150108_IPCsixsolarprojects.pdf

Case Nos. IPC-E-14-26, -27, -28;-29; -30 and -31
Contact: Gene Fadness [phone], 890-2712
www.puc.idaho.gov

PUC approves six more solar projects

BOISE (Jan. 8, 2015) – Sales agreements between the developer of six solar projects
and Idaho Power Company have been approved, adding another 181 megawatts to the
utility’s rapidly growing portfolio of solar generation.

Since November, the Idaho Public Utilities Commission has approved Idaho Power
agreements for 13 solar projects, totaling 400 MW and valued at $1.4 billion. Idaho
Power also recently signed contracts for 60 MW of solar generation in its Oregon
territory.

The projects approved this week are owned by Ketchum-based Intermountain Energy
Partners. Mark van Gulik is the developer. Five of the projects are in Elmore County and
one is in Power County. See the attached chart for project names, sizes and values.

In its order approving the agreements, the commission repeated the same concern it did
a month ago that the federal government’s must-buy provisions for qualifying
renewable energy projects may be compelling utilities to buy energy they do not need.

The federal Public Utility Regulatory Policies Act of 1978 (PURPA) requires regulated
utilities to buy energy from independent, renewable generation projects at rates
established by state commissions. The rate to be paid small-power producers is called
an “avoided-cost rate,” because it is based on the cost the utility avoids by not having to
generate the energy itself or buy it from another source. The commission must ensure
the avoided-cost rate is reasonable for utility customers because the price utilities pay
to qualifying small-power producers is included in customer rates.

The commission recently concluded a major review of PURPA contract terms and
conditions and updated how it calculates avoided-cost rates. Developers continue to
request contracts with Idaho Power in significant enough numbers “that we remain
concerned about the company’s ability to balance the substantial amount of must-take
intermittent generation and still reliably serve customers,” the commission said. The
order says utilities should inform the commission as to whether additional review of
PURPA contract terms and conditions is necessary.

Congress enacted PURPA in response to a national energy crisis in the late 1970s with a
goal to lessen the nation’s dependence on foreign oil. “Unfortunately, PURPA does not
address and FERC (Federal Energy Regulatory Commission) regulations do not
adequately provide for consideration of whether the utility being forced to purchase QF
power is actually in need of such energy,” the commission said.

Idaho Power’s 20-year Integrated Resource Plan does not indicate the utility is in need
of more energy sources. “And yet, in less than four months time, 13 QFs have
contracted with Idaho Power for nearly 400 MW of solar generation – all expected to be
on-line and producing power by the end of 2016,” the commission said.

The developer will be paid a non-levelized avoided-cost rate over the 20-year term of
the agreements, which means payments increase over the course of the agreement and
vary according to light-load and heavy-load hours of the day and seasons of the year.
The average levelized rate for these projects is about $61 per megawatt-hour and the
values of the six 20-year contracts range from $67.8 million to $243.8 million.

Included in each contract is an integration charge the developer pays Idaho Power to
cover the cost of integrating the energy into Idaho Power’s transmission and
distribution system. The integration cost increases as the amount of solar generation on
Idaho Power’s system increases. For these contracts, the charge ranges from $2.01 per
MWh to $4.60 per MWh in the first year of the contract and escalates through the end
of the 20-year term in 2036.

The agreements allow for a 2 percent deviation in estimated energy output before the
price can be adjusted. A consistent deviation from the hourly energy generation
estimates would be considered a material breach of the agreements. Also included is a
“90/110” firmness requirement. If a project’s generation exceeds 110 percent of
estimated output, the developer is paid 85 percent of a market-based price for the
generation above 110 percent of forecasted output. If the developer does not produce
at least 90 percent of forecasted generation, then all output is paid at 85 percent of the
market price.

Revenue from the sales of Renewable Energy Certificates associated with the projects
will be split 50-50 between the developer and Idaho Power.

The commission’s final order, along with other documents related to these cases, is
available on the commission’s Website at www.puc.idaho.gov. Click on “Open
Cases” under the “Electric” heading and scroll down to Case Nos. IPC-E-14-26 through
IPC-14-31.

Interested parties may petition the commission for reconsideration by no later than Jan.
29, 2015. Petitions for reconsideration must set forth specifically why the petitioner
contends that the order is unreasonable, unlawful or erroneous. Petitions should
include a statement of the nature and quantity of evidence the petitioner will offer if
reconsideration is granted.

Petitions can be delivered to the commission at 472 W. Washington St. in Boise, mailed
to P.O. Box 83720, Boise, ID, 83720-0074, or faxed to 208-334-3762.