20141031Comments.pdf

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KRISTINE A. SASSER , " .,.;' ' '
DEPUTY ATTORNEY GENERAL ^^,r nrr 1l tii L: 33
IDAHO PUBLIC UTILITIES COMMISSION ?I,,'I1.''-,I -I '
PO BOX 83720 1n r:'r. -' i i :,rr^.li
BOISE,IDAHO 83720-0074 ,,",,''i,:'r-.il rJ'-'"'
[phone] i i'^-' --
BAR NO. 6618
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF' )
IDAHO POWER COMPANY FOR APPROVAL ) CASE NO. rpc-E,-r4-20
OR REJECTION OF AN ENERGY SALES )
AGREEMENT WITH BOISE CITY SOLAR, ) COVTMENTS OF THE
LLC, FOR THE SALE AND PURCHASE OF ) COwTMISSION STAFF
ELECTRIC ENERGY. )
)
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Afforney of record, Kristine A. Sasser, Deputy Attorney General, and in response to the Notice of
Application and Notice of Modified Procedure issued in Order No. 33118 on September 5,2014,
in Case No. IPC-E-14-20, submits the following comments.
BACKGROUND
On July 25,20l4,Idaho Power (Company) filed an Application with the Commission for
approval or rejection of an Energy Sales Agreement with Boise City Solar, LLC for the sale and
purchase of electric energy. Idaho Power requests that the Commission accept or reject the
Energy Sales Agreement between Idaho Power and Boise City Solar, LLC, under which Boise
City Solar would sell and Idaho Power would purchase electric energy generated by the project's
40 megawatt (MW) solar photovoltaic project located in Ada County on South Cloverdale Road
STAFF COMMENTS ocToBER 3t,2014
between Boise and Kuna, Idaho. The Agreement between the parties was executed on July 17,
2014.
The Agreement is for a term of 20 years. Idaho Power states that the Agreement was
executed in compliance with the Commission's orders directing the implementation of PURPA for
the State of Idaho and contains negotiated avoided cost rates based upon the incremental cost,
integrated resource plan pricing methodology available to solar projects whose generation will
exceed 100 kilowatts (kW). Idaho Power explains that the Agreement also contains negotiated
solar integration charges as directed by the Commission in Order No. 33043, as well as several
other negotiated provisions requiring specific Commission approval. Idaho Power states that the
2}-year estimated contractual obligation based upon estimated generation levels, including
avoided cost rates and solar integration charges, is approximately $161 ,461,924.
The proposed project is expected to use mono crystalline solar modules with Tier 1
inverters and utilize a dual axis tracking system. The facility has a nameplate rating of 39.989
MW AC. Boise City Solar selected January 16,2016, as its Scheduled Operation Date. Various
requirements have been placed upon Boise City Solar in order for Idaho Power to accept energy
deliveries from the project. Idaho Power states that it will continue to monitor compliance with
these requirements throughout the term of the Agreement.
Idaho Power explains that this Agreement is the first of its type (along with Grand View
Solar) submitted for approval that contains negotiated avoided cost rates based upon the
incremental cost, integrated resource plan pricing methodology. Prices were determined on an
incremental basis with the inclusion of this project in its queued position of proposed projects on
Idaho Power's system. Over the 2}-year term of the Agreement, monthly rates vary from
approximately $44lmegawatt hour (MWh) for light load hours in early months of the Agreement
to as high as $113/MWh for heavy load hours in the later years of the Agreement. The equivalent
Z}-year levelized avoided cost rate would amount to approximately $72.1544Wh.
Article 2l of the Agreement provides that the Agreement will not become effective until
the Commission has approved all of the Agreement's terms and conditions and declared that all
payments Idaho Power makes to Boise City Solar for purchases of energy will be allowed as
prudently incurred expenses for ratemaking purposes.
