECs
evenly between utilities and solar and wind
projects not be applied to this case because
the proposed sales agreement was offered
in 2011.
However, the commission noted that REC
ownership was the primary issue in an
original complaint filed by Grand View Solar
Two against Idaho Power. “It now suggests
that we simply ignore the REC dispute – the
very heart of Grand View’s complaint,
amended complaint and Motion for
Summary Judgment,” the commission said.
“Grand View’s argument to simply separate
the REC dispute from the legally
enforceable obligation issue is inconsistent
with the facts and positions of the parties,”
the commission said.
Further, the commission said, both Grand
View and Idaho Power were parties to the
case that determined REC ownership and
Grand View did not raise the issue or
petition for judicial review at that time.
The commission has stated in prior orders
that when a QF project and a utility are
unable to agree to terms in their power
purchase agreement, that commission has a
responsibility to resolve the dispute. The
commission noted that ownership of RECs is
not an issue controlled by PURPA.
“Although there is not Idaho statutory law
specifically addressing the ownership of
RECs in Idaho, the commission relied upon
Idaho common law to determine the
property interest associated with RECs. Our
Supreme Court has declared that ‘the
commission has jurisdiction to examine
common law contract issues between QFs
and utilities.’ ”
Idaho Public Utilities Commission 2013
33 | P a g e
Summary of major electric
rate adjustments
Idaho Power has fourth largest PCA increase on
record
Case No. IPC‐E‐13‐10, Order No. 32821
May 31, 2013
Declining water, reduced revenue from
surplus energy sales and ongoing wind
power expenses all contributed to a $140
million Power Cost Adjustment, the fourth
highest in PCA history. To make up for the
shortfall caused by these factors, Idaho
Power Company’s residential customers will
be assessed a one‐year surcharge of an
average 12.5 percent effective June 1. For
all customers classes combined, the average
increase is 15.3 percent.
None of the money collected in the
surcharge can be used to increase Idaho
Power earnings or salaries, but is kept in a
deferred account, audited by the
commission, to be used only for paying
extraordinary power supply expense. While
base rates cover fixed costs, the PCA,
adjusted every June 1, covers costs that
vary from year to year, and are largely
outside the company’s control. These costs
are related largely to water levels, gas and
fuel expense, transportation expense and
renewable power contracts for projects
mandated by federal law. In six of the last
11 years, the PCA has been a decrease or no
change, but this year’s is the fourth highest
on
record
due
largely to
a 19 percent reduction in water the
company uses to power its hydroelectric
plants.
None of the parties to the case disputed the
company’s numbers in calculating the
annual adjustment, but all parties, including
commission staff, recommended spreading
the increase over two or three years to
soften its impact.
However, spreading the increase over two
or three years could mean even higher
increases for customers in 2014 and 2015 if
the state experiences low water again and a
new PCA surcharge is added to an existing
surcharge.
“We are sympathetic to the request to
spread the authorized rate increase over
time, and we understand that allowing full
recovery in one year will have an
immediate, negative impact on all
customers, some more than others,” the
commission said. “Our concern for creating
the risk of compounding or ‘pancaking’ rate
increases in the future overshadows the
Idaho Public Utilities Commission 2013
34 | P a g e
impact we know will be felt this year.
Forecasts for water are, at best, uncertain.
Given this, we find it too risky and
potentially could compound rate shock for
customers to spread this year’s PCA
recovery across multiple future years.”
For an average residential customer who
uses 1,050 kilowatt‐hours per month the
average monthly increase will be about
$11.38.
These are the primary factors that
contributed to the large increase in this
year’s Power Cost Adjustment:
About half of Idaho Power’s
generation comes from its
hydropower plants. Hydropower
generation from April 1, 2012,
through March 31, 2013 was 1.8
million megawatt‐hours less than
forecasted, a 19 percent reduction.
Revenue from surplus sales has
declined significantly. During those
periods when Idaho Power is
generating more electricity than its
customers consume, the utility sells
the surplus generation and shares
95 percent of the revenue with
customers. Cheaper energy prices
on the open market resulted in
$48.7 million in sales, $61.4 million
less than forecasted.
About $62.6 million is attributable to
power sales agreements between
Idaho Power and renewable energy
projects that qualify under the
provisions of the Public Utility
Regulatory Policies Act (PURPA). The
federal act requires utilities to buy
energy from qualifying renewable
energy projects. About $60 million
of that is from existing wind projects
and another $2 million is from new
wind added during the current PCA
year.
About $23 million is related to Hoku,
the Pocatello polysilicon plant that
failed last year. The company
included the $23 million in base
rates last year in anticipated
revenue from Hoku that never
materialized.
The revenue sharing credited to
customers since 2010 decreased to
$7 million this year, compared to
$27 million last year. If Idaho
Power’s return on equity exceeds
10.5 percent, half of the revenue
above that amount is shared with
customers through a reduction in
the PCA.
The commission said a negotiated
settlement in Idaho Power’s last base rate
case under which all parties agreed to keep
PURPA and Hoku expense in the PCA rather
than moving them into base rates causes a
higher PCA at this time. If not for that
decision, the commission said, the costs
from the wind projects would have been
included in base rates and customers would
already be paying to recover them. The rate
case settlement reduced the immediate
base rate impact on customers, “but, as we
see now, it has exposed them to a large
increase in the PCA adjustment,” the
commission said. “Had this been a normal
water year, the decision to recover those
costs in the PCA would not have been so
onerous. However, below normal water has
compounded the rate impact.” The
commission said that until Idaho Power files
a general rate case, the PURPA costs will
Idaho Public Utilities Commission 2013
35 | P a g e
accumulate and appear each year in the
company’s PCA.
