20120329Staff 3-20 to IPC.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 6618
RECEIVED
21112 MAR 29 AM 9: 15
PUBLIC
UTILITIES C0MM1SSIC
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 COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE SURROGATE
AVOIDED RESOURCE (SAR) AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING
PUBLISHED AVOIDED COST RATES.
CASE NO. GNR-E-11-03
SECOND PRODUCTION
REQUEST OF THE
COMMISSION STAFF TO
IDAHO POWER COMPANY
The Staff of the Idaho Public Utilities Commission, by and through its attorney of record,
Kristine A. Sasser, Deputy Attorney General, requests that Idaho Power Company (Company)
provide the following documents and information on or before THURSDAY, APRIL 19, 2012.
This Production Request is to be considered as continuing, and Idaho Power Company is
requested to provide, by way of supplementary responses, additional documents that it or any person
acting on its behalf may later obtain that will augment the documents produced.
Please provide answers to each question and any supporting workpapers that provide detail or
are the source of information used in calculations. The Company is reminded that responses pursuant
to Commission Rules of Procedure must include the name and phone number of the person preparing
the document, and the name, location and phone number of the record holder and if different the
witness who can sponsor the answer at hearing if need be. Reference IDAPA 31.01.01.228.
SECOND PRODUCTION REQUEST
TO IDAHO POWER COMPANY 1 MARCH 29, 2012
In addition to the written copies provided as response to the questions, please provide all
Excel and electronic files on CD with formulas activated.
REQUEST NO. 3: In the direct testimony of Lisa Grow at page 12, lines 12-19, and at page
14, lines 15-17, and in the direct testimony of Mark Stokes beginning at page 44, line 14 and
continuing to page 45, line 9, Idaho Power recommends that the Commission establish an authorized
negotiation process and procedure by which QFs can obtain power purchase agreements. However,
neither Idaho Power witness proposes specific details of a process, procedure, or tariff. In the direct
testimony of Rocky Mountain Power witness Paul Clements, beginning at page 2, line 17 and
continuing to page 6, line 20, he proposes that the Commission adopt a new Tariff Schedule 38 for
Rocky Mountain Power. Mr. Clements includes a draft of proposed Schedule 38 as Exhibit No. 202
to his testimony. Would Idaho Power support adoption for itself of a tariff similar to the draft
Schedule 38 proposed by Rocky Mountain Power? If so, please identify and discuss any differences
Idaho Power would propose for its own comparable tariff.
REQUEST NO. 4: Idaho Power proposes that it be permitted to establish a new Schedule
74, which includes policies and procedures for operational dispatch of certain PURPA Qualifying
Facilities, including curtailment during certain circumstances. If the Commission accepted the
Company's proposal to adopt Schedule 74, would integration costs for intermittent QFs be affected?
If so, has Idaho Power attempted to quantify the effect? Would Idaho Power propose to modify its
currently authorized wind integration charge of $6.50 per MWh for intermittent wind generation? If
so, how would Idaho Power propose to modify the $6.50 per MWh charge?
REQUEST NO. 5: The direct testimony of Tessia Park discusses generally the low loading
conditions when the proposed Schedule 74 might require curtailment, and describes a representative
example on pages 23-24. Has Idaho Power conducted any analysis or studies to attempt to estimate
the frequency, duration, and magnitude of curtailments that might be invoked in the future or that
would have been invoked in the past if its proposed Schedule 74 was in place? Please provide a copy
of any analysis or studies. If no analysis or studies have been done, please provide estimates if
possible.
SECOND PRODUCTION REQUEST
TO IDAHO POWER COMPANY 2 MARCH 29, 2012
REQUEST NO. 6: If Idaho Power's proposed Schedule 74 were to be approved by the
Commission and QFs were curtailed during certain low load conditions, would the avoided cost rates
computed based on Aurora analysis be impacted? Has Idaho Power conducted any Aurora analysis to
compute avoided cost rates under an assumption that QFs could be curtailed under certain low load
conditions?
REQUEST NO. 7: Please provide a list of all QFs with approved PURPA contracts, and for
each project list the following: 1) the project nameplate capacity, 2) whether the project has a
generator output limit controls (GOLCs) installed, and 3) whether Idaho Power's proposed Schedule
74 would apply to the project.
REQUEST NO. 8: If Schedule 74 is approved and a QF were curtailed, would Idaho Power
propose to pay the QF for capacity or energy (either, neither, or both) during the period of
curtailment?
REQUEST NO. 9: Idaho Power's proposed Schedule 74 does not address how non-QF long-
term contractual power purchases will be handled in the event of curtailment. Please state the
Company's proposed policy generally, and also specifically address all existing long-term power
purchase agreements.