STAFF COMMENTS ocroBER 31,2014
STAFF ANALYSN
Under PURPA, utilities are required to purchase power produced by Qualiffing Facilities
(QFs) at avoided cost rates established by the Commission. Purchases by the utility are
mandatory, not discretionary. Whether the purchase is in the public interest has already
effectively been determined through PURPA itself-if a project meets the requirements of a QF,
then the mandatory purchase requirements apply to the utility. The potential benefits of a QF,
such as its impact on the economy, its effect on generating local tax revenue, its ability to create
jobs, or its environmental benefits may all be significant, but they are generally outside of the
scope of the Commission's consideration. The Commission's authority with regard to PURPA
contracts is to ensure that the rates, terms and conditions contained in proposed power sales
agreements are reasonable. The rates in the agreements must accurately reflect the utility's
avoided costs, and the terms and conditions must fairly protect both the QFs and the utility and its
ratepayers. Consequently, Staffs comments on the proposed Agreement focus exclusively on
these areas.
Boise City Solar Pricing
Rates in the Agreement were determined using the incremental cost IRP methodology.
The rates consist of three components: (l) the avoided cost of energy, (2) the avoided cost of
capacity, and (3) the solar integration charge. Essentially at a basic level,
Total Avoided Cost:Avoided Cost of Energy + Avoided Cost of Capacity - Solar Integration Cost
The avoided cost of energy is based upon the incremental costs the utility would incur, but
for the addition of the QF resource, to generate power itself or to purchase power from another
source. The avoided cost of capacity reflects the cost of constructing or purchasing a generation
resource capable ofproducing that energy. The solar integration charge is intended to account for
the expense of integrating solar resources into the utility's distribution and transmission system.
The Avoided Cost of Enerry
Idaho Power determines the avoided cost of energy by choosing the highest displaceable
incremental cost being incurred during each hour of the QF's proposed contract term.
Displaceable incremental costs are limited to (1) incremental costs for the utility-owned thermal
resources including Bridger, Boardman, Valmy, Danskin, Bennett Mountain, and Langley Gulch
STAFF COMMENTS ocToBER 31,2014
that are online and operating at above their minimum load level, (2) the incremental cost
associated with longer-term firm purchases, and (3) the incremental cost of market purchases as
determined by the AURORA model on an hour-to-hour basis. Next, the highest displaceable
incremental cost is multiplied by the QF's hourly generation profile to produce the payment for
each hour. For example,
Highest Displaceable Incremental Cost for Hour I x QF Forecast Generation for Hour l,
Highest Displaceable Incremental Cost for Hour 2 x QF Forecast Generationfor Hour 2,
Highest Displaceable Incremental Costfor Hour 3 x QF Forecast Generationfor Hour 3,
These products are then summed over heavy r""O *O light load hours of each month, and divided
by the corresponding forecast QF generation to get the results of heavy load and light load prices
for each month of the contract term.
After an extensive review of Idaho Power's application of the incremental cost IRP
methodology, Staff has identified a number of flaws that it believes make the final results deviate
significantly from the true avoided cost of energy. Staff believes it is appropriate to address the
perceived flaws in the incremental cost IRP methodology now in order to ensure that accurate
avoided cost rates are applied in this Agreement and other future contracts.
Idaho Power generally described its proposed application of the methodology in Case No.
GNR-E-11-03 (See Bokenkamp, Di.pp. l0 - 33). Although the Commission approved use of
Idaho Power's incremental cost IRP methodology in Order No. 32697, full application of the
methodology has not occurred until now. The Grand View and Boise City Solar contracts will be
the first solar contracts to contain rates determined using the methodology. At the time of writing
of these comments, I I additional contracts have been submitted containing rates developed using
the methodology. Thus, it is critical to correct the flaws before the methodology is applied to any
project.