The commission staff, Wal‐Mart Stores, Inc.,
and the Snake River Alliance proposed to
spread the increase over two years, while
the Industrial Customers of Idaho Power
(ICIP) and the Department of Energy argued
for a three‐year recovery. Large commercial
and industrial customers will experience
increases of 16.9 percent and 21 percent
respectively. ICIP argued the longer
recovery period was especially needed
following the recent 7 percent increase
related to the new Langley Gulch natural
gas plant.
In its comments, the Snake River Alliance
said, “At issue is whether the commission
opts to impose on consumers the true cost
of their electricity over the past year,
punishing as that might be, or whether it
defers some of the cost to 2014 without
knowing if that bill may be even greater
next year.” SRA said it generally supports
“recovering verifiable expenses as close to
the time in which they are incurred,” but is
concerned that a one‐year recovery will be
“overly burdensome on the company’s
most vulnerable customers.”
Idaho Power did propose a mitigation plan
that would have recovered 9.6 percent in
the first year and the remaining 5.7 percent
in the second year. Commission staff
proposed collecting about 7.8 percent each
of two years.
###
Idaho Power PCA Over the Last Decade
This year’s PCA recovers $140 million. The two years that were higher followed the Westwide
energy crisis. The 2001 PCA was $220.2 million and in 2002 it was $240.2 million. Here’s a
look at the PCA over the last 10 years.
2013 – 15.3 percent increase. $140 million.
2012 – 5.1 percent increase, ($43 million) but that is offset from a revenue sharing agreement
for a net increase to customers of 1.7 percent.
2011 – 4.8 percent decrease. $50.4 million.
2010 – 6.5 percent decrease. $41.9 million.
2009 – 10.2 percent increase. $194 million.
2008 – 10.7 percent increase. $106 million.
2007 – 14.5 percent increase. $30.7 million.
2006 – 19.4 percent decrease. $‐46.8 million credit.
2005 – No change. $73.1 million.
2004 – No change. $70.8 million.
2003 – 18.9 percent decrease. $81.3 million.
Idaho Public Utilities Commission 2013
36 | P a g e
Commission adopts settlement of Avista
electric, gas cases
Case Nos. AVU‐E‐12‐08 and AVU‐G‐12‐07
March 27, 2013
The Idaho Public Utilities
Commission adopted a
settlement to the Avista
Utilities rate case that
considerably reduces the
size of the increase
originally proposed and delays an electric
increase for another six months.
The settlement divides Avista’s request into
two phases with a 4.9 percent increase in
natural gas rates on April 1 (Avista originally
proposed 7.2 percent) and no electric
increase.
On Oct. 1, customers received a net electric
increase of 1.9 percent. (Avista originally
proposed a 4.6 percent electric increase
effective April 1.) Also on Oct. 1, customers
received a 0.3 percent increase in natural
gas rates.
The settlement precludes another base rate
increase from becoming effective until Jan.
1, 2015, at the earliest.
Under the agreement, the bill of an average
residential electric customer who uses 930
kilowatt‐hours per month will increase by
about $2 on Oct. 1. The gas increase for a
residential customer who uses the
company’s average 60 therms per month
will be about $2.82 per month on April 1
and another 31 cents per month on October
1.
“The settlement represents a significant
reduction in Avista’s requested revenue
increase,” the commission said.
“Moreover, the stay‐out provision
prohibiting any new electric or
natural gas base rate increase
before January 1, 2015, provides
an extended period of rate stability that
might not otherwise occur,” had the case
not been settled and instead proceeded to
a full hearing, the commission said.
Signatories to the settlement are Avista
Utilities, commission staff, the Clearwater
Paper Association, Idaho Forest Group and
the Community Action Partnership
Association of Idaho, (CAPAI), which
represents customers on low and fixed
incomes.
The electric increase, delayed until October
1, is a 3.1 percent increase to base rates.
However, the settlement also provides that
customers receive a $3.86 million credit due
to an Avista settlement with the Bonneville
Power Administration regarding BPA’s use
of Avista transmission lines over the last
eight years. That credit reduces the net
increase in electric rates to an average 1.9
percent.
The Oct. 1 gas adjustment is a 2.1 percent
increase to base rates. However, that total
is offset by a reduction in the annual
Purchased Gas Cost Adjustment (PGA)
resulting in a net 0.3 percent increase.
Idaho Public Utilities Commission 2013
37 | P a g e
The additional annual revenue requirement
allowed Avista is $7.8 million on the electric
side and $3.1 million on the gas side. When
Avista filed the case last October, it sought
$11.4 million on the electric side and $4.6
million on the gas side.
The return on equity allowed is up to 9.8
percent. If the company earns above that, it
must share 50 percent of the overage with
customers. Avista is allowed to earn up to a
7.9 percent rate of return.
About 70 percent of its electric revenue
increase and 48 percent of its natural gas
revenue increase are attributed to the need
to replace aging infrastructure and upgrade
existing plant. Other expense increases are
related to hydroelectric plant relicensing,
mercury emissions compliance and federal
reliability requirements.