REQUEST NO. 10: The avoided cost rates computed using an IRP methodology are
typically presented in an FESA as monthly heavy and light load hour prices. If hourly prices are
computed in Aurora, some of which may reflect a value of zero due to surplus conditions, how are
these "zero value hours" captured and reflected in monthly prices contained in the FESA?
REQUEST NO. 11: In the direct testimony of Mark Stokes at page 31, he discusses the
calculation of the avoided cost of capacity in the IRP methodology. He states that the peak-hour
capacity factor for wind, solar and canal drop projects is based on a 90 percent exceedance, but that
for baseload resources (biomass, geothermal) peak-hour capacity factor is reduced from 100 percent
to 92 percent to account for forced outages. Are forced outages also a possibility for wind, solar and
canal drop projects? If so, does Idaho Power believe that the 90 percent exceedance values for wind,
SECOND PRODUCTION REQUEST
TO IDAHO POWER COMPANY 3 MARCH 29, 2012
solar, and canal drop projects should be further reduced to account for the possibility of forced
outages and to remain consistent with the treatment of baseload resources?
REQUEST NO. 12: In the direct testimony of Mark Stokes at page 34, he states that no
carbon adder was used in the Aurora model to calculate the avoided cost of energy for the sample
calculations. Recognizing that Idaho Power believes it would be inappropriate to include a carbon
adder for avoided cost calculations, if a carbon adder consistent with assumptions used in the 2011
IRP were included in the sample calculations, what would be the result?
REQUEST NO. 13: In the direct testimony of Mark Stokes beginning at page 39, line 24 and
continuing to page 40, line 18, he points out that Langley Gulch will be dispatchable while QF
resources are not dispatchable. In the IRP methodology as proposed by Idaho Power, is the lack of
dispatchability of QF resources taken into account in computing an avoided cost rate? If so, can
Idaho Power quantify the value of dispatchability? Please provide that value.
REQUEST NO. 14: Idaho Power proposes that contract lengths be limited to five years, in
part to relieve ratepayers of the risks associated with long-term contracts. Assuming facilities of
equal capacity and 20-year contract lengths, please compare and contrast the risks associated with a) a
QF, b) a utility-owned gas-fired project (such as Langley Gulch, and c) a non-indexed PPA (such as
Elkhorn wind). Please compare the relative magnitude of the risks and identify who bears the risks—
the utility, ratepayers, or project owners.
REQUEST NO. 15: Please clarify whether it is Idaho Power's proposal that published rates
for all resource types 100 kW and smaller be based exactly on the four sample project results
presented in the direct testimony and exhibits of Mark Stokes. If not, does Idaho Power believe that
any change in project characteristics or input data assumptions (e.g., fuel prices, load-resource
balance, generation profile, project size, etc.) would be necessary before sets of published avoided
cost rates could be determined that accurately represent Idaho Power's avoided costs? Please explain.
SECOND PRODUCTION REQUEST
TO IDAHO POWER COMPANY 4 MARCH 29, 2012
REQUEST NO. 16: Please clarify whether it is Idaho Power's proposal that published rates
derived using the IRP methodology be adjusted for seasonality and heavy and light load hours similar
to the methods currently applied to published rates, or whether hourly and seasonal adjustments
would be based on Aurora analysis. For whichever method Idaho Power proposes, please provide,
for each resource type, a complete schedule of proposed published rates that would be included in a
FESA.
REQUEST NO. 17: Avista in this case proposes, among other things, that the capacity and
energy components of published rates be computed separately. The capacity value of a particular
project would be based on its contribution during the utility's system peak hours. The capacity value,
in turn, would then be spread over the hours the project is expected to operate during the year. One
outcome of this approach is that the capacity value of project types with low annual capacity factors
(such as canal hydro and solar) is spread over fewer hours, making rates for these project types much
higher per MWh than for project types with high annual capacity factors (such as biomass and
geothermal). Does Idaho Power agree with Avista's proposed approach for determining capacity
value? If not, please explain why.
REQUEST NO. 18: In the direct testimony of Karl Bokenkamp beginning at page 12, line
21 and continuing to page 13, line 15, he states that Idaho Power is proposing to disregard the
transaction-related costs and use the Aurora market clearing price to set the displaceable incremental
cost for long-term firm, non-PURPA, power purchases whenever they are flowing. Please provide a
reasonable estimate of any transaction-related cost (transmission costs, losses, etc.).
REQUEST NO. 19: Referencing again the testimony referred to in Request No. 18, please
explain why Idaho Power would accept and pay for generation from a QF if, in order to be
accommodated, it required that energy from a firm purchase be resold at market price. Explain why
the value of energy from the QF would not be zero in any hour when a longer-term firm purchase
would have to be sold to accommodate the purchase from the QF.