Intense scrutiny of the methodology did not occur in the GNR-E-11-03 case because the
methodology had yet to actually be applied. Now that it has been applied, it is only now that it has
become possible to closely examine the details of the methodology. Staff believes that the
Commission's approval of the incremental cost IRP methodology in Order No. 32697 was
intended to be general and based on the concept, not specific based on yet-to-be-determined
details. As stated earlier, Staff believes the Commission must ensure that the avoided cost rates
are as accurate as possible. Despite Boise City Solar and Idaho Power both apparently negotiating
in good faith based on the rates in the proposed Agreement, Staff believes the Commission has
STAFF COMMENTS ocroBER 3t,20t4
both the obligation and the authority to order that the contract rates be re-computed, correcting the
flaws identified by Staff.
Staff believes the Commission's authority to order that the rates be modified is supported,
in part, by a recent decision of the Idaho Supreme Court. ln ldaho Power Company v. Idaho
Public Utilities Commission and Grouse Creek Wind Park, 155 Idaho 780, 316 P.3d 1278 (2013),
the Court concluded that any rates at which electric utilities can purchase power must be approved
by the Commission and that the Commission is not required to accept whatever rates are set forth
in power purchase agreements.
Staff will address each of the perceived flaws in more detail below.
Assumptions about Displaceable Resources
As proposed, the incremental cost IRP methodology assumes that the resource of the
highest displaceable incremental cost always has enough volume to be displaced. For example, if
Bridger 1 is the resource of the highest displaceable incremental cost for a specific hour, then
Bridger 1 sets the avoided cost of energy for that hour, even though it may only have l0 MW to be
displaced and the QF is expected to produce 80 MW during that hour. Idaho Power pointed out in
Case No. GNR-E-l l-03 that "[t]his simplification may introduce some error...[I]t will always be
in favor of the QF since Idaho Power begins with the highest incremental cost resource that is
displaceable to set the avoided cost for any hour" (See Bokenkamp, Di. pp.26).
This simplification introduces significant errors that become greater as project size
increases. For a 40 MW project like Boise City, the errors could potentially amount to millions of
dollars. Staff believes this flaw could be fixed by assigning QF capacity to different resources in
the order of incremental cost values, (i.e. from the highest displaceable to the second highest
displaceable to the third highest displaceable...) until all the QF capacity is distributed to various
resources. The final price is the weighted average of a set of incremental costs with different
displacements. For example, for the l6th hour of June 24,2Ol7,the displaceable output and the
displaceable incremental cost are shown in Table l.
STAFF COMMENTS ocroBER 3t,2014
Table 1. Displaceable Output and Displaceable Incremental Cost for the 16th Hour of June24,2017
Displaceable 0utput (MW)
Brldser 1 lridser 2 lrideer !Bridser 4 Boardman /almv I t/almv I Danskin 1 )anskin 2 Danskin !Bennett [fin tG
LTFirm
Purchase
VlkClearing
rrice
13.6(13.2(20.7t 12.84 1.9:0.fl 0.0 0.0(0.fl 0.q 0.fl 27.5i 0.u 279.&28.5(
Disolaceable lncremental Cost lS/MWhl
Bridser 1 3ridger 2 lridger Bridser 4 Boardman /almv 1 [almy 2 Danskin 1 )anskin 2 Danskin i Bennett lrltn LG
LTFirm
Purchase
27.31 27.6i 29.Lt 29.31 32.7t 0.q 0.0(0.0(0.fl 0.q 0.q 32.4',0.q 28.5(32.7(
The avoided cost of energy for Boise City for that hour can be calculated as follows:
Avoided Cost of Energyfor the l6'h hour of June 24, 2017
: 3 2. 7 6* ( I. 9 2/40) + 3 2. 47 * (27. 5 3 /40) + 29. 3 7 * [(40- 1. 9 2-27. 5 3)/40J
: 31.67
This new method takes into account of real displaceable capacities of the resources, and
assigns QF's total capacity to each resource from the high to low incremental cost values until all
the capacity is distributed. Prices under this new methodology are always lower than or equal to
those under the original IRP methodology, but never higher. Staff believes the new method is able
to capture the true avoided cost of energy more accurately, and recommends the Commission
consider the displaceable capacities of the resources and adopt this new method in calculating the
avoided cost ofenergy.
