20140609_4380.pdf

DECISION MEMORANDUM 1
DECISION MEMORANDUM

TO: COMMISSIONER KJELLANDER
COMMISSIONER REDFORD
COMMISSIONER SMITH
COMMISSION SECRETARY
COMMISSION STAFF
LEGAL

FROM: KRISTINE SASSER
DEPUTY ATTORNEY GENERAL

DATE: JUNE 2, 2014

SUBJECT: IDAHO POWER’S REQUEST TO UPDATE ITS WIND INTEGRATION
RATES AND CHARGES, CASE NO. IPC-E-13-22

On November 29, 2013, Idaho Power Company filed an Application with the
Commission seeking to update its wind integration rates and charges. The Company’s
Application includes a 2013 Wind Integration Study Report as well as the supporting testimony
of Philip DeVol and Michael J. Youngblood.
BACKGROUND
Idaho Power reports rapid growth in wind generation over the past several years.
Idaho Power maintains that it currently manages a total of 678 megawatts (MW) of wind
generation capacity on its system – 577 MW of capacity are provided by Public Utility
Regulatory Policies Act (PURPA) projects and an additional 101 MW of wind generation
capacity is provided by a non-PURPA project (Elkhorn Valley Wind Farm). Idaho Power states
that 505 MW of its total wind generation capacity has been added to the Company’s system
during 2010, 2011, and 2012.
Idaho Power’s Application maintains that, due to the variable and intermittent nature
of wind generation, the Company must modify its system operations to successfully integrate
wind projects without impacting system reliability. Idaho Power explains that it must provide
operating reserves from resources that are capable of increasing or decreasing dispatchable
generation on short notice to offset changes in non-dispatchable wind generation. The effect of
having to hold operating reserves on dispatchable resources is that the use of those resources is
DECISION MEMORANDUM 2
restricted and they cannot be economically dispatched to their fullest capability. Idaho Power
states that this results in higher power supply costs that are subsequently passed on to customers.
Idaho Power asserts that its capability to integrate wind generation is nearing its limit.
The Company maintains that, even at the current level of wind generation capacity penetration,
dispatchable thermal and hydro generators are not always capable of providing the balancing
reserves necessary to integrate wind generation. Idaho Power states that this situation is
expected to worsen as wind penetration levels increase, particularly during periods of low
customer demand.
The Company states that it considers the cost of integrating wind generation in its
integrated resource planning when evaluating the costs of utility and third-party generation
resources. Idaho Power maintains that the costs associated with wind integration are specific and
unique for each individual electrical system based on the amount of wind being integrated and
the other types of resources that are used to provide the necessary operating reserves. The
Company explains that, in general terms, the cost of integrating wind generation increases as the
amount of nameplate wind generation on the electrical system increases. Idaho Power asserts
that a failure to calculate and properly allocate wind integration costs to wind generators when
calculating avoided cost rates impermissibly pushes those costs onto customers.
Idaho Power asserts that the costs associated with wind integration are currently
under-collected. The costs are assessed on a percentage basis of various avoided cost rates,
which results in an inequitable contribution of the various wind QFs to the cost of integrating
wind on the system.
The Company states that the use of the percentage of avoided cost rates really has no
relation to actual costs of the additional reserves necessary to integrate variable and intermittent
resources on the system. Idaho Power further maintains that setting the amount of wind
integration charge for the entire duration of the power sales agreement assures further under-
collection of integration costs as those costs rise. The under-collection from existing wind QFs
results in an additional allocation to new wind QFs.
The Company discusses three separate methods by which wind integration costs
could be accounted for in avoided cost rates.
1) Maintaining current allocation;
2) Current allocation with an integration tariff; and
DECISION MEMORANDUM 3
3) Equitable allocation of costs.
The Company’s Application proposes two overall changes, which have been incorporated into
each of the three methods offered above, to address the collection of wind integration costs.
Change one abandons the use of percentage of avoided cost rate allocation and instead allocates
a fixed amount based upon penetration level. Change two decouples the wind integration charge
from the avoided cost rate contained in the power sales agreement and instead has wind
integration costs assessed as a stand-alone tariff charge.
A Notice of Application was issued on December 31, 2013, allowing 21 days for
intervention. Idaho Winds, LLC; Snake River Alliance; Cold Springs Windfarm, LLC; Desert
Meadow Windfarm, LLC; Hammett Hill Windfarm, LLC; Mainline Windfarm, LLC; Ryegrass
Windfarm, LLC; Two Ponds Windfarm, LLC; Renewable Northwest Project; America Wind
Energy Association; Cassia Windfarm, LLC; Hot Springs Windfarm, LLC; Bennett Creek
Windfarm, LLC; Cassia Gulch Wind Park, LLC; Tuana Springs Energy, LLC; High Mesa
Energy, LLC; Rockland Wind Farm, LLC; Idaho Wind Partners I, LLC; and Meadow Creek
Project Company, LLC, petitioned for, and were granted, intervention. A Notice of Parties was
issued on January 31, 2014.
Twelve intervenors1 (all qualifying facilities, “QFs”) represented by the firm of
Richardson Adams filed a Motion to Dismiss on January 31, 2014 (hereafter, “Petitioners”).
Petitioners argued that federal preemption principles should apply that would prohibit the
Commission from considering the Application of Idaho Power. On February 7, 2014, pursuant
to Rule of Procedure 256.04, the remaining intervenors2 filed motions in response to the Motion
to Dismiss. Idaho Power filed an Answer to the Motion to Dismiss and additional motions on
February 21, 2014. The Petitioners filed a reply to Idaho Power’s answer on February 28, 2014.
The Commission issued Order No. 33030 on April 30, 2014, denying Petitioners’
Motion to Dismiss. The Commission stated that “[a] Commission proceeding commenced to
consider a request by a utility to update its wind integration rates and charges does not conflict
with federal statutes.” Order No. 33030 at 7. However, we clarified that “any Commission