About 21 commission staff members were
assigned to the case. They submitted 199
formal production requests and numerous
formal and informal audit requests. Staff
also reviewed the more than 300 data
requests and responses that were part of
the latest Avista electric and natural gas
rate case filings in Washington state. Three
Idaho staff accountants conducted a week‐
long on‐site audit of Avista’s books and
reviewed work papers of external auditors.
The commission, by state law, cannot
accept or deny a requested increase
without first considering the evidence.
State law requires that regulated utilities be
allowed to recover their prudently incurred
expenses and earn a reasonable rate of
return, which is also set by the commission.
The burden of proof is on the utility to
demonstrate if additional expenses already
incurred were needed to serve customers
and, if so, were they prudently incurred.
Avista serves about 123,000 electric and
75,000 natural gas customers in northern
Idaho.
Commission adopts decrease in Avista PCA, but
increase to Energy Efficiency Rider
Case Nos. AVU‐E‐13‐04, Order No. 32892,
AVU‐E‐13‐05, Order No. 32894
September 25, 2013
Avista electric customers will be paying
about 0.4 percent more for electricity as a
result of rate adjustments approved by the
Idaho Public Utilities Commission. The
increases in rates, effective Oct. 1, do not
increase Avista earnings.
Avista’s annual Power Cost Adjustment
(PCA) adjusts electric rates up or down to
account for conditions that change from
year to year due to factors like weather
conditions and fuel prices. When those
conditions result in expenses that are less
than anticipated, customers get a one‐year
credit. When those factors cause an
increase in costs above that already
included in base rates, customers get a one‐
year surcharge. This year, variable
Idaho Public Utilities Commission 2013
38 | P a g e
expenses were $3.8 million lower than
anticipated, resulting in a 0.83 percent
decrease for customers. The PCA portion of
electric rates declines from 0.09 cents per
kWh to 0.152 cents per kWh.
The commission also approved a 1.2
percent increase in Avista’s Energy
Efficiency Rider.
The rider, which increases from 0.146 cents
per kWh to 0.245 cents for residential
customers, funds about 30 programs that
increase energy efficiency or shift electric
demand from peak‐use times when
electricity is more expensive. The increase
will allow the company to recover a $3.6
million shortfall in the rider account and
allow continued funding of energy
efficiency and demand response programs.
In approving the rider increase, the
commission said that energy efficiency and
demand response programs reduce the
need for higher cost, supply‐side resources
such as a new or expanded power plant.
The programs funded by the rider must
pass cost efficiency tests that demonstrate
that all customers benefit from the
programs, not just those who directly
participate in them. In other words,
without the programs in place rates for all
electric customers would be higher.
Most of the underfunded amount in the
rider account is the result of Avista’s efforts
to incent customers to switch to higher
efficiency fluorescent lighting fixtures.
During 2012, the utility issued rebates to
4,740 customers who switched from the
T12 fixtures to T8 fixtures. Avista had
originally budgeted $1.2 million for the
program, but customer participation was so
high that the utility ended up paying $5.2
million in rebates.
Other programs include rebates for energy
efficiency appliances, HVAC improvements
and electric motor measures. Another
program offers rebates to residential
customers who convert from electric to
natural gas for space and water heating.
During 2012, the programs resulted in
Idaho electric savings of 24,183 megawatt‐
hours in addition to another 15,942 MWh in
savings through Avista’s participation in the
regional Northwest Energy Efficiency
Alliance, which is also funded by the rider.
Idaho Public Utilities Commission 2013
39 | P a g e
Rates increase slightly under PacifiCorp
settlement; but no further hike until 2016
Case No. PAC-E-13-04, Order
No. 32910
October 25, 2013
The Commission approved a negotiated
settlement that increased rates for customers
of PacifiCorp (Rocky Mountain Power in eastern
Idaho) by 0.77 percent effective Jan. 1, 2014.
The agreement also provided for no further
increases in base rates until Jan. 1, 2016, at the
earliest.
For a residential customer who uses the
company average of 830 kilowatt‐hours per
month, the increase is less than $1 per month,
according to the company’s calculations.
“The commission believes that the value of a
small, less than 1 percent uniform increase for
all rate classes over a two‐year period and the
company’s agreement to not file another
general rate case until May 31, 2015, provides
significant value for customers,” the
commission said. “In particular, it ensures multi‐
year rate stability and is in the public interest.”
A commission staff review of the company’s
application, which included an expansive audit
of the Company’s Results of Operations,
revealed that the company was prepared to file
a rate case with a requested revenue
requirement of greater than $15 million. The
settlement allows an additional revenue
requirement of $2 million, which is the
remaining expense for the Populus to Terminal
transmission line already approved by the
commission in a previous rate case.
The settlement further allows PacifiCorp to
defer up to $5.43 million in expense associated
with the new Lake Side II natural gas power
plant south of Salt Lake City. The plant begins
serving customers next summer and collection
of costs related to the plant will be collected
through the annual Energy Cost Adjustment
Mechanism (ECAM) beginning in 2015 and then
included in base rates after the next rate case.
The ECAM, which can be an increase or
decrease depending on other factors, is
adjusted every April 1.