Assumptions about Fuel Forecasts
The current methodology assigns one fuel price to each year, assuming the fuel price stays
the same over the entire year. This is less of a problem for coal-fired plants, because typically coal
prices stay the same within a year in a contract. But when it comes to gas-fired plants, their fuel
prices vary from month to month. In general, natural gas is more expensive during the winter than
it is during the summer (See Figure l). Conversely, solar generation is lower during the winter
than it is during the summer (See Figure 2). When the IRP methodology applies a fixed annual
natural gas price without considering the monthly variations, the QFs are underpaid in the winter
and overpaid in the summer. Since the QFs produce more energy in the summer when natural gas
price is lower, the overpayment amount is greater than the underpayment amount, and thus the
overall effect is overpayment to QFs.
STAFF COMMENTS ocToBER 31,2014
Staff re-calculated the solar prices with the monthly variations considered, and results
showed that prices for Boise City Solar increased slightly. This flaw is likely not an issue in
calculating the avoided cost of energy for wind projects, because wind generation profiles do not
seem to be related to natural gas prices. However, in a solar case, solar generation profiles and
natural gas prices are correlated with temperature positively and negatively, respectively.
Therefore, it is inappropriate to use the annual average natural gas price in calculating the avoided
cost of energy.
Staff, in re-calculating rates for Boise City Solar, has incorporated modeling changes to
account for monthly gas price variations. Staff recommends that the Commission adopt Staff s
modeling changes for Boise City Solar and for other future contracts.
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Henry Hub Monthly Shape
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Henry Hub Monthly Shape of Scaling Factors
Monthly Solar Capacity Factor
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7STAFF COMMENTS ocToBER 31,2014
The Avoided Cost of Capacity
Under the incremental cost IRP methodology, the avoided cost of capacity is based on the
cost of a simple cycle combustion turbine (SCCT) from the Company's 2013 IRP. A SCCT is
assumed as a surrogate resource that Idaho Power would avoid building absent the capacity
provided by the QF. The cost of the SCCT is multiplied by the peak-hour capacity factor of the
PURPA resource to account for the amount of capacity the PURPA resource will provide during
Idaho Power's peak-hour period between 3:00 p.m. and 7:00 p.m. in July, because the utility's
need for capacity is driven by the summertime peak-hour loads during that period.
The avoided cost of capacity is only paid by the utility when the utility experiences a
capacity deficit. At the time the Agreement was being negotiated and signed, Idaho Power's first
deficit was expected to occur in2016. Consequently, the capacity component of the rates in the
Agreement is based on an assumption of a2016 capacity deficit.
In calculating Boise City Solar's avoided cost of capacity, Idaho Power used a 6.70 percent
Weighted Average Cost of Capital. Although this is inconsistent with the 8.18 percent Weighted
Average Cost of Capital used in the SAR model, Staff believes it is appropriate to use 6.70 percent
in this case. Because rates in the proposed Agreement are based upon the IRP methodology, it is
more important to be consistent with the discount rate used in the Company's 2013 IRP, than to be
consistent with the SAR methodology.
Staff believes that both the assumptions and the methods used by Idaho Power to calculate
the avoided cost of the capacity are reasonable. However, as more data become available from
this and other solar PURPA facilities, Staff expects Idaho Power to regularly revisit its peak-hour
capacity analysis for future solar contracts.
Solar Integration Charge
The Agreement also contains a solar integration charge that was negotiated and agreed to
by the parties. Although the integration charge is based on Idaho Power's 2013 solar integration
study, the study was not yet complete during contract negotiations. However, the most currently
available data and analysis from the study was used by the parties in the course of negotiations.