SECOND PRODUCTION REQUEST
TO IDAHO POWER COMPANY 5 MARCH 29, 2012
REQUEST NO. 20: Idaho Power proposes that the avoided cost of capacity be determined
using a Simple Cycle Combustion Turbine (SCCT) rather than a Combined Cycle Combustion
Turbine (CCCT). Please clarify whether it is the Company's proposal to use a SCCT as the basis for
determining the avoided cost of capacity for all QF resource types. Does Idaho Power believe that it
is equally appropriate to base capacity value on a SCCT for low capacity factor QF resources as for
high capacity factor QF resources such as geothermal or biomass? Please explain.
Dated at Boise, Idaho, this 2, day of March 2012.
Xikme A. Sasser
Deputy Attorney General
Technical Staff: Rick Sterling
i:umisc:prodreq/gnre 11 .3ksrps pr2.doc
SECOND PRODUCTION REQUEST
TO IDAHO POWER COMPANY 6 MARCH 29, 2012
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 8TH DAY OF MARCH 2012,
SERVED THE FOREGOING SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO 1`01J/ER COMPANY, IN CASE NO. GNR-E-1 1-03,
BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE FOLLOWING:
DONOVAN E WALKER
JASON B WILLIAMS
IDAHO POWER COMPANY
P0 BOX 70
BOISE ID 83707-0070
MICHAEL G ANDREA
AVISTA CORPORATION
1411 EMISSION AVE
SPOKANE WA 99202
ROBERT D KAHN
NW & INTERMOUNTAIN POWER
PRODUCERS COALITION
1117 MINOR AVE STE 300
SEATTLE WA 98101
ROBERT A PAUL
GRAND VIEW SOLAR II
15690 VISTA CIRCLE
DESERT HOT SPRINGS CA 92241
THOMAS H NELSON
RENEWABLE ENERGY COALITION
P0 BOX 1211
WELCHES OR 97067
R GREG FERNEY
MIMURA LAW OFFICES PLLC
2176 E FRANKLIN RD
STE 120
MERIDIAN ID 83642
DANIEL E SOLANDER
TED WESTON
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON & O'LEARY
515 N 27TH STREET
BOISE ID 83702
DON STURTEVANT
ENERGY DIRECTOR
J R SIMPLOT COMPANY
P0 BOX 27
BOISE ID 83707-0027
JAMES CARKULIS
EXERGY DEVELOPMENT GROUP OF
IDAHO LLC
802 W BANNOCK ST STE 1200
BOISE ID 83702
JOHN R LOWE
RENEWABLE ENERGY COALITION
12050 SW TREMONT ST
PORTLAND OR 97225
BILL PISKE MGR
INTERCONNECT SOLAR
DEVELOPMENT LLC
1303 E CARTER
BOISE ID 83706
CERTIFICATE OF SERVICE
RONALD L WILLIAMS WADE THOMAS
WILLIAMS BRADBURY DYNAMIS ENERGY LLC
1015 W HAYS ST 776 E RIVERSIDE DR
BOISE ID 83702 STE 15
EAGLE ID 83616
BRAN OLMSTEAD MEGAN WALSETH DECKER
GENERAL MANAGER SR STAFF COUNSEL
TWIN FALLS CANAL CO RENEWABLE NW PROJECT
P0 BOX 326 421 SW 6TH AVE STE 1125
TWIN FALLS ID 83303 PORTLAND OR 97204
TED DIEHL BILL BROWN CHAIR
GENERAL MANAGER BOARD OF COMMISSIONERS
NORTH SIDE CANAL CO OF ADAMS COUNTY ID
921 N LINCOLN ST P0 BOX 48
JEROME ID 83338 COUNCIL ID 83612
TED S SORENSON P E GLENN IKEMOTO
BIRCH POWER COMPANY MARGARET RUEGER
5203 SOUTH I I TH EAST IDAHO WINDFARMS LLC
IDAHO FALLS ID 83404 672 BLAIR AVE
PIEDMONT CA 94611
M J HUMPHRIES ARRON F JEPSON
BLUE RIBBON ENERGY LLC BLUE RIBBON ENERGY LLC
3470 RICH LANE 10660 SOUTH 540 EAST
AMMON ID 83406 SANDY UT 84070
DEAN J MILLER BENJAMIN J OTFO
McDEVITF & MILLER LLP ID CONSERVATION LEAGUE
P0 BOX 2564 P0 BOX 844
BOISE ID 83701 BOISE ID 83702
KEN MILLER MARY LEWALLEN
SNAKE RIVER ALLIANCE CLEAR WATER PAPER CORP
BOX 1731 STE1100
BOISE ID 83701 601 W RIVERSIDE AVE
SPOKANE WA 99201
ENERGY INTEGRITY PROJECT
TAUNA CHRISTENSEN
769N 1100 B
SHELLEY ID 83274
CERTIFICATE OF SERVICE