The settlement also:
Allows PacifiCorp to defer any net
increase or decrease in depreciation
expense allocated to Idaho until after
the next rate case. A settlement to that
case is currently before the commission
(Case No. PAC‐E‐13‐02).
Creates a regulatory asset for future
recovery from customers of the
expense allocated to Idaho for removal
costs related to the retirement of the
172‐megawatt Carbon coal plant near
Helper, Utah.
Accepts a new electric service
agreement between PacifiCorp and its
largest customer, the Monsanto
phosphate plant near Soda Springs,
which begins Jan. 1. 2014, with an initial
term through Dec. 31, 2015. The
agreement includes a new section that
allows for an annual true‐up of the
credit Monsanto is allowed for agreeing
to have its service interrupted to
provide additional electrical load to
PacifiCorp. There are still issues
regarding the value of that interruption
to PacifiCorp that the parties will
continue to negotiate.
Idaho Public Utilities Commission 2013
40 | P a g e
Increase to BPA credit means decrease for Rocky
Mountain residential, commercial customers
Case No. PAC‐E‐13‐11, Order No. 32901
October 2, 2013
A federal electric rate credit passed along to
residential and small‐business customers of
Rocky Mountain Power increased Oct. 1,
2013 and the Idaho Public Utilities
Commission is hoping a settlement of one
remaining disputed issue will eventually
result in a larger credit.
The commission adopted a Bonneville
Power Administration residential exchange
credit of 0.3095 cents per kWh on an
interim basis pending further discussion.
The credit was 0.1839 cents per kWh. For a
residential customer who uses Rocky
Mountain Power’s average 840 kilowatt
hours per month, the monthly credit
increases from $1.54 to $2.60, resulting in a
1.3 percent decrease to the residential bill.
The Bonneville Power Administration
markets and distributes power to
consumer‐owned electric utilities in
Oregon, Washington, Montana and Idaho.
BPA power is generated from federal dams
in the Columbia River system. While
customers of publicly‐owned utilities (like
rural co‐ops and the City of Idaho Falls)
have preferential access to BPA power, the
Northwest Power Act of 1980 also requires
that customers of private, investor‐owned
utilities (85 percent of Idahoans) also share
in the benefits of the region’s federal
hydroelectric projects through a financial
credit as part of BPA’s Residential Exchange
Program (REP). The amount of the credit is
determined by formulas using various
factors, including a utility’s average system
cost for producing power. If an investor‐
owned utility’s average system cost to
produce electricity results in rates higher
than those offered to BPA public utility
customers, customers of investor‐owned
utility are issued a credit.
PacifiCorp is one of six Northwest investor‐
owned utilities whose customers can qualify
for a credit. PacifiCorp allocates its total
credit among the three Northwest states it
serves, including in eastern Idaho where it
operates as Rocky Mountain Power.
Commission staff disagrees with the way
PacifiCorp has chosen to allocate its share
of the credit to Idaho customers for the
2014‐2015 fiscal years. The benefits to
PacifiCorp customers in Oregon,
Washington and Idaho total $69.5 million
over two years, with Idaho scheduled to
receive $6.55 million. The credit is partially
determined by the amount of electric load
served by PacifiCorp in each of the three
states.
The commission agreed to adopt its staff
recommendation that the 0.3095‐cent per
kWh be adopted on an interim basis, while
reserving resolution of the disputed issue
pending further discussions between staff
and PacifiCorp.
Idaho Public Utilities Commission 2013
41 | P a g e
Demand Response Issues
Commission allows Idaho Power to ramp down
two demand response programs for one year
Case No. IPC‐E‐12‐29, Order No. 32776
April 3, 2013
The commission allowed Idaho Power
Company to considerably ramp down two
of its demand response programs, a
compromise from the company’s initial
application to suspend the programs for
2013. The ramped‐down programs will give
the commission and interested parties one
year to review how the programs should be
designed in the years ahead. (See following
article on settlement approving the
programs for beyond 2013.)
The two programs impacted are only a
portion of the 20 programs devoted to
demand‐side management.
The programs, one geared toward
residential customers and the other toward
irrigators, provide financial incentives to
customers to not use power during those
time periods when demand on Idaho
Power’s generation system is at a peak.
Due primarily to the economic downturn,
Idaho Power now claims its generating
plants can meet peak demand in the
summer months until at least through 2016,
eliminating the need for the programs.
Under the “A/C Cool Credit” program,
residential customers who signed up were
credited $7 for each of three summer
months to allow Idaho Power to remotely
cycle air conditioners on and off during
peak periods. Under the “Irrigation Peak
Rewards” program, Idaho Power was able
to turn off irrigation pumps through the use
of an electric switch connected to
customers’ electrical panels.
Idaho Power claims it has enough
generation to meet peak demand and that
suspending the programs would save
customers the approximate $5.5 million it
spent during 2012 on the A/C Cool Credit
program and $12.3 million on Irrigation
Peak Rewards. The costs of the programs
are passed on to customers through the
annual Power Cost Adjustment (PCA)
surcharge updated every June 1.
Instead of suspending the programs
entirely, the commission adopted a
negotiated settlement that provides a
“continuity payment” of $1 per month to
residential customers during three summer
months who have been participating in the
A/C Cool Credit program, even though air
conditioner cycling will not occur.
Participating irrigators will also receive
continuity payments, but the payment
amounts vary depending on which Peak
Reward option irrigators chose. It is hoped
those payments will incent customers from
not dropping out while the programs are
reviewed.
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“We find that providing continuity
payments as proposed for both residential
and irrigation participants for 2013
adequately balances the need to maintain
the two demand response programs while
the commission and the parties evaluate
the programs for 2014 and beyond,” the
commission said. “We also appreciate the
thoughtful comments offered by customers
about encouraging and maintaining
participants,” in the programs.
“We are disappointed that the company
proposed to discontinue their use
completely,” the commission said, noting
that reducing peak summer loads lessens
Idaho Power’s reliance on buying power or
building new generation resources.
“Valuable time and resources were used to
develop effective ... programs, and we do
not want to impair the effectiveness of
these programs in the future when the
company’s peak loads surpass its supply
resources.” The commission agreed with
one customer who said it may be cheaper
for the company to cycle air conditioning
units than to purchase or generate power
from its own resources.
The commission said it also found merit in
one customer’s comment about using the
programs to respond to unforeseen
emergencies. “Although the company does
not believe it will need to use these
programs in 2013, we doubt that it has
perfect foresight.”
The commission will open a new docket to
evaluate both programs for use in 2014 and
beyond.
The “A/C Cool Credit” and “Irrigation Peak
Rewards” programs were created in 2003
and 2004, respectively. During 2012, the
two programs and another program
targeted to commercial and industrial
customers reduced demand on Idaho
Power’s system by 367 MW.
Settlement ensures ongoing Idaho Power
demand response programs
Case No. IPC‐E‐13‐14, Order No. 32923
November 13, 2013
The commission accepted a settlement that
ensures continuity of Idaho Power “demand
response” programs designed to reduce
electric demand during summertime peak‐
use periods.
Earlier this year, Idaho Power Co. filed an
application with the commission to
temporarily suspend its “A/C Cool Credit”
and “Irrigation Peak Rewards.” The utility
said the programs cost the utility and,
hence, its customers more to operate than
the value of the energy saved. The
downturn in the economy reduced demand
on Idaho Power’s generation system, the
company claimed, and its own forecasting
did not show a peak‐hour capacity deficit
until 2016.
“A/C Cool Credit” paid residential
customers $7 per month each of three
Idaho Public Utilities Commission 2013
43 | P a g e
summer months for allowing the utility to
remotely cycle their air conditioning units.
“Irrigation Peak Rewards,” paid farmers to
curtail irrigation during peak periods. A
third program, “Flex Peak,” offers incentives
to large commercial and industrial
customers to create customized efficiency
programs.
The settlement, reached by Idaho Power,
commission staff, the Idaho Irrigation
Pumpers Association, Idaho Conservation
League, Snake River Alliance and EnerNOC,
Inc. , keeps costs lower by slightly reducing
both the duration of the programs and the
amount of credit paid customers who
volunteer to participate. The settlement
makes the demand reduction more valuable
by eliminating, in most cases, the
requirement on the utility to notify
participating customers in advance of
interruption.
The commission commended the parties
who reached the settlement after five
public workshops. The settlement allows
the utility to leverage the investment it
made when the programs started –
enrolling customers, installing load‐control
devices, etc. – while operating them in a
more cost‐efficient manner, reducing costs
to all customers.
Keeping the programs viable means they
can be ramped up when needed, the
commission said. “We believe it is
important for the company to continue its
demand response (DR) programs to ensure
it has sufficient, reliable DR resources to
meet expected deficits,” the commission
said. “Circumstances such as increased
demand related to business relocation and
expansion, coupled with increased
residential construction can occur quickly
....” the commission said.
The parties agreed that the value to both
the company and its customers of all the
programs combined would be about $16.7
million annually. During 2012, Idaho Power
spent $5.5 million on the A/C Cool Credit
program and $12.3 million on Irrigation
Peak Rewards. Much of that expense was
in direct payments to customers. During
2012, these two programs and FlexPeak
provided about 367 MW of peak reduction.
The settlement says demand response
should be used not only during peak‐use
periods, but also to delay construction of
new peaking capacity, avoid transmission
line losses and provide improved reliability
during emergencies.
Some of the program specifics include:
A/C Cool Credit will be available on
weekdays from June 15 to August
15. Participating customers will
receive a $15 bill credit over three
billing periods. Idaho Power will not
actively market the program, but
will recruit customers who move
into a home where a load‐control
device has been installed because
the previous owner agreed to
participate. The company will
accept new participants upon
request.
Irrigation Peak Rewards will be
available also from June 15 to
August 15 on Mondays through
Saturdays from 1 p.m. to 9 p.m.
Participants will receive a fixed
incentive of about $16 per kW per
Idaho Public Utilities Commission 2013
44 | P a g e
season. If more than three
interruptions occur, participants get
a variable incentive. Participating
irrigators will choose from one of
three interruption options, two of
which will not require advance
notice of interruption. Interruptions
can last up to four hours, but no
more than 15 hours per week or 60
hours per irrigation season.
Flex Peak Management would be
available to commercial and
industrial customers from June 15 to
August 15 from 2 to 8 p.m. on
weekdays. Participants get a fixed
incentive for up to three
interruptions and a variable
incentive if more interruptions
occur. Interruptions may last up to
four hours, but no more than 60
hours per summer.
The Industrial Customers of Idaho Power
participated in the discussions, but did not
sign the settlement.
PUC denies utility request for funding mechanism
Annual price adjustment would have covered costs of demand response programs
geared to large commercial, industrial customers
Case No. IPC‐E‐12‐24, Order No. 32766
March 22, 2013
The Commission denied an Idaho Power
Company request to immediately begin
recovering from customers the expenses
and carrying charges associated with an
energy conservation program geared
toward large commercial and industrial
customers.
Idaho Power asked the commission to
approve a yearly rate mechanism that
would be adjusted every June 1 to pay for
the program. The first adjustment under
the new tariff schedule would have
increased average residential rates by about
23 cents a month beginning June 1.
Under the program, eligible energy
efficiency projects are customized to serve
large customers at each of their sites to
reduce electric use. Idaho Power pays
financial incentives to these customers to
implement efficiency measures such as
motor rewinds and energy efficient
refrigeration. The cost of the program is
included in rates for all customers because
all customers benefit from the reduced
demand on Idaho Power’s generation
system. That reduced demand prevents the
company from having to generate or buy
energy from more expensive sources.
The large commercial and industrial
program is Idaho Power’s largest energy
efficiency program, saving about 68 million
kilowatt‐hours in 2011, enough energy to
serve the average needs of 5,400 residential
Idaho Public Utilities Commission 2013
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customers for one year. The commission
does not approve demand reduction
programs like these unless cost‐
effectiveness tests show that all customers,
not just those participating in the program,
pay less for electricity than they would if
the programs were not in place.
Idaho Power incurred about $8.1 million in
expenses and carrying charges attributed to
the program during 2011. The commission
earlier determined the 2011 expenses were
prudently incurred, but directed the
company to defer the expenses in a
regulatory account until it files its next rate
case.
That deferral allows the company to accrue
annual program expenses for recovery with
profit later on. The commission had
directed Idaho Power to address the issues
of the amount of interest it ought to be
allowed to accrue on the deferred balance
and the amount of time over which
customers would pay down the deferred
account in its next general rate case.
Rather than waiting for its next rate case,
Idaho Power proposed the yearly
mechanism to more timely recover the
expenses. Under the current method of
waiting until a rate case filing, there can be
a lag of between 18 and 36 months before
Idaho Power is allowed to recover
expenses, the company claimed.
The commission disagreed, stating that a
rate case provides a forum for all parties to
address questions that would not be as
thoroughly addressed in an annual rate
recovery mechanism. “In fact, the
comments filed by the parties demonstrate
reasonable disagreements over issues
necessarily reviewed when expenditures
are placed in customers’ rates,” the
commission said. These issues have direct
bearing on the amount of recovery that can
be included in rates, the commission said.
One of those issues is the amount of
interest the company ought to be allowed
on the deferred account. Both Idaho Power
and the Idaho Conservation League (ICL)
argued that allowing the company to earn
the same rate of return on demand‐side
resources (acquiring energy from
conservation programs that reduce
demand) as it does on supply‐side resources
(acquiring energy from power plant
production), would further incent
conservation measures.
A second issue is about how much time
should be allowed for customers to pay
back the company’s investment. The utility
and the ICL also said a four‐year
amortization period should be allowed to
reduce the company’s risk because the
incentives are not backed by physical assets
and Idaho Power doesn’t own or have
control over the efficiency equipment
owned by the large commercial and
industrial customers.
Commission staff noted the custom
efficiency program is a 12‐year program and
that a reduced amortization period to four
years without a reduced interest rate would
result in customers paying $12 million (after
being grossed‐up for taxes) for a program
that included only $7 million in direct
customer incentives.
Commission staff and the Industrial
Customers of Idaho Power advocated that
inclusion of these funds should be
considered in a rate case. The Industrial
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Customers also recommended the
commission open a docket to investigate
whether Idaho Power’s demand‐side
resource programs should be managed by a
third‐party provider “that does not demand
unnecessary and unwarranted returns in
order to bring the correct ‘business
evaluation perspective’ to the task of
energy efficiency and conservation.”
Two Rocky Mountain Power irrigation programs
suspended; deemed not to be cost‐effective
Case No. PAC‐E‐13‐10, Order No. 32879
August 19, 2013
The Commission granted an application by
Rocky Mountain Power to suspend two
efficiency programs for irrigators that have
been determined to not be cost‐effective.
The programs, which were suspended
effective July 15, 2013, include one in which
participants turn in worn nozzles, gaskets or
drains for equivalent new equipment at no
cost and another where irrigators are given
financial incentives when they make pivot
and linear equipment improvements.
Rocky Mountain hired a third party,
Navigant Consulting, which, the commission
determined, “presented clear and
compelling evidence,” that the programs
are not cost‐effective. The programs are
just part of a number of programs funded
by a 2.1 percent “Customer Efficiency
Services Rate Adjustment” on all Rocky
Mountain Power customer bills. The Idaho
commission requires that all programs
funded by the 2.1 percent rider pass cost‐
effectiveness tests to ensure their cost does
not exceed the savings realized for all the
company’s customers, not just irrigators
who participate in the programs. The total
program budget for 2012 was about
$652,000.
During some years customer efficiency
programs may be cost‐effective but then
other factors, such as decreased customer
participation and market conditions, may
render them not cost‐effective, the
commission said. “Therefore, the
commission remains vigilant in its oversight
and assessment of these programs and
constantly seeks to ascertain whether
program funds are being utilized in a cost‐
effective manner,” the commission said.
Rocky Mountain will instead continue its
“custom analysis” on a site‐by‐site basis
that would include pre‐installation
measurements to develop savings estimates
and then a post‐installation verification of
savings.
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Integrated Resource Plans
Reduced load growth leads Avista Utilities to
scrap or delay plans for natural gas plants
Case No. AVU‐E‐13‐07, Order No. 32888
November 1, 2013
Avista Utilities, which serves about 125,000
electric customers in northern Idaho, claims
that reduced load‐growth projections will
delay the need for a natural‐gas fired plant
by one year and eliminate the need for one
of two natural gas plants that were
projected for 2023.
The commission was taking comments on
Avista’s 20‐year growth plan, called an
Integrated Resources Plan at the filing of
this report. The commission requires
regulated electric and gas utilities to file
plans every two years outlining how they
anticipate meeting load‐growth in the most
cost‐effective manner.
In 2011, the company projected annual load
growth of about 1.6 percent, but the 2013
plan adjusts annual load growth downward
to slightly more than 1 percent. Avista’s
plan says its own generation and its long‐
term contracts will provide enough energy
to meet customer needs until 2020. The
company may be short during peak winter
periods in 2014‐15 and 2015‐16 but plans
to meet those needs with market
purchases. A long‐term capacity deficit does
not happen until 2020.
To address
that deficit,
the
company’s
plan calls for
the addition of an 83‐MW simple‐cycle
combustion turbine natural gas plant in
2019. Beyond 2020, the plan calls for
another 83‐MW simple‐cycle CT in 2023 and
a 270‐MW combined‐cycle CT in 2026.
Another simple‐cycle natural gas plant of 50
MW is anticipated for 2032.
Energy efficiency programs decrease
Avista’s energy requirements by 125
average megawatts and that is expected to
increase to 164 aMW by 2033. Absent
energy efficiency programs, Avista would be
resource‐deficient earlier than 2020.
The 2013 plan removes a 35‐aMW wind
resource that was included in the 2011
plan. A 30‐year power purchase agreement
with the eastern Washington Palouse Wind
Project in December 2012 (40 aMW) and
changes in Washington state law eliminated
the need for the 2019‐20 wind addition.
For the first time since Avista’s 2007 plan,
costs related to greenhouse gas emissions
have been removed. “Based on current
legislative priorities and the President’s
Climate Action Plan, a national greenhouse
Idaho Public Utilities Commission 2013
48 | P a g e
gas cap‐and‐trade system or tax is no longer
likely,” the plan’s executive summary
states. Instead, the IRP forecasts some plant
retirements to meet new environmental
rules promulgated by state and federal
agencies. Avista’s thermal resources include
five natural gas plants, a wood‐waste
biomass facility, and 111 MW from part
ownership of two units of the Colstrip coal
plant in eastern Montana.
Avista gets about half of its generation from
hydroelectric plants, 33 percent from
natural gas, 9 percent from coal, 5 percent
from power purchases and 2 percent each
from wind and biomass.
Completion of transmission plan key to long‐
range planning for Idaho Power Company
Case No. IPC‐E‐13‐15, Order No. 32868
September 20, 2013
An Idaho Power Company long‐range
growth plan is counting on completion of a
transmission line from Boardman, Oregon
to Melba as its major new resource for
power generation over the next 20 years.
Idaho Power’s Integrated Resource Plan
(IRP) projects the 500‐kV line will bring in
about 500 megawatts of additional power
from Northwest energy markets into Idaho
Power’s southern Idaho territory.
Idaho’s regulated electric utilities are
required to file an IRP every two years with
the Idaho Public Utilities Commission. The
plan explains how the utility intends to
provide adequate and reliable service to its
growing customer base at the lowest cost
possible over the next two decades. Idaho
Power’s IPR case was still open at the filing
of the report.
The IRP is for planning purposes only and is
updated to account for changing
circumstances. Even if the Idaho Public
Utilities Commission accepts the plan, the
resource
projects
outlined
must still
be reviewed and evaluated for their need
and prudency on a case‐by‐case basis.
Idaho Power anticipates that its customer
base will increase from the current 500,000
to about 670,000 by 2032 for an average
load increase of 21 MW per year, or 1.1
percent annual growth.
Completion of the transmission line,
expected in 2018, along with procuring
another 150 MW through energy efficiency
and demand reduction programs, was
found to be the least cost of nine potential
resource portfolios the utility considered,
according to the company.
The transmission project has been in Idaho
Power’s IRP since 2006. The utility is still
working on acquiring the necessary
regulatory approvals and permitting. Idaho
Power has a joint funding agreement for
the transmission line with the Bonneville
Power Administration and PacifiCorp, which
includes eastern Idaho as part of its service
territory.
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The company hopes to have 150 MW of
increased energy efficiency and demand
reduction in place by 2017 and increasing
that to 370 MW by 2032. A major upgrade
of the Shoshone Falls hydroelectric plant,
from its current 12.5 MW to 61.5 MW, is set
to be completed by 2019.
The utility is also planning on upgrades at
two out‐of‐state coal plants it co‐owns with
other utilities. Idaho Power currently has a
case before the commission seeking
authority to include about $130 million in
customer rates for emissions control
upgrades at the Jim Bridger plant near Rock
Springs. A technical hearing in that case is
scheduled for Nov. 22.
The plan also states that Idaho Power will
“commit to” installing emission‐control
technology at its North Valmy plant near
Winnemucca this year. The Bridger plant,
of which Idaho Power owns one‐third,
provides 770 MW of capacity to Idaho
Power customers and the Valmy plant
another 283 MW. Idaho Power owns 50
percent of the Valmy plant.
Idaho Power also owns 17 hydroelectric
projects, three natural gas‐fired plants and
one diesel‐powered plant. About 45 percent
of the utility’s generation comes from
hydroelectric resources, 30 percent from
coal, 14 percent from long‐term power
purchases, 7 percent from market‐
purchased power and 4 percent from
natural gas and diesel projects. Of the long‐
term power purchase contracts, 63 percent
of the generation comes from wind and 22
percent from hydroelectric resources. The
company buys about 789 MW from 103
projects that qualify under the Public Utility
Regulatory Policies Act, or PURPA. It also
buys all the output from the 100‐ MW
Elkhorn Valley wind project in northeast
Oregon.
PacifiCorp plans to acquire most new
generation from energy efficiency
Case No. PAC‐E‐13‐05, Order No. 32890
September 17, 2013
The commission accepted the IRP from
PacifiCorp, the electric utility that serves
eastern Idaho but, at the same time, urged
the utility to increase its efforts toward
energy efficiency and demand reduction in
the face of increasing coal costs.
Environmental groups claimed PacifiCorp,
which does business as Rocky Mountain
Power in eastern Idaho, Utah and
Wyoming, did not take into account
additional capital investment in coal plants
they claim will be needed to meet federal
environmental regulations.
Part of PacifiCorp’s long‐range plan is to
install emissions control equipment at three
of its coal plants – Hunter Unit 1 near Castle
Dale, Utah, and Jim Bridger Units 3 and 4
near Point of Rocks, Wyo. The utility also
plans to convert the Naughton Unit 3 coal
plant near Kemmerer, Wyo., to a natural
gas‐fired facility.
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The Snake River Alliance and the Idaho
Conservation League claim PacifiCorp
ignored their repeated requests to include
the costs of the coal plant retrofitting that
may be needed to meet the draft regional
haze rules. Including those costs would
make alternatives, such as increased
emphasis on energy efficiency and demand
reduction
more
attractive,
the
groups
claimed.
PacifiCorp projects it will meet 67 percent
of its future generation needs through
energy efficiency, acquiring 953 megawatts
within the next decade.
Other projected resources include 140 MW
of solar generation, 12 MW of combined
heat and power and between 650 and 1333
MW of market power purchases.
The company anticipates more market
purchases because wholesale power and
natural gas prices are down significantly
due to the expansion of shale gas
exploration in North America.
Without these additions, the company
anticipates a system capacity deficit of 824
MW starting this year, increasing to 2,308
MW in 2022.
The commission said it “offers no opinion”
on the company’s preferred resource
choices. However, the commission did say
that while forecasting coal costs is “fraught
with failure and uncertainty,” it seems likely
that the Environmental Protection Agency
will impose additional regulation on fossil‐
fueled generation such as coal and natural
gas.
“In light of this contingency, it appears to be
in the best interest of the company and its
customers to continue to evaluate and
devote more focus on the development of
alternative energy resources.”
The commission directed
the company to increase its
efforts toward achieving
higher levels of energy
efficiency and demand reduction.
“Instituting cost‐effective energy efficiency
measures that reduce customer demand
benefits everyone. Such measures can
obviate the need for new generation
resources and thereby decrease the
constant upward pressure on energy
pricing.” Efficiency programs “are almost
always preferable” to building new natural
gas plants or buying power from the
market, the commission said.
In its six‐state territory, PacifiCorp
anticipates average load growth of 1.1
percent per year. In Idaho, however,
expected annual growth is 0.57 percent.
The company does not anticipate significant
load growth in its Utah, Idaho and Wyoming
territory primarily because of load request
cancellations in Utah and Wyoming caused
by “prolonged recessionary impacts and
permitting issues.”
The utility also plans to increase generation
with expanded transmission that will allow
it to dispatch resources more efficiently and
improve reliability. Completion of the
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Windstar to Populus transmission project,
from Glen Rock Wyo., to Downey, Idaho, is
slated to bring more wind generation.
In its comments, commission staff said
there are indications that the need for the
transmission line could be offset by
accelerating efficiency and demand
response programs and encouraged the
company to consider the issue further.
Because of slower than normal load growth,
the company has deferred addition of a
major generation resource until 2024 when
it expects to add a 432‐MW combined‐cycle
natural gas plant and 432 MW of wind
generation.
The Idaho Conservation League claimed
that PacifiCorp’s “arbitrary and unexplained
discounting of future carbon costs can
expose customers to substantial risk.” The
Snake River Alliance questioned the need
for the utility to upgrade and retrofit its coal
plants and believes the company relies too
heavily on uncertain market transactions in
lieu of buying power from renewable
resources.
PacifiCorp’s largest customer, Soda Springs‐
based Monsanto, claims the company
intentionally designed the IRP process to be
overly complex so as to discourage
participation.
PacifiCorp hosted 15 public input meetings
before finalizing the plan.