20141031Comments.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03s7
BAR NO. 6618
Street Address for Express Mail:
472 W . WASHINGTON
BOISE, IDAHO 83702.5918
Attorney for the Commission Staff
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR APPROVAL
OR REJECTION OF AN ENERGY SALES
AGREEMENT WITH GRAND VIEW PV SOLAR
TWO, LLC, FOR THE SALE AND PURCHASE
OF ELECTRIC ENERGY.
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norll
CASE NO. IPC.8.14.19
COMMENTS OF THE
COMMISSION STAFF
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
COMES NOW the Staff of the ldaho Public Utilities Commission, by and through its
Attorney of record, Kristine A. Sasser, Deputy Attorney General, and in response to the Notice
Modified Procedure issued in Order No. 33119 on September 5,2014, in Case No. IPC-E-14-19,
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 (Agreement) with Grand View PV Solar Two,
LLC (Grand View), for the sale and purchase of electric energy. Idaho Power requests that the
Commission accept or reject the Agreement between Idaho Power and Grand View PV Solar Two,
LLC, under which Grand View would sell and Idaho Power would purchase electric energy
generated by Grand View's 80 megawatt (MW) solar photovoltaic project located approximately
STAFF COMMENTS ocToBER 31,2014
20 miles southwest of Mountain Home, 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 (IRP) 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,
avoided cost rates and solar integration charges, is approximately $310,237,634.
The proposed project is expected to consist of approximately 340,480 polysilicon
photovoltaic panels installed on a single axis tracking system, supported by a fixed post and beam
structure. Grand View selected July I ,2016, as its Scheduled Operation Date. Various
requirements have been placed upon Grand View 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 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 2O-year
term of the Agreement, monthly rates vary from approximately $3l/megawatt hour (MWh) for
light load hours in early months of the Agreement to as high as $159/MWh for heavy load hours
in the later years of the Agreement. The equivalent 2}-year levelized avoided cost rate would
amount to approximately $73.4 I /MWh.
Article 2l of the Agreement provides that the Agreement will not become effective until
the Commission has approved all of the Agreement's terms and conditions and declared that all
payments Idaho Power makes to Grand View for purchases of energy will be allowed as prudently
incurred expenses for ratemaking purposes.
2STAFF COMMENTS OCTOBER 3T,2OT4
STAFF ANALYSIS
Under PURPA, utilities are required to purchase power produced by Qualifying Facilities
(QF$ 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.
Grand View 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 Energ + 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 Energy
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 ocroBER 31,20t4
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 Costfor Hour I x QF Forecast Generationfor Hour l,
Highest Displaceable Incremental Costfor Hour 2 x QF Forecast Generationfor Hour 2,
Highest Displaceable Incrementol Cost for Hour 3 x QF Forecast Generationfor Hour 3,
These products are then summed over heavy load and light load hours of each month, and divided
by the corresponding forecast QF generation to get the results of heavy load and
for each month of the contract term.
load prices
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. 10 - 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, 11 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 Grand View and Idaho Power both apparently negotiating in
good faith based on the rates in the proposed Agreement, Staff believes the Commission has both
STAFF COMMENTS ocroBER 31,20t4
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 I sets the avoided cost of energy for that hour, even though it may only have l0 MW to be
displaced while the QF is expected to produce 80 MW during that hour. Idaho Power pointed out
in Case No. GNR-E-11-03 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 an 80 MW project like Grand View, the errors can amount to millions of dollars.
Staff believes this flaw could be corrected 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 22"d hour of March l4,2}l7,the displaceable output and the
displaceable incremental cost are shown in Table l.
STAFF COMMENTS ocToBER 31,2014
Table l. Displaceable Output and Displaceable Incremental Cost for the 22nd Hour of March 14,
2017
Displaceable 0utput (MW)
Brideer Brideer !Bridser !Bridser4 Boardman /almy /almy 2 )anskin 1 Danskin I Danskin 3 lennett Mtn LG
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63.1!53.3:52.4{43.6(4.5t 0.q 0.0(0.q 0.q 0.0(0fi N.4{0.fi 0.0(38.45
Displaceable lncremental Cost (S/MWh)
Bridser 1 Bridger i Bridger Brideer4 Boardman /almy Valmv 2 )anskin 1 Danskin I Danskin lennett [4tn tG
lTFirm
Purchase
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27,34 27.6"29,11 29,31 32.7(0,0(0.0(0.fi 0.q 0.0(0fi 32.4)0.q 0,0(32,7(
The avoided cost of energy for Grand View for that hour can be calculated as follows:
Avoided Cost of Energyfor the 22nd hour of March 14, 2017: 32.76*(4.55/80) + 32.47*(40.4/80) + 29.37*[(80-4.55-40.4)/80J
:31.13
This new method takes into account the 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 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. Because 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 31,2074
Staff re-calculated the solar prices with the monthly variations considered, and results
showed that prices for Grand View dropped a small amount. 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 ofenergy.
Staff, in re-calculating rates for Grand View, has incorporated modeling changes to
account for monthly gas price variations. Staff recommends that the Commission adopt Staff s
modeling changes for Grand View and for other future contracts.
Henry Hub Monthly Shape
1.06
L.O4
L.02
1
0.98
0.96
0.94
o.92
Figure 1. Henry Hub Monthly Shape of Scaling Factors
STAFF COMMENTS ocToBER 31,2014
Monthly Solar Capacity Factor
0.50
0.40
0.30
0.20
0.r0
0.00
Figure 2. Monthly Solar Capacity Factor
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 dehcit.