The negotiated solar integration charge starts at $1.34lMWh for the first year of the Agreement
(2015) and escalates to $3.1llMWh in2036. The equivalent 2O-year levelized solar integration
charge would amount to approximately $2.0144Wh.
STAFF COMMENTS ocToBER 31,2014
Idaho Power currently has 60 MW of existing solar penetration based on recently signed
Oregon contracts, in addition to the proposed 80 MW Grand View project. The solar integration
charge for Boise City Solar, agreed to by the parties, is based upon the costs identified in the 100-
300 MW tier of solar penetration from the solar integration study.
Staff believes that the solar integration charges contained in the Agreement are reasonable.
Staff also believes it is reasonable to base the solar integration charges on Idaho Power's best
estimate at the time the Agreement was negotiated, rather than on the final integration charges
now proposed in Case No. IPC-E-I4-18. In any event, the difference between the solar integration
charges in the Agreement and those proposed in IPC-E-14-18 is very minimal.
Effect on Contract Rates of Staff s Proposed Modifications
Staffs proposed rates are included as Attachment 1. If all of the computational
modifications proposed by Staff are made, the avoided cost rates in the Agreement would be
increased by approximately $0.24 per MWh. Over the 2}-year term of the Agreement, on a net
present value basis, the difference in payments from Idaho Power to Boise City Solar is an
increase of approximately $5 1 6,000.
In the case of Boise City Solar, the computational modifications proposed by Staff produce
an increase from the rates contained in the Agreement. However, in the case of Grand View Solar,
the computational modifications produced a very significant decrease. Nevertheless, for
consistency sake, Staff recommends that the modifications be incorporated into the analysis for all
future contract rates derived using the incremental cost IRP methodology.
90/110 Firmness Requirement
This Agreement contains provisions for a90ll10 firmness requirement, as well as a pricing
adjustment and a solar integration charge. Idaho Power states that it prefers that90ll10 firmness
be included in all PURPA QF agreements, and that the Company does not consider solar
integration charges to be a replacement for the 90/l l0 requirements. Idaho Power believes that
90/l l0 firmness requirements and solar integration charges address different concerns. 90/1 l0
requirements address the Commission's definition of firmness for entitlement to an avoided cost
rate determined at the time of contracting for the duration of the contract, whereas solar integration
charges address the increased system operation costs incurred because ofthe variable and
intermittent nature of the generation. Based on negotiations and an agreed to price adjustment, the
STAFF COMMENTS ocToBER 31,2014
Company states that it is confident that the Agreement contains provisions to reasonably assure
that the project performs in conformance with its generation estimates and, if not, the project
receives a reduced price for the non-conforming month's generation.
More specifically, the Agreement allows for a two percent deviation in the monthly net
energy deliveries from the generation profile estimates provided by the project, without assessing
a price adjustment. If the project's actual generation deviates downward by more than two percent
of its generation estimates, then a coffesponding percentage adjustment to the monthly price is
imposed. The price adjustment has a floor of 90 percent and a cap of 100 percent of the contract
price. The adjustment is limited to a maximum price reduction of l0 percent and if the project
energy deliveries exceed 100 percent of the original estimates there is no price adjustment.
Staff believes this pricing adjustment is a critical element of this contract as it provides
some assurance that the initial prices calculated and included in the contract for a20 year period
are based upon accurate estimates. Moreover, the pricing adjustment helps to ensure that the rates
paid to Boise City Solar are commensurate with the energy firmness delivered by the project. In
Staff s opinion, the price adjustment alone carries the most weight in assuring that the Agreement's
terms are a reasonable substitute for the 90/110 firmness requirement. The effectiveness of this
provision requires, however, that Idaho Power strictly enforce the contract term that consistent and
material deviations from the hourly energy estimates in the generation profile will be considered
by Idaho Power to be a material breach of the Agreement.