1 Cold Springs Windfarm, LLC; Desert Meadow Windfarm, LLC; Hammett Hill Windfarm, LLC; Mainline
Windfarm, LLC; Ryegrass Windfarm, LLC; Two Ponds Windfarm, LLC; Cassia Wind Farm, LLC; Hot Springs
Windfarm, LLC; Bennett Creek Windfarm, LLC; Cassia Gulch Wind Park, LLC; Tuana Springs Energy, LLC; and
High Mesa Energy, LLC.
2 American Wind Energy Association; Idaho Wind Partners I, LLC; Idaho Winds, LLC; Renewable Northwest
Project; Rockland Wind Farms, LLC; Snake River Alliance;
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approved modifications to Idaho Power’s wind integration rates and charges will only apply
prospectively – to new contracts as they are entered into by the parties and submitted to the
Commission for approval.” Id. at 8. The Commission allowed parties fourteen (14) days to
withdraw as intervenors if any party believed that, based on our ruling in Order No. 33030, it no
longer had a direct and substantial interest in the underlying proceeding. Several parties
withdrew from the case. An Amended Notice of Parties was issued on May 20, 2014.
Thereafter, pursuant to the Commission’s directive, Staff informally discussed a procedural
schedule, service of discovery, and other issues pertinent to the processing of this case with the
remaining parties.
THE PROPOSED SCHEDULE
The parties agree that Modified Procedure can be used to effectively process the
remainder of this case. Based on agreement between the parties, Staff proposes the following
procedural schedule:
Comment deadline July 2, 2014
Settlement conference July 9, 2014
Reply comment deadline July 22, 2014

The parties agree that best efforts will be made to answer discovery within 14 days, but no later
than 21 days from the date of the discovery request.
COMMISSION DECISION
Does the Commission wish to adopt the schedule proposed by the parties and issue a
Notice of Modified Procedure and Notice of Scheduling?

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