In calculating Grand View'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
STAFF COMMENTS ocToBER 31,2014
this and other solar PURPA facilities, Staff expects ldaho Power to regularly revisit its peak-hour
capacity analysis for future solar contracts.
Solar Integration Charges
The Agreement also contains a solar integration charges that were negotiated and agreed to
by the parties. Although the integration charges are 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 $0.99lMWh for the first year of the
Agreement (2015) and escalates to $1.84/MWh in2036. The equivalent 20-year levelized solar
integration charge would amount to approximately $1.28lMWh.
Idaho Power cunently has 60 MW of existing solar penetration based on recently signed
Oregon contracts. As a result, Grand View's 80 MW spans two penetration levels--4O MW at the
0-100 MW cost and 40 MW at the 100-300 cost. The solar integration charges in the Agreement
are blended costs from these two penetration levels.
Staff believes that the method used by Idaho Power to calculate the solar integration charge
is reasonable. Staffalso believes it is reasonable to base the solar integration charge 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-14-18. In any event, the difference between
the solar integration charge in the Agreement and that proposed in IPC-E- 14- I 8 is very minimal.
Effect on Contract Rates of Staffs Proposed Modifications
Staffs proposed rates are included as Attachment l. If all of the computational
modifications proposed by Staff are made, the avoided cost rates in the Agreement would be
decreased by approximately $2.84 per MWh, levelized over the life of the contract. Payments
from Idaho Power to Grand View would be reduced by approximately $12.8 million over the
2}-year term of the Agreement. Because 100 percent of PURPA costs are recovered in base rates,
or alternatively passed through at 100 percent in Idaho Power's Power Cost Adjustment (PCA),
this difference would be a direct benefit to ratepayers.
STAFF COMMENTS ocToBER 31,20t4
90/l 10 Firmness Requirement
This Agreement does not contain a90lll0 firmness requirement. Instead, it contains
provisions for a combination of a pricing adjustment, a Mechanical Availability Guarantee
(MAG), a solar integration charge, and solar forecasting fees. Idaho Power states that it prefers
that 90/110 firmness be included in all PURPA QF agreements, although Grand View preferred a
MAG and forecasting costs. Idaho Power maintains that the use of a MAG is not a replacement
for the firmness determinations of the 90/110 provisions; however, based on negotiations and an
agreed to price adjustment, the Company states that it is comfortable and 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 five 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 five percent
of its generation estimates, then a corresponding percentage adjustment to the monthly price is
imposed. However, the adjustment is limited to a maximum price reduction of ten 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 because it
provides some assurance that the initial prices calculated and included in the contract for a 20 year
period are based upon accurate estimates. Moreover, the pricing adjustment helps to ensure that
the rates paid to Grand View are commensurate with the degree of energy firmness delivered by
the project. In Staffs 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.
The Agreement includes a MAG that requires the project be mechanically capable of
generating during 85 percent of the hours when the sun is shining. Conceptually, this is the same
requirement that has been applied to several wind QFs. Although Staff has no objection to this
provision, Staff believes it has little value because it is already in the QF's best interest to maintain
STAFF COMMENTS 10 ocToBER 31,2014
a mechanical availability that it as high as possible. Quite simply, if a QF is not mechanically
available, it cannot produce energy and receive payments from the utility.
Finally, the Agreement includes provisions requiring the QF to pay a small charge for solar
forecasting. The solar forecasting charge is capped at 0.1 percent of Idaho Power's annual
payments to the QF. This is the same requirement that has been included in other PURPA wind
agreements in which forecasting has been required. Staff believes this contract provision and the
0.1 percent cap are reasonable.
Staff believes that collectively, the requirements for a price adjustment mechanism, the
MAG, the forecasting charge, and the solar integration charge are a reasonable substitute for the
90/l l0 requirement that has been imposed on intermittent generation in the past.
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. In addition, the parties negotiated a
50/50 split of environment attributes (aka renewable energy credits). Finally, 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 identified by Staff. Staff recommends that the spreadsheet
model used for computing the avoided cost of energy be modified to account for monthly
variations in natural gas price, thus, monthly variations in dispatch costs of Idaho Power's gas-
l1STAFF COMMENTS ocToBER 3t,2014
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 reflect the methodology changes proposed by Stafl obtain concurrence 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 rates, terms, and conditions and declare that all payments Idaho Power
makes to Grand View for purchases of energy will be allowed as prudently incurred expenses for
ratemaking purposes.
Respecttully submitted this 3 l{ day of Octo ber 2014.
Technical Staff: Rick Sterling
i:umisc:comments/ipcel4. l9ksrps comments
Kris'fine A. Sasser
Deputy Attorney General
STAFF COMMENTS t2 ocToBER 31,2014
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Attachment I
Case No. IPC-E-14-19
Staff Comments
10131114 Page I of 8
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Case No. IPC-E-14-19
Staff Comments
1013lll4 Page 2 of 8
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Case No. IPC-E-14-19
StaffCommentsl}l3ll14 Page 3 of 8
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Case No. IPC-E-14-19
Staff Comments
1013ll14 Page 4 of 8
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Case No. IPC-E-14-19
Staff Comments
l)l3ll14 Page 5 of 8
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Case No. IPC-E-14-19
Staff Comments
10131114 Page 6 of 8
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Case No. IPC-E-14-19
Staff Comments
10131114 Page 7 of 8
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Case No. IPC-E-14-19
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10131114 Page 8 of 8
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 3IST DAY oF OCTOBER 2014,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-14.19, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWNG:
DONOVAN E. WALKER
REGULATORY DOCKETS
IDAHO POWER COMPANY
P.O. BOX 70
BOISE,ID 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]
SECRETARY
CERTIFICATE OF SERVICE