Idaho Power states that in this contract, the monthly price adjustment and the 90i 110
provision work together. That is, if the initial 90/110 net energy amounts estimated in the contract
are changed to stay within the 90/110 performance requirement, potentially a price adjustment
may occur because the project's generation profile no longer matches the profile upon which the
rate computations were based. However, if the project elects to not change the 90/110 net energy
amounts specified in the contract, a price adjustment may not occur, but instead there may be a
price change due to the project not meeting the 90/l l0 performance requirement. Thus, in either
circumstance there is motivation for the project to provide accurate estimates at the time the
contract pricing is calculated.
Staff believes that collectively, the requirements for a price adjustment mechanism and the
90i 110 firmness provisions are a reasonable substitute for the 90/l l0 requirement that has been
imposed on intermittent generation in the past.
t0STAFF COMMENTS ocroBER 31,2014
Additional Contract Provisions
New provisions providing for actual delay damages as opposed to liquidated damages are
included in the Agreement, consistent with Order No. 32697. The parties negotiated a 50/50 split
of environment attributes (aka renewable energy credits). As with all PURPA QF generation, the
project must be designated as a network resource (DNR) to serve Idaho Power's retail load on its
system. Consequently, the Agreement contains provisions requiring completion of a Generator
Interconnection Agreement (GIA), compliance with GIA requirements, and designation as an
Idaho Power network resource as conditions of Idaho Power accepting delivery of energy and
paying for the same under the Agreement. In order for the project to maintain its DNR status,
there must be a power purchase agreement associated with its transmission service request that
maintains compliance with Idaho Power's non-discriminatory administration of its Open Access
Transmission Tariff (OATT) and maintains compliance with FERC requirements.
Staff believes these additional contract provisions are reasonable and comply with prior
Commission orders.
RECOMMENDATIONS
Staff believes that the rates contained in the Agreement should be revised to account for
the energy cost computation issues identif,red by Staff. Staff recommends that the spreadsheet
model used for computing energy value by modified to account for monthly variations in natural
gas price and heat rate, and thus monthly variations in dispatch costs of Idaho Power's gas-fired
resources. Staff also recommends that the model be modified to allow for hourly dispatch costs to
be assigned in proportion to the cost and quantity of each resource able to be displaced by the QF
in each hour. These modeling modifications are described in more detail above in these
comments. When Staff s proposed adjustments are made to spreadsheets used to compute the
rates, the resulting rates are those shown in Attachment 1.
Staff believes that all of the remaining terms and conditions contained in the Agreement
are acceptable and in compliance with applicable Commission orders.
Staff recommends that the Commission direct Idaho Power to revise the rates in the
Agreement to match the rates proposed by Staff, obtain concurence by the project developer, and
resubmit the Agreement for Commission approval. If Staff s recommended rates are included in a
revised Agreement, then Staff recommends that the Commission approve all of the Agreement's
t1STAFF COMMENTS ocToBER 31,2014
rates, terms, and conditions and declare that all payments Idaho Power makes to Boise City Solar
for purchases of energy will be allowed as prudently incurred experurcs for ratemaking purposes.
Respecttully submittedthis 3F day ofOcto ber2Ol4.
Technical Staff: Rick Sterling
Yao Yin
i:umisc:commcnts/ipcc l4.2Oksrpsyy comments
Deputy Attorney General
STAFF COMMENTS ocroBER 31,20t4
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CERTIFICATE OF SERVICE
T HEREBY CERTIFY THAT I HAVE THIS 31't DAY OF OCTOBER 2014,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC.E.I4-20, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
DONOVAN E. WALKER
REGULATORY DOCKETS
IDAHO POWER COMPANY
P.O. BOX 70
BOISE, TD 83707
E-MAIL : [e-mail]
dockets@ idahopower. com
RANDY C. ALLPHIN
ENERGY CONTRACT ADMINISTRATOR
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE