20110118IPC to NIPPC 23-54.pdf

DONOVAN E. WALKER
Senior Counsel
dwalker(âidahopower.com
1SIDA~POR(I
An IDACORP Company
January 14, 2011
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilties Commission
472 West Washington Street
P.O. Box 83720
Boise, Idaho 83720-0074
Re: Case No. GNR-E~tO-04
IN THE MA ITER OF THE JOINT PETITION OF IDAHO POWER COMPANY,
AVISTA CORPORATION, AND PACIFICORP DBA ROCKY MOUNTAIN
POWER TO ADDRESS AVOIDED COST ISSUES AND TO ADJUST THE
PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP
Dear Ms. Jewell:
Enclosed for filing please find an original and three (3) copies of Idaho Power
Company's Response to the Fourth Production Request of the Northwest and
Intermountain Power Producers Coalition to the Joint Utilties in the above matter.
In addition, enclosed in a separate envelope are four (4) confidential disks
containing confidential documents being produced in response to the production requests.
Please note, this information should be handled in accordance with the Protective
Agreement executed by the parties in this matter.
tô
Donovan E. Walker
DEW:csb
Enclosures
1221 W. Idaho St. (83702)
P.O. Box 70
Boise, ID 83707
DONOVAN E. WALKER (ISB No. 5921)
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
dwalkercæidahopower.com
Inordstrom~idahopower.com
Attorneys for Idaho Power Company
Street Address for Express Mail:
1221 West Idaho Street
Boise, Idaho 83702
r=.. r--). "- ,.,.-
"f'l .~.
Lt;; .
I . '1?'..i" 0~
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT
PETITION OF IDAHO POWER
COMPANY, AVISTA CORPORATION,
AND PACIFICORP DBA ROCKY
MOUNTAIN POWER TO ADDRESS
AVOIDED COST ISSUES AND TO
ADJUST THE PUBLISHED AVOIDED
COST RATE ELIGIBILITY CAP.
)
) CASE NO. GNR-E-10-04
)
) IDAHO POWER COMPANY'S
) RESPONSE TO THE FOURTH
) PRODUCTION REQUEST OF THE
) NORTHWEST AND
) INTERMOUNTAIN POWER
) PRODUCERS COALITION TO THE
) JOINT UTILITIES
)
COMES NOW, Idaho Power Company ("Idaho Powet' or "Company"), and in
response to the Fourth Production Request of the Northwest and Intermountain Power
Producers Coalition to the Joint Utilties dated December 24, 2010, herewith submits the
following information:
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES ~ 1
REQUEST NO. 23: Reference Avista's Initial Comments, page 9 (stating
"Proposals for larger utilty-scale projects, where the developers have both the means
and sophistication to negotiate a QF rate, should be subjected to a negotiated rate").
(a) Please provide, in electronic format, the economic model Avista proposes
to use to negotiate with developers of larger projects.
(b) Please provide a copy of the guidelines Avista proposes to use in said
negotiations.
(c) Please explain what safeguards Avista will employ to insure that all QFs
are treated in a non discriminatory manner.
RESPONSE TO REQUEST NO. 23: Answering hereto on behalf of Idaho Power
Company only, Idaho Power does not have this information. Please see Avista's
response to Northwest and Intermountain Power Producers Coalition's ("NIPPC")
Production Request No. 23.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 2
REQUEST NO. 24: Reference Avista's Initial Comments, page 4 (stating "utilty
customers are paying developers too much under the published rates"). Reference
Rocky Mountain Powets Initial Comments, page 5 (stating "Rocky Mountain Power is
primarily concerned with the increase in power supply costs, and the resulting increase
in rates to its customers that the current published avoided cost using the SAR
methodology causes...") Reference Idaho Powets Initial Comments, page 7 (stating
"Idaho Power is deeply concerned with the increase in power supply costs due to these
contracts, and the resulting increase in rates to its customers, that the current published
avoided cost, SAR methodology, causes.")
(a) Please admit or deny that each utilty is required to pay QFs its full
avoided cost.
(b) Please admit or deny that each utilty is required to pay QFs its full
avoided cost - even if doing so places upward pressure on its retail rates.
(c) If your response in (a) is to deny, please explain the circumstances under
which your utility is excused from paying QFs your full avoided cost.
(d) If your response in (b) is to deny, please explain the circumstances under
which your utilty is excused from paying QFs full avoided cost.
RESPONSE TO REQUEST NO. 24: Answering hereto on behalf of Idaho Power
Company only:
(a) Sections 201 and 210 of PURPA, and pertinent regulations of the
Federal Energy Regulatory Commission ("FERC"), require that regulated electric
utilities, such as Idaho Power, purchase power produced by cogenerators or small
power producers that obtain qualifying facilty ("QF") status. 16 U.S.C. § 824a-3(a).
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 3
The rate a QF receives for the sale of its power is generally referred to as the "avoided
cost" rate and is to reflect the incremental cost to an electric utilty of electric energy or
capacity or both, which, but for the purchase from the QF, such utility would generate
itself or purchase from another source. 16 U.S.C. §§ 824a-3(b), (d). The Idaho Public
Utilities Commission ("Commission") has authority under PURPA Sections 201 and 210
and the implementing regulations of the FERC, 18 C.F.R. § 292, to set avoided costs, to
order electric utilities to enter into fixed-term obligations for the purchase of energy from
QFs, and to implement FERC rules. See Connecticut Light and Power Co., 70 F.E.R.C.
1r 61,012,61,024 (1995).
(b) Please see the Company's Response to NIPPC's Production
Request No. 24(a).
(c) Please see the Company's Response to NIPPC's Production
Request No. 24(a).
(d) Please see the Company's Response to NIPPC's Production
Request No. 24(a).
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 4
REQUEST NO. 25: Reference Rocky Mountain Powets Initial Comments, page
8 (stating "The Commission should balance the desire to stimulate QF development
with the mandate that customers not pay more for QF power than for other resources."
(a) What is Rocky Mountain Powets understanding of the phrase "desire to
stimulate QF Development"?
(b) Please identify the source of that understanding in Commission orders or
otherwise.
(c) Please admit or deny that the Commission has a mandate to stimulate QF
development.
(d) If you deny that the Commission has a mandate to stimulate QF
development please explain the source of your denial in Commission orders or
otherwise.
RESPONSE TO REQUEST NO. 25: Answering hereto on behalf of Idaho Power
Company only, as this question is directed to Rocky Mountain Power only, please see
Rocky Mountain Power's response to NIPPC's Production Request No. 25.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 5
REQUEST NO. 26: Reference Rocky Mountain Powets Initial Comments, page
8 (stating liThe rationale for standard rates is to minimize transaction costs for small
projects."). Reference Avista's Initial Comments, page 8 (stating "Published rates are
intended for smaller projects, in large part to ease the administrative burden of the
developer in negotiating the economic component of the QF contract.") Reference
Idaho Power's Initial Comments, page 9 (stating "The more prescriptive SAR-based
published avoided cost methodology was developed and intended for smaller projects
and the more unsophisticated developers in part to ease the administrative burden on
the developer and to 'level the playing field' in negotiating the economic components of
a QF contract.")
(a) Please explain the basis for that statement and provide supporting
documentation.
(b) Are you aware of any other rationale or intent for standard rates? If so,
please provide documentation for that understanding.
(c) Please document, by category (e.g. legal, engineering, accounting) the
transaction costs associated with negotiating a power purchase agreement with your
utilty.
(d) Please quantify and document the difference in cost to a developer to
negotiate a power purchase agreement with your utilty for a 100 kw power purchase
agreement and the following:
(i) a 150 kw power purchase agreement
(ii) a 500 kw power purchase agreement
(iii) a 1,000 kw power purchase agreement
(iv) a 5,000 kw power purchase agreement
(v) a 10,000 kw power purchase agreement
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 6
(d) (sic)Please provide copies of all internal company manuals, guides,
correspondence, policy statements of whatever form that instructs company personnel
in how to negotiate a power purchase agreement with a QF. Identify the company
personnel who are assigned to such negotiations.
(e) (sic)Please identify and document all efforts (if any) your utilty has
taken to streamline and/or make the QF contract negotiation process as inexpensive,
transparent and efficient as possible.
RESPONSE TO REQUEST NO. 26: Answering on behalf of Idaho Power
Company only:
(a) It is common knowledge that the Surrogate Avoided Resource
("SAR")-based published avoided cost methodology was developed and intended for
smaller projects and the more unsophisticated developers in part to ease the
administrative burden on the developer and to "level the playing field" in negotiating the
economic components of a QF contract. In fact, by its very nature, the SAR-based
methodology is meant to apply only to those "smallet' QF projects that are under 10
average megawatts ("aMW"), with a different methodology, the IPR-based methodology,
to apply to "Iarget' QF projects. The Commission has referenced these notions in
several Orders. See, e.g., Order Nos. 25884 and 22636.
(b) No.
(c) Idaho Power does not have the data to document the cost to a
developer as requested in this question.
(d) See the Company's Response to NIPPC's Production Request No.
26(c).
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 7
(d) (sic)No such documents exist. Randy Allphin and Michael
Darrington are responsible for conducting initial negotiations with proposed QF projects
on behalf of Idaho Power with support from Idaho Powets Legal Department.
(e) (sic)Mr. Allphin and/or Mr. Darrington have personal contact with
each prospective QF project that contacts Idaho Power interested in pursuing a QF
power purchase agreement. Not only is the power purchase contracting process
explained to the prospective project, but information is also communicated regarding the
generator interconnection and transmission study processes. If a potential QF project
continues to express interest in pursuing a contract, the Company coordinates a draft
Firm Energy Sales Agreement to include the project's specific information and continues
to pursue discussion and negotiation of the terms and conditions contained therein.
The process is streamlined, efficient, and as transparent and inexpensive as possible.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 8
REQUEST NO. 27: Reference Idaho Powets Initial Comments, page 9 (stating,
"historical 'unsophisticated' QF project developers...")
(a) Please identify the source of the quotation.
(b) Please define how Idaho Power uses the term "unsophisticated."
(c) Please provide a list of the QF projects with which Idaho Power has an
executed power purchase agreement that it views as being "unsophisticated."
RESPONSE TO REQUEST NO. 27:
(a) The quotation marks were not meant to indicate an outside source
quotation. See The Gregg Reference Manual, 8th ed., p. 58 (quotation marks may be
used when using technical terms, business jargon, coined words, or to indicate irony);
Purdue Online Writing Lab (quotation marks may additionally be used to indicate words
used ironically or with some reservation).
(b) Please see the explanation and context for the quoted language asked
about in NIPPC's Production Request No. 27 on pages 8 through 10 of Idaho Powets
Comments for how Idaho Power "uses the term 'unsophisticated.'"
(c) No such list exists. At this point in time, Idaho Power believes that nearly
all of the parties that it contracts with for PURPA contracts have some familarity with
the power production business and with PURPA. The reference in Idaho Power's
Comments to unsophisticated QF project developers refers generally to: (1) projects
that originated historically during the 1980s and the 1990s, (2) small projects with
developers that have few assets available to them, (3) projects/developers that are not
generally in the power production business and are involved in a different/unrelated
primary business, (4) projects/developers that have not previously been involved with
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 9
the PURPA QF contract negotiation processllittle or no experience with PURPA, and (5)
projects/developers that are unfamilar with the rules, requirements, policies, and
procedures of PURPA and the interconnection/transmission process and requirements
required to connect their projects to Idaho Powets system. For example, a canal
company's .5 megawatt ("MW") irrigation ditch hydroelectric project or a dairy farmets
1.5 MW anaerobic digester project as opposed to Exergy, Shell Wind Energy, General
Electric, Reunion Power and their multiple 10, 15, and 20 MW wind park projects or
Ridgeline with its 80 MW project.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES -10
REQUEST NO. 28: Reference RMP's Initial Comments, page 5 (referencing QF
acquisition through a competitive bidding process).
(a) Please admit or deny that the Idaho PUC has never promulgated
competitive bidding rules or guidelines applicable to utilty resource acquisitions.
RESPONSE TO REQUEST NO. 28: Answering hereto on behalf of Idaho Power
Company only, as this question is directed to Rocky Mountain Power, please see Rocky
Mountain Power's response to NIPPC's Production Request No. 28.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 11
REQUEST NO. 29: Reference Idaho Powets Initial Comments, page 7 (stating
"The additional 678 MW of signed QF wind contracts that have been submitted to the
Commission represent a total payment amount of over $3.9 bilion over the 20-year term
of the agreements. . .. For comparison, Idaho Powets total approved rate base is just
over $2 billon.")
(a) Please explain the relationship between Idaho Powets rate base and
payments to wind QFs.
(b) Please admit or deny that a more logical comparison would be between
Idaho Power's revenue requirement over the same period?
(c) What is Idaho Power's current annual revenue requirement? Please
compare Idaho Powets estimated revenue requirement over the next twenty years,
assuming a 1.5% rate of inflation with the $3.9 bilion number referenced above.
(d) Please identify the dollar amount Idaho Power wil have avoided paying
the identified QFs due to the wind integration discount from its full avoided cost rate,
over the 20 year life the agreements.
(e) Please explain whether Idaho Powets revenue requirement over the 20
year period may increase or decrease with changes in market factors, such as gas
prices and future environmental regulation. Please explain whether the rates owed to
the wind QF developers may change over the 20 year life the agreements due to market
factors.
RESPONSE TO REQUEST NO. 29:
(a) The relationship shows the magnitude of difference in the obligation
entered into with PURPA QF contracts as compared to the total amount of investment
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 12
required to provide service to all of Idaho Powets customers throughout its service
territory. It highlights the fact that the power purchase obligations to PURPA QFs has
and wil continue to have a large effect upon Idaho Power's customers.
(b) Any party is free to make whatever comparison they deem appropriate,
and accordingly support it, or not.
(c) Idaho Powets revenue requirement for its Idaho and Oregon service
territory is approximately $841 millon. The information is available for any part to do
the requested calculation on its own behalf.
(d) The requested calculation has not been done. The wind integration
charge is currently capped at $6.50/MW. The estimated generation for each proposed
PURPA QF project is contained in each project's contract, which is filed and available to
the public at the Commission and on its website.
(e) PURPA QF contract rates are fixed pursuant to the contract. The
Company's revenue requirement, and markets, can increase or decrease over time.
The response to this Request was prepared by with Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES -13
REQUEST NO. 30: Reference Idaho Powets Initial Comments, page 10 (stating
"A system specific analysis, such as the IRP-based methodology, that considers the
characteristics of the specific resource under question is necessary to determine a more
accurate assessment of the costs avoided as a result of adding a specific PURPA
resource. A true avoided cost determination which would be appropriate for renewable
projects that generate renewable energy certificates ("RECs"), would consider the cost
to the utilty to develop and operate a similar project over a 20-year period. This would
take into account the RECs, government tax incentives, accelerated depreciation
allowances, and other similar cost incentives that the utility, and its customers, would
have the advantage of if the utilty were to build the resource, and that currently
generate a double recovery windfall for the QF developer.").
(a) Please reconcile the first sentence's assertion that the IRP methodology
considers the "characteristics of a specific resource" using a "system specific analysis"
with the apparent assumption in the second and third sentences that a "true avoided
cost determination" assumes that the utilty itself is the developer of the project.
(b) Is it Idaho Powets position that its "true avoided costs" are the costs to it
to construct a renewable project taking into account the RECs, etc.?
(c) Under the scenario posited (sic) under the "true avoided" cost assertion,
would the power purchase agreement discount from payments to the developer the
value of the RECs, government tax incentives, accelerated depreciation and other
similar cost incentives?
(d) Please explain what is meant by the phrase "double recovery windfalL."
Please provide documentation of the windfall and quantify it.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 14
(e) Is it Idaho Power's position that federal and state authorized tax incentives
are inappropriate? If not, then please explain the use of the phrase "double recovery
windfall"?
(f) If RECs were provided by a QF and RECs were needed by the utilty,
would the utilty be avoiding the cost of acquiring the RECs elsewhere? Would it be
appropriate to set the PURPA avoided cost rate at a level that reflected the avoided cost
of the RECs delivered to the utilty? Reference California Public Utiities Commission,
133 FERC 1r 61,059, 1r 26 (Oct. 21, 2010) (order denying rehearing).
(g) Is the current SAR methodology (including the discount for wind
integration) designed to compensate wind QFs for the value of the RECs, or just the
value of the energy and capacity provided?
(h) Admit or deny that the value of the avoided cost rate generated in Staffs
strawman wind SAR was higher than the current published avoided cost rates
authorized in Order No. 31025.
RESPONSE TO REQUEST NO. 30:
(a) The quotation in NIPPC's Production Request No. 30 above leaves out
the topic sentence of that paragraph, which immediately precedes the quoted language.
That sentence reads, "First, the SAR methodology does not represent the actual costs
avoided by adding a specific PURPA resource to Idaho Powets resource portolio."
Comments of Idaho Power Company at p. 10. The following sentences that NIPPC
asks to "reconcile" are two examples that, contrary to the SAR methodology, do
consider aspects of the specific resource and the Company's system.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES -15
(b) Yes. One way to calculate the "true avoided costs" for a specific PURPA
project, especially a PURPA project capable of producing Renewable Energy
Certificates ("RECs" or "REC"), is the costs for an electric utilty to construct and operate
a similar facility over an equivalent time period. The costs for the utilty-constructed
project would take into account any available government tax incentives, accelerated
depreciation allowances, or other similar cost incentives, including the value of any
RECs produced and residual value of the facilty at the end of the contract time period,
that the utilty and its customers would enjoy if the utilty had constructed the project.
(c) Under this "posited (sic) scenario" for the "true avoided cost" for a specific
PURPA project, where the PURPA project is capable of producing RECs, and
considering the costs for an electric utilty to construct and operate a similar facility over
an equivalent time period, a utilty's true avoided cost would be equal to the resulting
levelized cost of energy from the utilty constructed project net of all available incentives,
including revenue from REC sales and residual value of the project. PURPA requires
that utilty customers be economically indifferent to the effects of whether power is
purchased from a QF or otherwise acquired (generated or purchased) by the utilty.
Southern California Edison Co., 71 F.E.R.C. P 61,269, 1995 WL 327268 (F.E.R.C.
1995) ("The intention (of PURPA) was to make ratepayers indifferent as to whether the
utility used more traditional sources of power or the newly-encouraged alternatives."). If
a utility were to build a wind resource, the utiity would receive the value of the RECs,
tax incentives, depreciation benefits, and other cost incentives and capture these
savings in the reduced net capital investment; this reduced capital investment cost
would result in a savings to the customer. Construction of a PURPA project would allow
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 16
the utilty to avoid a similar resource, thus the cost being avoided is the net cost
including the various incentives and REC value.
(d) The phrase "double recovery windfall" refers to the issues discussed in the
Company's Responses to NIPPC's Production Requests Nos. 30(b) and (c) and the fact
that if we assume the "avoided cost" paid to the developer is the cost that the utilty
would avoid by not building its own identical project, the value of such things as the
RECs, tax incentives, depreciation benefits, and other cost incentives would be present
in the avoided cost price paid for the energy. The requested documentation and
quantification would vary and depend on each individual project and what was received
for each of the above-listed items and other cost incentives.
(e) No. Please see the Company's Response to NIPPC's Production
Request No. 30(d).
(f) PURPA requires that utilty customers be economically indifferent to the
effects of whether power is purchased from a QF or otherwise acquired (generated or
purchased) by the utilty. Southern California Edison Co., 71 F.E.R.C. P 61,269, 1995
WL 327268 (F.E.R.C. 1995) ("The intention (of PURPA) was to make ratepayers
indifferent as to whether the utilty used more traditional sources of power of the newly-
encouraged alternatives."). If a utilty were to build its own renewable energy project,
the utilty would receive all of the RECs from that project at no additional cost above and
beyond the cost of building the renewable energy project. Thus, if a PURPA project is
allowing the utility to avoid incurring the cost of building this renewable energy project,
then the avoided cost should be based on the capital and operation and maintenance
costs of the "avoided project," which would include no additional cost for RECs.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 17
(g) The current SAR methodology uses a natural gas-fired combined cycle,
combustion turbine as the surrogate avoided resource. Thus, by its very nature, being a
fossil fuel resource, it is not eligible for RECs. However, this natural gas-fired SAR has
significantly different operating characteristics in comparison to a renewable energy
resource, one of the most significant being its dispatchabilty.
(h) Staffs strawman wind SAR and the Commission's Order No. 31025 speak
for themselves.
The response to this Request was prepared by Karl E. Bokenkamp, Director,
Operations Strategy, Idaho Power Company, and Randy C. Allphin, Senior Energy
Contracts Coordinator, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES -18
REQUEST NO. 31: Reference Idaho Powets Initial Comments, page 10 (stating
that a "Problem" with the SAR methodology is that it is "essentially static" and that "The
published avoided cost rates are updated infrequently at best... ").
(a) Please identify the constraints preventing Idaho Power from seeking more
frequent updates of the SAR?
(b) Admit or deny that any Idaho utilty may file a petition to update the
avoided cost rates at any time.
(c) Please explain why Idaho Power, Avista and RMP are seeking to overhall
(sic) the Commission's PURPA implementation methodology rather than seeking an
update of the SAR rates?
RESPONSE TO REQUEST NO. 31:
(a) It is assumed that "updates of the SAR" from NIPPC's Production Request
No. 31 refers to updates of the inputs that go into the calculation of the price in the SAR
methodology. The input which has the most significant impact upon the price is the
natural gas forecast. One of the "constraints" upon updating this input is the release of
the Northwest Power and Conservation Council's natural gas forecast - which is the
only forecast that has consensus from past practice and Commission Orders to be
utilzed in the SAR methodology.
(b) Any person may file a petition seeking any kind of relief, whether valid or
invalid, with the Commission at any time.
(c) Please see the Joint Petition filed by Idaho Power Company, Avista
Corporation, and Rocky Mountain Power in this matter. As discussed at the final
workshop in Case No. GNR-E-09-03, there are many issues beyond a mere update of
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 19
rates in the SAR methodology that all parties to that proceeding expressed some level
of desire to investigate.
The response to this Request was prepared by Randy C. Allphin, Senior Energy
Contracts Coordinator, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 20
REQUEST NO. 32: Reference Idaho Powets Initial Comments, page 12 (stating
"The current state of PURPA development in Idaho has created a situation where the
IRP planning process is being circumvented in order to benefit independent developers
wanting to build generation projects in Idaho Power's service territory.").
(a) Please explain why Idaho Powets IRP process is not robust enough to
adopt (sic) to changing circumstances?
(b) What is Idaho Power's policy on incorporating potential future PURPA
projects into its IRP load and resource planning process? Please document.
(b) (sic)Is it Idaho Powets position that the IRP is a mandate from the
Commission as to how it wil develop future resources? Please explain.
RESPONSE TO REQUEST NO. 32: Idaho Powets integrated resource planning
process is robust and able to adapt to changing circumstances. The Integrated
Resource Plan ("IRP") is updated every two years and in the time between resource
plan filings, changes can be and are made as conditions change. The integrated
resource planning process is designed to identify the best portolio of resources needed
to meet future customer demand, taking into account cost, risk, and environmental
concerns. The 2009 IRP included up to 150 MW of wind generation by 2012, which
was originally contemplated to be acquired through an RFP process. The large quantity
of recent PURPA wind projects has greatly exceeded this amount, and, under PURPA,
Idaho Power is obligated to purchase this energy even though it has not been identified
as part of the preferred portolio in the IRP.
PURPA contracts are not incorporated into the IRP until a contract has been
signed. Past experience indicates PURPA projects can disappear at any point in the
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 21
process leading up to a signed contract. In the IRP process, a forecast of generation
from signed PURPA contracts is prepared and included in the load and resource
balance. This is documented on slide 70 in a presentation to the IRP Advisory Council
on September 21,2010, which can be found at:
http://ww.idahopower.com/pdfslAboutUs/PlanningForFuture/irp/2011/201009211 RPAC
MeetingPresenationSlides Final.pdf
Every two years, once an IRP is filed, the Commission "accepts" the plan for
filng. This language is very specific in recognition that it is not an "approval" of the plan,
and that deviations from the plan may be warrnted as conditions change. The near-
term and long-term action plans contained in the IRP detail Idaho Power's expected
actions as long as the assumptions made in the IRP continue to be valid.
The response to this Request was prepared by M. Mark Stokes, Manager, Power
Supply Planning, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 22
REQUEST NO. 33: Reference Idaho Powets Initial Comments, page 13 (stating
"Actual performance of the wind project under contract to Idaho Power during the
summer of 2010 suggests that a 5 percent capacity expectation is accurate.")
(a) Please provide documentation, including workpapers supporting that
assertion.
RESPONSE TO REQUEST NO. 33: Idaho Power uses 90th percentile
streamflow conditions to forecast hydro generation for peak-hour planning as described
on page 57 of the 2009 Integrated Resource Plan. Likewise, for peak-hour resource
adequacy, Idaho Power continues to assume 90th percentile streamflow conditions to
project peak-hour hydroelectric generation. The 90th percentile means that streamflows
are expected to exceed the planning criteria 90 percent of the time and to be worse than
the planning criteria only 10 percent of the time.
Idaho Power applies the same 90th percentie planning criteria to wind generation
to calculate a peak-hour wind capacity factor. Under these assumptions, the following
calculations were made:
. July 2010 Peak Hours: 4:00 p.m. to 8:00 p.m. every day during the
month
. Nameplate Wind Generation in July 2010: 199 MW
. Actual 90th Percentile Wind Generation: 8 MW
. Calculated Wind Capacity Factor: 4.0 percent (8 MW divided by 199
MW)
The peak-hour wind generation capacity factor can be calculated for the winter
period using the same techniques. The winter peak often occurs during the time period
from early December through mid-January and Idaho Power customers set a winter
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 23
system peak during the identified time period on Thursday, December 10, 2009. A
reasonable winter peak period can be defined as December 7 through January 15.
. Measurement Period: December 7, 2009, through January 15, 2010,
during peak hours. Peak hours are defined to be the three-hour period
from 7:00 a.m. to 10:00 a.m. plus the three hour period from 5:00 p.m.
through 8:00 p.m. every day during the measurement period.
. Nameplate Wind Generation (during the period): 173 MW
. Actual 90th Percentie Wind Generation: 0 MW
. Calculated Wind Capacity Factor: 0 percent (0 MW divided by 173 MW)
As demonstrated above, applying the same planning criteria that Idaho Power
uses for resource planning to wind generation results in a calculated wind capacity
factor lower than five percent (measured during the winter peak period of 2009-2020
and during the July 2010 summer peak period). The two time periods studied suggest
that the five percent capacity factor applied to wind generation is generous.
The response to this Request was prepared by Thomas A. Noll, Planning
Analyst, Idaho Power Company, in consultation with Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 24
REQUEST NO. 34: Reference Idaho Power's Initial Comments, page 13 (stating
"However, the quantity of PURPA development currently being seen in Idaho was never
contemplated when the PURPA rules were established by the Commission")
(a) What was the quantity of PURPA development contemplated by the
Commission when the PURPA rules were established by the Commission? Please
provide supporting documentation.
RESPONSE TO REQUEST NO. 34: The quoted sentence does not state, ". . .
the quantity of PURPA development contemplated by the Commission" as referenced in
NIPPC's Production Request No. 34; it states, n. . . the quantity of PURPA development
currently being seen in Idaho was never contemplated when the PURPA rules were
establish(ed) by the Commission." This is a reference generally to the notion that when
PURPA was enacted, it was envisioned as a way to allow small, renewable projects to
be developed, projects that would be considered too small by utilty standards. See,
e.g., Southern California Edison Co., 71 F.E.R.C. P 61,269, 1995 WL 327268 at *6
(F.E.R.C. 1995) (Congress intended PURPA to diversify generation fuel mix and
encourage renewable technologies). At least for Idaho Power's system, this notion
proved to hold relatively true for approximately the first 20 years of PURPA. See
Petition of Idaho Power, Avista Corporation, and Rocky Mountain Power, Attachment
NO.1. However, with the emergence and proliferation of large wind PURPA projects,
since approximately 2005, this has changed. Id. As to a quantification of what the
Commission contemplated, the Commission can speak for itself.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 25
REQUEST NO. 35: Reference Idaho Powets Initial Comments, page 14.
(a) Please provide a copy of the Operating Plan for the entire year.
RESPONSE TO REQUEST NO. 35: The requested information is confidential
and contains forward looking information.
Although the information is confidential, Idaho Power is wiling to make the
portions of the Operating Plan that are shared with the Customer Advisory Group
available for review at the offices of Idaho Power. Please contact Doug Jones (388-
2615) or Camila Victoria (388-5821) to make an appointment to review this information.
The data used to prepare Figures 1 and 2 is provided in Response to NIPPC's
Production Request No. 36.
The response to this Request was prepared by Karl E. Bokenkamp, Director,
Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 26
REQUEST NO. 36: Reference Idaho Powets Initial Comments, page 15.
(a) Please provide all supporting documentation and workpapers used to
prepare Figure 2.
RESPONSE TO REQUEST NO. 36: The requested information is provided in
Excel format on the confidential CD. This information is confidential and is being
provided pursuant to the Protective Agreement in this docket.
The response to this Request was prepared by Karl E. Bokenkamp, Director,
Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 27
REQUEST NO. 37: Reference Idaho Powets Initial Comments, page 16.
(a) Please provide all supporting documentation and workpapers used to
prepare the table on that page.
RESPONSE TO REQUEST NO. 37: Please refer to the Company's Response
to NIPPC's Production Request No. 36 and the additional information provided on the
confidential CD. This information is confidential and is being provided pursuant to the
Protective Agreement in this docket.
The response to this Request was prepared by Karl E. Bokenkamp, Director,
Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 28
REQUEST NO. 38: Reference Idaho Powets Initial Comments, page 17.
(a) What is the expected impact on the planned Hemmingway (sic) to
Boardman transmission project on the transfer rights identified on that page. Please
provide documentation and workpapers supporting your response.
RESPONSE TO REQUEST NO. 38: The Boardman to Hemingway transmission
line is expected to provide 850 MW of import capability and 1 ,300 MW of export
capabilty. Idaho Powets IRP has identified a need for the Boardman to Hemingway
transmission project to allow Idaho Power to import electricity from the Pacific
Northwest to Idaho. It is unknown at this time if any additional export capacity wil be
available, and wil not be known until the final allocation of the line is determined based
on the participation by other equity partners and those requesting service on the path.
The estimated capacity of the new line is presented on page 83 of Idaho Powets 2009
Integrated Resource Plan; however, at the time the IRP was prepared, the estimated
export capacity was 1 ,400 MW. Idaho Power's 2009 Integrated Resource Plan can be
found at:
http://ww.idahopower.com/pdfs/ AboutUs/PlanningForFuture/irp/2009/2009IntegratedR
esourcePlan.pdf
The response to this Request was prepared by M. Mark Stokes, Manager, Power
Supply Planning, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 29
REQUEST NO. 39: Reference Idaho Powets Initial Comments, page 18.
(a) Please provide copies of the heavy and light load hour forward market
forecasts for the time frame referenced in Figure 3.
RESPONSE TO REQUEST NO. 39: The requested information is provided
under the "Prices" tab in the Excel file provided by the Company in its Response to
NIPPC's Production Request No. 36. This information is confidential and is being
provided pursuant to the Protective Agreement in this docket.
The response to this Request was prepared by Karl E. Bokenkamp, Director,
Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 30
REQUEST NO. 40: Reference RMP's Attachment to NIPPC Request 3(b), at p.
2 of 12 (stating that Mr. Bruce Griswold stated that he "wish(ed) we (private developers)
would all just go away").
(a) Please admit or deny that Mr. Griswold made the statement, or a
substantially similar statement.
(b) Has Mr. Griswold ever made such a statement, or a substantially similar
statement?
(c) Does Mr. Griswold wish private developers would just go away?
(d) Would Mr. Griswold prefer that Rocky Mountain Power build all of its own
generating resources, rather than contract with private developers?
(e) Please provide Mr. Griswold's job description and describe Mr. Griswold's
responsibilties with regard to PURPA contracts and developments.
(f) Was Mr. Griswold speaking on behalf of Rocky Mountain Power when he
made that statement?
(g) If Rocky Mountain Power objects to (a) of this question on grounds of
hearsay or denies the statement, please provide the name, address, and phone number
of the person who sent the emaiL.
RESPONSE TO REQUEST NO. 40: Answering hereto on behalf of Idaho Power
Company only, as this question is directed to Rocky Mountain Power, please see Rocky
Mountain Power's response to NIPPC's Production Request No. 40.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 31
REQUEST NO. 41: Reference Idaho Powets Initial Comments, at page 19
(stating transmission upgrades for PURPA wind projects "may actually increase the cost
to customers even more").
(a) Admit or deny that PURPA developer (sic) pay for interconnection costs.
(b) Admit or deny that PURPA developers in the past have paid for 75% of up
front network upgrades, and receive no refund for 25% of the costs. Reference Order
No. 32136.
(c) If the response to (b) is to admit, admit or deny that under this approved
framework ratepayers never pay for 25% of the network upgrades caused by a PURPA
development. Admit or deny that ratepayers defer payment of 50% of said Network
Upgrades.
(d) Admit or deny that ratepayers pay for 100% of interconnect facilities and
network upgrades necessary to bring a Company-owned generation to load.
RESPONSE TO REQUEST NO. 41:
(a) PURPA QF projects are solely responsible for the interconnection costs
required to interconnect their proposed projects to Idaho Powets system.
(b) PURPA QF projects are almost always responsible for the network
upgrades, or transmission upgrades, required to bring their energy from the point of
interconnection with Idaho Powets system to load. The Commission has the authority
and jurisdiction to allocate the costs of required transmission upgrades necessary to
integrate PURPA generation facilties into Idaho Powets system, either entirely to the
PURPA project or by some sharing "formula," as was done in Case No. IPC-E-06-21
("the Cassia case"). The Commission has exclusive authority and jurisdiction over the
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 32
interconnection and allocation of interconnection costs for PURPA QFs when an electric
utiity is required to interconnect under 18 C.F.R. § 292.303 of the FERC PURPA
regulations (Le., when the QF's entire output is sold to a regulated utilty). 18 C.F.R. §
292.306.See Standardization of Generator Interconnection Agreements and
Procedures, FERC Stats. & Regs. 1r 31,146 (2003) ("Order No. 2003"); and
Standardization of Small Generator Interconnection Agreements and Procedures,
FERC Stats. & Regs.1r 31,180 (2005) (Order No. 2006, p. 135, 1r 516). Under FERC
rules, interconnection costs, including all reasonable costs of connection, switching,
metering, transmission, distribution, safety provisions, and administrative costs caused
solely by such QF interconnection, may be assessed by the Commission against a QF.
18 C.F.R. §§ 292.306(a), (b); 292.101.7.
The Generator Interconnection Agreement ("GIA") approved by the Commission
in Order No. 32136 (Sawtooth Wind) referenced by NIPPC's Production Request No. 41
is the second instance where the Commission has approved a sharing formula to a
PURPA QF outside of PURPA QF projects located in the Twin Falls queue and parties
to the Cassia case settlement. The first instance where the Commission authorized a
sharing formula of transmission upgrade costs outside of the Twin Falls queue was in
Case Nos. IPC-E-06-34 and IPC-E-06-35, for Hot Springs Windfarm and Bennett Creek
Windfarm, respectively. These two projects shared the same developer and the
interconnection and the same GIA. The Sawtooth Wind project wil be interconnected to
the same transmission line as the Bennett Creek and Hot Springs Wind projects and the
network transmission upgrades required wil have a similar impact. Therefore, as a
similarly situated project, the GIA includes a cost sharing allocation as defined in the
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 33
Cassia case, and subsequently approved by the Commission for the Bennett Creek/Hot
Springs GIA.
In the Cassia case, the Commission approved a settlement which implemented a
cost-sharing arrangement (the "Cassia Formula") under which Idaho Power wil
contribute 25 percent of the cost of the needed transmission upgrades, Cassia wil
make a non-refundable 25 percent contribution in aid-of-construction ("CIAC") to
support the transmission upgrades, and Cassia wil make an advance in aid-of-
construction ("AIAC") for the remaining balance of the cost of the upgrades. The AIAC
wil be refunded to Cassia over time if it fully performs its Firm Energy Sales Agreement
with Idaho Power.
In Order No. 30414, the Commission concluded that use of the Cassia Formula
was appropriate for Cassia Wind Farms, as well as the other PURPA generation
projects in the Twin Falls 138 kilovolt transmission queue. However, the Commission
did not authorize the Company to automatically apply the Cassia Formula in other
locations on its system where transmission upgrades would be required. The
Commission indicated that application of any terms or conditions approved as a part of
the settlement in the Cassia case to other QF interconnection requests "wil depend on
the specific characteristics of that situation." Order No. 30414, p. 11.
(c) Please see the Company's Response to NIPPC's Production Request No.
41(b).
(d) If the Commission determines that the investment is prudently incurred
and required to provide service to the public, then it is included in customer rates as
determined by the Commission.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 34
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 35
REQUEST NO. 42: Reference Idaho Powets Initial Comments, at page 23
(stating that the average bid into the 2012 RFP was between $85/MWh and $150/MWh,
compared to the current $82.38/MWh rate being "put" to Idaho Power by wind QFs).
(a) Admit or deny that the $82.38/MWh figure does not include a reduction for
the $6.50/MWh wind integration rate.
(b) Provide the 20-year levelized rate containing an adjustment for the wind
integration charge currently approved by the Commission.
(c) Admit or deny that the published rates being "put" to Idaho Power by QFs
is lower than any bids made into the RFP. If the response is to deny, please provide
your estimate for value of the RECs that may have been included, and supporting
documentation for that REC value estimate, and the redacted bid.
RESPONSE TO REQUEST NO. 42:
(a) The $82.38/megawatt-hour ("MWh") figure reported on page 23 of Idaho
Power's Comments is the current published rate levelized price for a project that would
come on-line during 2011 without a reduction for wind integration.
(b) The present published avoided cost rates for projects delivering energy to
Idaho Power are identified in Attachment 3 of the Commission's Order No. 31025 dated
March 16, 2010. The wind integration charge is specified on page 8 of the
Commission's Order No. 30488 dated February 20, 2008, and is capped at $6.50.
(c) As noted on page 23 of Idaho Powets Comments, "The 20-year levelized
prices (of the projects bid into the 2012 Wind RFP) ranged from approximately $85 per
MWh to almost $150 per MWh." At the time of the 2012 Wind RFP (May 2009), the 20-
year levelized published avoided cost for a non-fueled project with an on-line date of
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 36
2012 delivering energy to Idaho Power was $95.56 per MWh. Order No. 30744,
Appendix B, p. 1, March 12, 2009. In May 2009, the wind integration charge for a 20-
year project with an on-line date of 2012 was capped at $6.50 per MWh. Order No.
30488, p. 8, February 20, 2008. Subtracting the wind integration charge from the
levelized published avoided cost leads to a 20-year levelized published avoided cost of
$89.06 per MWh, including the wind integration charge. A projection of renewable
energy credit prices is shown in Figure 10.1 on page 106 of Idaho Powets 2009
Integrated Resource Plan.
The response to this Request was prepared by Tom Noll, Power Supply Senior
Planning Analyst, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 37
REQUEST NO. 43: Reference the website for IdaWest Energy, describing the
company's 50% ownership of several hydropower resources, available online at
http://02e5106.netsolhost.com/tablehyd.htm.
(a) Admit or deny that IdaWest Energy is a subsidiary of Idaho Powets parent
company, IdaCorp. Admit or deny the (sic) Idaho Power and IdaWest Energy are
affiliates.
(b) Are any of the eight hydropower projects listed currently selling their
electrical output under PURPA contracts? If so, identify which project and the
purchasing utility. Please provide the contracts.
(c) Does Idaho Power believe that these QF projects are among the QF
projects for which ratepayers are overpaying?
(d) Are the rates in these contracts above or below the Mid-C rates as
projected on Idaho Powets graph on page 18 of its Initial Comments.
RESPONSE TO REQUEST NO. 43:
(a) Idaho Power and IdaWest Energy are both wholly owned by IdaCorp, and
are affilates.
(b) Idaho Power currently has contracts to purchase energy from four projects
of which IdaWest has 49 percent or less level of participation in. Those projects are:
Falls River, Hazelton B, Wilson Lake, and Lowline CanaL. All are small hydropower
contracts PURPA OF contracts that have been filed with, and approved by, the
Commission. The other projects have contracts with Pacific Gas and Electric, and are
under the jurisdiction of the California Public Utilities Commission.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 38
(c) No special consideration was given to these projects over any other
PURPA QF project that the Company has contracted with. These contracts contain all
applicable terms and conditions according to the Commission's Orders that were
applicable at the time these contracts were executed. All were approved by the
Commission.
(d) The Company has not done the exact comparison indicated in NIPPC's
Production Request No. 43(d). The contract rates and Figure 3 on page 18 of Idaho
Power's Comments are available for anyone to make this comparison.
The response to this Request was prepared by Randy C. Allphin, Senior Energy
Contracts Coordinator, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 39
REQUEST NO. 44: Reference Idaho Powets investment relations presentation
dated April 1, 2010, at slide 30 (stating Langley Gulch wil be "Capable of integrating
intermittent, alternative resources such as wind and solat'), available online at
http://ww.idacorpinc.com/pdfs/presentations/MW Analyst Pres 3 10 II i. pdf.
(a) Admit or deny that Langley Gulch increases the level of wind penetration
the Company can safely integrate.
(b) Admit or deny that the Company's gas peaking plants (Bennet (sic)
Mountain and Danskin) can be used to integrate wind. Has the Company used Bennet
(sic) Mountain or Danskin to integrate wind?
(c) Admit or deny that Idaho Power believed in its 2007 Wind Study that it
could safely integrate 600 to 900 MW of wind.
(d) Which of the following resources did Idaho Power consider in its 2007
Wind Study in its determination that it could safely integrate 600 to 900 MW of wind:
(i) Langley Gulch.
(ii) Bennet (sic) Mountain.
(iii) Danskin.
(e) Considering all of the resources in (d), what level of wind penetration does
Idaho Power believe it can safely integrate?
RESPONSE TO REQUEST NO. 44:
(a) When operating, the Langley Gulch combined-cycle, combustion turbine
wil provide additional operating reserves beneficial to integrating wind generation.
When the plant is not being operated due to economics, primarily light load hours, the
plant will not be providing additional operating reserves and wil not increase the amount
of wind generation Idaho Power can safely integrate on its system.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 40
(b) Idaho Powets gas peaking units can be used to integrate wind
generation; however, similar to Langley Gulch, they must already be running in order to
provide additional operating reserves. Gas peaking plants by nature do not run at high
capacity factors and, therefore, Idaho Power cannot rely on these units to be running in
order to integrate wind generation.
(c) The results of Idaho Powets 2007 wind integration study indicated that up
to 600 MW of wind generation could be safely integrated on its system. The study also
indicates that when the 600 MW level is reached, the study should be updated to re-
evaluate the capability of the system to integrate additional wind generation.
(d) The results of Idaho Powets 2007 wind integration study indicated that up
to 600 MW of wind generation could be safely integrated on its system. The 2007 study
did not include any of the listed natural gas resources. Langley Gulch was not
contemplated at the time the study was being performed, and as mentioned previously,
the gas peaking units are not able to provide consistent, reliable operating reserves to
help integrate wind.
(e) Idaho Power is in the process of updating its wind integration study and is
unable to estimate an upper limit at this time.
The response to this Request was prepared by M. Mark Stokes, Manager, Power
Supply Planning, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 41
REQUEST NO. 45: Reference Idaho Powets Initial Comments at page 18
(containing a graph of Mid C prices and light load PURPA rates).
(a) Did Idaho Power adjust the amount of wind online for the online dates set
in the contracts before the Commission, many of which are not projected to come online
until 2013 or 2014? Provide supporting documentation.
(b) Explain how Idaho Power generated the Mid-C price profile. Can Idaho
Power enter into a 20-year contract today for energy and capacity at the rates contained
for Mid-C prices?
(c) Admit or deny that Idaho Power concluded in its most recent wind
integration study that wind integration charges decrease as market prices decrease.
(d) Please explain why in Idaho Powets 2007 wind integration study, Idaho
Power proposed to use "historic" Mid-C prices, including average prices from 2000 at
132/MWh, but in the graph in Idaho Powets Initial Comments it uses the Mid-C prices
from 2010. Reference Enernex 2007 Idaho Power Wind Study, at p. 5.
(e) Admit or deny that Mid-C prices between now and 2020, or 2031, are
unpredictable, and could be significantly higher than those in Idaho Powets graph.
(f) Please generate the same graph with a Mid-C price curve from the dates
used in Idaho Powets 2007 wind study -- 1998, 2000, and 2005. Reference Enernex
2007 Idaho Power Wind Study, at p. 5. Please also adjust the PURPA rate to include
the wind integration charge.
RESPONSE TO REQUEST NO. 45:
(a) The graph on page 18 of Idaho Powets Comments was constructed using
information from the November 2010 Operating Plan, including the Cogeneration and
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 42
Small Power Production ("CSPP") forecast used in the November 2010 Operating Plan.
However, the CSPP forecast used in the November 2010 Operating Plan did not include
all of the PURPA wind projects with signed contracts. Of the over 1,166 MW of wind
generation referenced in Idaho Powets Comments, only 551 MW were included in the
graph on page 18 of Idaho Powets Comments. The on-line dates used in the CSPP
forecast were based on the information available at the time the CSPP forecast was
created. However, over 495 MW of wind projects with signed contracts plus another
120 MW in contract discussions for a total of 615 MW were not included in the graph on
page 18 of Idaho Powets Comments. If these projects had been included, the annual
surpluses represented on the graph would have increased by approximately 185 MW
(( 495 MW + 162 MW) x 30% capacity factor = 184.5 MW).
For supporting information, please see the "CSPP Forecast column" in
Attachment No. 1 to Idaho Powets Comments. Also, please see the Company's
Response to NIPPC's Production Request No. 36
(b) Idaho Powets forward price curve for Mid-C is based on market
information provided by brokers, settlement data provided by the Intercontinental
Exchange, observed bids and offers on electronic trading platforms, and actual
transactions. In the event individual months within a quarter or calendar strip are not
readily available, assumptions are made using available data from similar instruments
and terms. Escalators are used to shape terms that are too far out into the future to rely
on actual observed transactions or market quotes. These escalators are derived by
following trends set in the preceding years where data is available. The profile of
annual Mid-C light load prices shown in the graph on page 18 of Idaho Powets
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 43
Comments was constructed by averaging the monthly Mid-C light load forward prices
over each year.
In the current market, it is unlikely that Idaho Power could enter into a 20-year
contract today for energy and capacity at the rates in the graph on page 18 of Idaho
Powets Comments for Mid-C prices. Conducting a request for proposals process
would provide additional information regarding counterparties interest in executing
longer-term transactions. Based on information Idaho Power has received from
brokers, financial swaps are potentially available through the 2016-2017 time frame.
(c) Idaho Powets February 2007 wind integration summary states:
Changes in Electricity Price Levels: Future
fluctuations in the overall level of wholesale market
prices for electricity are not accounted for in the study.
Market prices wil impact the overall cost of integrating
wind as Idaho Power utilzes its transmission system
to access markets to purchase and sell electricity.
Although the study did not address this issue, as a general concept, integration
costs should decrease as market prices decrease in that, in the original study, the cost
associated with integrating wind is primarily related to the lost opportunity cost of sellng
surplus hydroelectric energy into the market. At higher market prices, the lost
opportunity cost (or cost of integrating wind) would be higher.
(d) Idaho Powets 2007 wind integration study focused on three different
types of water years (low, normal, and high) in order to evaluate the impact of varying
water conditions on the abilty to integrate wind generation. Historical data was
evaluated in the study so that actual water and market conditions, which are highly
correlated, could be evaluated. The data in Idaho Powets Comments was chosen
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 44
simply because it is the most current data that reflects current and projected market
conditions.
(e) Mid-C prices over the next 20 years could be higher or lower than those
shown in Idaho Powets chart.
(f) Idaho Power has not created the requested graph. If NIPPC would like to
construct this graph, the data is available to them. The annual light load surplus data
was provided in the Company's Response to Production Request No. 36. Mid-C and
Palo Verde wholesale electricity market price data (inflation adjusted to 2005 level) is
included in Appendix F (page 85) of Idaho Power's February 2007 Wind Integration
study. The study is available on Idaho Powets website at:
http://ww.idahopower.com/pdfs/AboutUs/PlanningForFuture/wind/Petition ReviseAvoidedCost
Rates1.pdf?id=238&.pdf
The response to this Request was prepared by Karl E. Bokenkamp, Director,
Operations Strategy, Idaho Power Company, and M. Mark Stokes, Manager, Power
Supply Planning, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 45
REQUEST NO. 46: Reference Order No. 30892, p. 6 (estimating that Langley
Gulch wil cost $126/MWh); see also Comments of the Commission Staff, Case No.
IPC-E-09-34, p. 9 (May 3, 2010) (stating Langley Gulch's levelized cost wil be
$111.13/MWh).
(a) Provide updated levelized price estimates for Langley Gulch in $/MWh
ratepayers wil pay for its output. If the estimate is substantially different from those
quoted above, please explain why.
(b) Please explain whether the estimate in (a) is greater or less than the
current, published avoided cost rates.
(c) Please explain whether the estimate in (a) is greater or less than the rates
that would be generated for a QF project in the IRP method.
(d) Please use the inputs for the Langley Gulch plant into the IRP
methodology, and provide the avoided cost rate that the IRP methodology would
generate for Langley Gulch.
(e) If the rates customers wil pay for Langley Gulch are higher than the rates
generated in either (or both) of the two PURPA methodologies approved by the Idaho
Commission, is it fair to say that ratepayers are paying a premium for Company-owned
power? Please explain.
(f) Why would the rates generated in a surrogate model for a CCCT be
different from the rates charged to ratepayers for Idaho Powets own CCCT it is
currently building?
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 46
(g) With regard to Avista, why are the rates different in the SAR than for the
Lancaster Plant? Are the Lancaster rates greater or lower than the SAR rates? Please
explain.
RESPONSE TO REQUEST NO. 46:
(a) The calculated, levelized rate of the Langley Gulch project is substantially
dependent on the capacity factor assumption used to calculate the rate. At higher
capacity factors, the levelized cost wil be less because the plant would generate more
MWhs over which to spread the fixed costs. Conversely, lower capacity factor
assumptions reduce the MWhs and the levelized rate is higher. Therefore, the rates
quoted in the question above are stil valid estimates of the levelized cost of the Langley
Gulch project. The actual annual average cost of the electricity produced by the plant
will not be known until it is in operation and it wil vary year-to-year depending on the
actual amount the plant is in operation.
(b) The range of estimated, levelized rates referenced in the Company's
Response NIPPC's Production Request No. 46(a) above are higher than the current
published avoided cost rates. However, if an equivalent capacity factor is used for
Langley Gulch, the resulting levelized price is lower than published avoided cost rates.
Please see the Company's Response to NIPPC's Production Request No. 46(d) below.
This ilustrates the additional value Idaho Power gains by having the abilty to dispatch
the plant. The Langley Gulch plant wil only run when Idaho Power needs it to serve
load or when it is "in the money" when compared to market prices and surplus energy
that can be sold into the market at a profit to benefit customers. A PURPA project is
incented to produce as much electricity as possible regardless of Idaho Powets needs,
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 47
or whether it is more expensive than market priced power. This gets at the heart of the
issue in this case, as Idaho Power must often sell this surplus energy at a loss in the
market.
(c) Using the IRP methodology, the calculated rate for any QF project wil
depend on the amount and shape of the energy delivered to Idaho Power. The
calculated rate would therefore be different for each project and would be based on the
value provided to Idaho Power and its customers.
(d) The 20-year, levelized rate calculated for the Langley Gulch project using
the IRP methodology is $75.88, which is based upon a capacity factor of approximately
90 percent. The difference between this amount and the higher Idaho Power levelized
estimates are due to the amount of energy delivered to Idaho Power when it was not
needed and has to be sold into the market, and the inabilty for Idaho Power to dispatch
the PURPA project.
(e) No. Please see the Company's Responses to NIPPC's Requests Nos.
46(a) and (b) above.
(f) Using the "IRP Methodology" to establish avoided cost rates, the Langley
Gulch plant is modeled in AURORA as a zero cost resource and therefore it wil be
dispatched almost all of the time. This correctly models the incentive for PURPA
projects to generate as much electricity as possible. When the Langley Gulch project is
modeled under a utilty operation scenario, there is a dispatch cost associated with
running the plant and it wil only be dispatched when it is needed to serve load or when
it is "in the money." Although the levelized price is higher under this scenario, the total
cost is less.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 48
(g) Answering hereto on behalf of Idaho Power Company only, as this
question is directed to Avista only, please see Avista's response to NIPPC's Production
Request No. 46.
The response to this Request was prepared by M. Mark Stokes, Manager, Power
Supply Planning, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 49
REQUEST NO. 47:
(a) Admit or deny that QF wind contracts impose no fuel cost risk on the utilty
or its ratepayers.
(b) Admit or deny that the fuel cost for Bridger increased in the 2010 NPSE
and PCA filings, and that the Commission authorized recovery for that increase from
ratepayers.
(c) Admit or deny that PGE estimated that the Boardman coal plant wil need
$510 million in upgrades to operate in environmental compliance until 2040.
(d) Please provide the cost to Idaho Power for upgrades to Boardman PGE
has proosed (sic) under Bart ILL, for operation through 2020. Admit or deny that
Boardman could shut down before 2020 if the Sierra Club lawsuit in federal court is
successfuL.
(e) Wil Idaho Power ratepayers pay for Boardman expenses and pollution
control upgrades necessary to operate until 2020? Wil Idaho Power ratepayers pay for
any capitalized expenses associated with Boardman regardless of whether the plant
closes in 2020, or some earlier date?
RESPONSE TO REQUEST NO. 47:
(a) QF projects impose significant risks on Idaho Power and its customers.
First, on a longer-term basis, there is the risk that a QF wind project wil not produce its
expected or forecast amount of generation over a monthly, yearly, or multiple year
periods. In this instance, the utilty and its customers would have received less energy
from the subject QF than it originally planned to receive, potentially resulting in
additional market purchases or increased generation from other utiliy owned resources,
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 50
which would subject the utilty and its customers to market or fuel risk. If the utilty had
known the QF was not going to produce as originally anticipated, Idaho Power might
have entered into other arrangements to hedge the additional fuel or market risk. The
risks vary from under-producing during a given month to a QF wind project being
delayed for multiple years, or never being constructed.
Second, on a shorter-term basis, but continuing for the life of the QF contract, the
utility and its customers are continually subjected to additional market risk as a result of
the purchases or sales made to accommodate the intermittency of the wind generation.
Similarly, the utilty and its customers also are subject to the fuel risk associated with the
additional generation necessary to provide sufficient up and down regulation and ensure
system reliabilty to accommodate intermittency of the QF wind generation.
In addition to the risk that a project mayor may not be developed on the
proposed schedule, wind is an intermittent resource and forecasts of wind generation
may overstate or understate the actual energy delivered to the Idaho Power system due
to the variable nature of the wind. Idaho Power balances the load and resources on a
variety of time horizons from 20 years in integrated resource planning to instant-by-
instant balancing of load and generation in real-time operations. In the situations where
the delivered QF energy is less than anticipated, Idaho Power may need to acquire
additional resources to meet the customer load. Depending on the time of year and the
regional energy market, Idaho Power customers may benefit when the delivered wind is
less than forecast because the energy purchases may be at rates less than the
published PURPA avoided cost rates paid to the wind developers for their energy. In
the situations where the delivered energy is greater than anticipated, Idaho Power
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 51
would likely either reduce generation at another project or sell the excess energy into
the market. Market sales may be at prices less than the published PURPA avoided cost
rates paid to the wind developers for their energy. The QF contracts are generally
structured so that Idaho Power must take the energy when QF project delivers the
energy, whether or not Idaho Power has a need for the energy and regardless of the
existing market conditions at the time of energy delivery.
(b) A cost increase for the Bridger plant in base level power supply expense
and the Power Cost Adjustment forecast was approved by the Commission in Order No.
31093 issued on May 28,2010.
(c) In Portland General Electric's ("PGE") press release dated June 28,2010,
PGE made the following statement:
The utilty's original resource plan, filed in November
of 2009, included a recommendation to install
extensive emissions control retrofits on the Boardman
Plant, at an estimated cost of $520 milion to $560
milion. These controls would allow continued
operation of the plant through at least 2040 in
compliance with existing DEQ rules.
The emission control retrofits referenced above were an alternative to allow
continued operation, as a coal-fired facilty, at least through 2040. However, Idaho
Powets current expectation is that Boardman wil cease coal-fired operations by
December 31, 2020, resulting in less extensive emissions control retrofis than
contemplated in the above quote. See, Response to NIPPC's Production Request No.
47(d).
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 52
(d) In PGE's press release dated December 9, 2010, PGE made the following
statement:
The new controls are expected to reduce NOx
emissions by about 50 percent and permitted levels of
S02 emissions by 75 percent. A separate set of rules
also requires controls to reduce the plant's mercury
emissions by 90 percent. All coal-related emissions
from the Boardman facilty wil be reduced to zero with
the end of coal-fired operations in 2020. The
combined capital cost of the required controls is
currently estimated at about $60 milion.
As a 10 percent owner of the Boardman plant, unless other arrangements were
in place, Idaho Power would be expected to pay its ownership share of the capital costs
associated with required upgrades. Based on the $60 millon noted in the above-
referenced PGE press release, Idaho Power's estimated share of the upgrades would
be about $6 million.
If the Sierra Club lawsuit were successful and resulted in a federal court ordering
Boardman to shut down prior to 2020, Idaho Power expects that after evaluating and
perhaps pursuing the available appeal processes, the plant owners would comply with
the federal court's ruling.
(e) Expenses that are determined by the Commission to be prudent and
necessary to serve the public wil be included in customers' rates as authorized by the
Commission.
The response to this Request was prepared by Karl E. Bokenkamp, Director,
Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 53
REQUEST NO. 48: Is it possible that Boardman, Bridger, Valmey (sic), or any of
RMP's coal plants could experience increased costs as a result of ongoing EPA
rulemaking proceedings regarding coal waste, or hazardous air pollutants, or any other
new environmental regulations? Wil your utility pass any increased costs onto
ratepayers? Provide all internal studies regarding risk analysis for such future
regulations.
RESPONSE TO REQUEST NO. 48: It is possible the above-referenced
resources could experience increased costs as a result of future Environmental
Protection Agency rulemaking or federal legislation. This possibility has existed for
many years and there is stil much uncertainty regarding what future regulations might
be enacted. Idaho Power would expect to be able to include any additional capital costs
associated with future regulations in its rate base, and recover any additional operating
expenses incurred. Expenses that are determined by the Commission to be prudent
and necessary to serve the public wil be included in customers' rates as authorized by
the Commission.
Idaho Power deals with the risk of future environmental regulations in its
integrated resource planning process. The most recent analysis is detailed in Chapters
9 and 10 of Idaho Powets 2009 Integrated Resource Plan. The 2009 Integrated
Resource Plan can be found at:
http://w.idahopower.com/pdfs/ AboutUs/PlanningForFuture/irp/2009/2009IntegratedR
esourcePlan.pdf.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 54
The response to this Request was prepared by M. Mark Stokes, Manager, Power
Supply Planning, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 55
REQUEST NO. 49: If a wind QF were forced to face increased costs, or cease
or curtail operation for environmental compliance reasons, do the wind QF contracts
allow for wind QFs to increase the rates collected from the utilty and its ratepayers?
Please explain how this compares to the Company-owned thermal, hydro, and
renewable resources of each utilty.
RESPONSE TO REQUEST NO. 49: No. A public utilty has an obligation to
serve those requesting service located within its service territory.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 56
REQUEST NO. 50: Please explain how the avoided cost rate relates to the cost
of new resources built by the utilty. Is it reasonable and prudent for the utilitiy (sic) to
build a new resource when the cost of that resource wil exceed the avoided cost it
would pay to a QF? Should the Commission ever approve a non-PURPA resource that
has a higher cost than the avoided cost at the time of approval of CPCN? Please
explain.
RESPONSE TO REQUEST NO. 50: Please see the Company's Response to
NIPPC's Production Request No. 46. Yes, it certainly can be. For example, a natural
gas peaking plant is built to serve peak loads over a small number of hours, resulting in
a higher levelized cost than a base load or a PURPA resource, but the overall cost to
customers is lower. Yes. Please see the Company's Response to NIPPC's Request
No. 46.
The response to this Request was prepared by Randy C. Allphin, Senior Energy
Contracts Coordinator, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 57
REQUEST NO. 51: When your utilty analyzes new resources in its IRP process,
does it compare the cost to the PURPA avoided costs? Does it use the published
avoided cost rate schedule, or does it run the "IRP method" for the utilty's proposed
resource to determine if the resource is cost-effective? Please explain and provide
supporting documents of instances where the utilty has compared the cost of its
proposed resources to the avoided cost provided to QFs under and above 10 aMW in
size.
RESPONSE TO REQUEST NO. 51: Idaho Powets Integrated Resource Plan
("IRP") analysis process does not consider the current calculated PURPA avoided cost
rate. For the IRP, the AURORA model is used to analyze the value/cost of numerous
resource portolios, each of which have been designed to meet the projected needs of
Idaho Power's customers. From this standpoint, the analysis is very similar to the "IRP
method" currently used for larger PURPA projects and currently proposed by Idaho
Power, Avista, and Rocky Mountain Power for all PURPA projects over 100 kilowatts
("kW").
When Idaho Power requests Idaho Commission approval of power purchase
agreements, the published avoided cost rate is typically referenced in comparison to the
rates contained in the new contract. Recent examples of these types of comparisons
can be found in the Rockland wind contract (IPC-E-10-24), Neal Hot Springs
geothermal contract (IPC-E-09-34), and the Cassia Gulch and Tuana Springs wind
contracts (I PC-E-09-24).
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 58
The response to this Request was prepared by M. Mark Stokes, Manager, Power
Supply Planning, Idaho Power Company, in consultation with Donovan E. Walker,
Senior Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 59
REQUEST NO. 52: Considering all applicable Commission Orders, what were
the published avoided cost rates in effect for the time period from December 14, 2010,
to the date of this production request? What is the eligibilty cap for availabilty of those
rates during the same time period - 10 aMW, 100 kw, or some other amount? Is the
response different for different QF resource types? Please explain.
RESPONSE TO REQUEST NO. 52: The rates for new PURPA contracts in
effect from December 14, 2010, to the current time are set forth in the Commission's
Order No. 31025 issued on March 16, 2010. The eligibilty cap for a QF to qualify for
the published avoided cost rate is currently set at 10 aMW. The response is not
different by QF resource type. The Commission's Orders speak for themselves.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 60
REQUEST NO. 53: What is the currently filed rate for published avoided cost
rates currently in effect, as contemplated in 18 CFR 292.304(c) (1) & (2)? What is the
eligibilty cap for that rate for your utilty?
RESPONSE TO REQUEST NO. 53: Please see the Company's Response to
NIPPC's Production Request No. 52.
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 61
REQUEST NO. 54: Reference Avista (Initial Comments page passim) RMP
(Initial Comments passim) Idaho Power (Initial Comments passim) to the effect that the
current SAR methodology and rate eligibilty cap requirement is causing the utilties to
incur higher power supply costs that they otherwise would incur.
(a) Please explain why it is reasonable for your utility to insist on a $45 delay
liquid security deposit that is designed to prevent developers from delaying the on line
date in their power purchase agreements.
(b) Please provide all workpapers, studies, notes memoranda or any other
documents that were used; (i) to calculate the $45 delay liquid security number and (ii)
in the decision making process to insert it in your draft power purchase agreements with
developers.
(c) Please identify damages your utilty would incur per MW were the QFs
referenced in your Initial Comments were to delay their on line date by one year, by two
years and by three years.
RESPONSE TO REQUEST NO. 54:
(a) Please see the relevant Commission Orders discussing, and finding
reasonable, the contract provisions requiring the posting of delay security as referenced
below. Delay security provisions have been included in PURPA QF contracts approved
by the Commission since at least 2007. See Case No. IPC-E-06-36. In addition, one of
the first Commission-approved QF contracts to contain terms requiring the project to
post liquid delay security was the contract for Cassia Gulch Wind Park and Tuana
Springs Energy, Case No. IPC-E-09-24. In that case, the Commission approved
provisions requiring the posting of liquid security in the amount of $20 per kW of project
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 62
capacity. The Commission subsequently considered and approved provisions providing
for the posting of liquid security in the amount of $20 per kW of project capacity in at
least four other QF contracts. See Case Nos. IPC-E-09-18, IPC-E-09-19, IPC-E-09-20,
and IPC-E-09-25. The Commission has since analyzed and approved provisions
requiring the posting of liquid security in the amount of $45 per kW of nameplate
capacity in at least ten different PURPA FESAs. See Case Nos. IPC-E-10-02, IPC-E-
10-05, IPC-E-10-15, IPC-E-10-16, IPC-E-10-17, IPC-E-10-18, IPC-E-10-19, IPC-E-10-
22, IPC-E-10-24, and IPC-E-10-26.
(b) Please see the Company's Response to NIPPC's Production Request No.
54(a).
(c) Please see the Company's Response to NIPPC's Production Request No.
47(a).
The response to this Request was prepared by Donovan E. Walker, Senior
Counsel, Idaho Power Company.
DATED at Boise, Idaho, this 14th day of January 2010.
~t~~
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 63
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 14th day of January 2011 I served a true and
correct copy of the IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH
PRODUCTION REQUEST OF THE NORTHWEST AND INTERMOUNTAIN POWER
PRODUCERS COALITION TO JOINT UTILITIES upon the following named parties by
the method indicated below, and addressed to the following:
Commission Staff
Donald L. Howell, II
Kristine Sasser
Deputy Attorneys General
Idaho Public Utilities Commission
472 West Washington
P.O. Box 83720
Boise, Idaho 83720-0074
Avista Corporation
Michael G. Andrea
Clint Kalich
Avista Corporation
1411 East Mission Avenue - MSC-23
P.O. Box 3727
Spokane, Washington 99220-3727
PacifiCorp d/b/a Rocky Mountain Power
Daniel E. Solander
J. Ted Weston
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Bruce Griswold
PacifiCorp
825 NE Multnomah
Portland, Oregon 97232
-- Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email don.howeiicæpuc.idaho.gov
kris.sasser~puc. idaho.gov
Hand Delivered
-- U.S. Mail
_ Overnight Mail
FAX
-- Email michael.andrea~avistacorp.com
clint. kalich~avistacorp.com
Hand Delivered
-- U.S. Mail
_ Overnight Mail
FAX
-- Email danieLsolander~pacificorp.com
ted. westoncæpacificorp.com
Hand Delivered
-- U.S. Mail
__ Overnight Mail
FAX
-- Email bruce.griswoldcæpacifiCorp.com
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 64
Exergy, Grand View Solar, J. R.
Simplot, Northwest and Intermountain
Power Producers Coalition, & Board of
Commissioners of Adams County,
Idaho
Peter J. Richardson
Greg Adams
RICHARDSON & O'LEARY, PLLC
515 North 27th Street
P.O. Box 7218
Boise, Idaho 83702
Exergy Development Group
James Carkulis, Managing Member
Exergy Development Group of Idaho, LLC
802 West Bannock Street, Suite 1200
Boise, Idaho 83702
Grand View Solar II
Robert A. Paul
Grand View Solar II
15960 Vista Circle
Desert Hot Springs, California 92241
J.R. Simplot Company
Don Sturtevant, Energy Director
J.R. Simplot Company
One Capital Center
999 Main Street
P.O. Box 27
Boise, Idaho 83707-0027
Northwest and Intermountain Power
Producers Coalition
Robert D. Kahn, Executive Director
Northwest and Intermountain Power
Producers Coalition
1117 Minor Avenue, Suite 300
Seattle, Washington 98101
Renewable Energy Coalition
Thomas H. Nelson, Attorney
P.O. Box 1211
Welches, Oregon 97067-1211
Hand Delivered
-l U.S. Mail
_ Overnight Mail
FAX
-l Email peter~richardsonandoleary.com
gregcærichardsonandoleary.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email icarkulis~exergydevelopment.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email robertapauI08~gmail.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email don.sturtevant~simplot.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email rkahncænippc.org
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email nelsoncæthnelson.com
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 65
John R. Lowe, Consultant
Renewable Energy Coalition
12050 SW Tremont Street
Portland, Oregon 97225
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email jravenesanmarcoscæyahoo.com
Cedar Creek Wind, LLC, & Dynamis
Energy, LLC
Ronald L. Willams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, Idaho 83702
Hand Delivered
-- U.S. Mail
_ Overnight Mail
FAX
-- Email roncæwiliamsbradburv.com
Cedar Creek Wind, LLC
Scott Montgomery, President
Cedar Creek Wind, LLC
668 Rockwood Drive
North Salt Lake, Utah 84054
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email scottcæwesternenergy.us
Dana Zentz, Vice President
Summit Power Group, Inc.
2006 East Westminster
Spokane, Washington 99223
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email dzentzcæsummitpower.com
Dynamis Energy, LLC
Wade Thomas, General Counsel
Dynamis Energy, LLC
776 East Riverside Drive, Suite 15
Eagle, Idaho 83616
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email wthomas~dynamisenergy.com
Idaho Windfarms, LLC
Glenn Ikemoto
Margaret Rueger
Idaho Windfarms, LLC
672 Blair Avenue
Piedmont, California 94611
Hand Delivered
-- U.S. Mail
_ Overnight Mail
FAX
-- Email glenni~EnvisionWind.com
Margaret~EnvisionWind.com
Interconnect Solar Development, LLC
R. Greg Ferney
MIMURA LAW OFFICES, PLLC
2176 East Franklin Road, Suite 120
Meridian, Idaho 83642
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email greg~mimuralaw.com
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 66
Bil Piske, Manager
Interconnect Solar Development, LLC
1303 East Carter
Boise, Idaho 83706
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email bilpisketãcableone.net
Intermountain Wind LLC
Dean J. Miler
McDEVITT & MILLER LLP
420 West Bannock Street
P.O. Box 2564
Boise, Idaho 83701
Hand Delivered
-- U.S. Mail
_ Overnight Mail
FAX
-- Email joetãmcdevitt-miler.com
Paul Martin
Intermountain Wind LLC
P.O. Box 353
Boulder, Colorado 80306
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email
paulmartincæintermountainwind .com
North Side Canal Company and Twin
Falls Canal Company
Shelley M. Davis
BARKER ROSHOLT & SIMPSON, LLP
1010 West Jefferson Street, Suite 102
P.O. Box 2139
Boise, Idaho 83701-2139
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email smdtãidahowaters.com
Brian Olmstead, General Manager
Twin Falls Canal Company
P.O. Box 326
Twin Falls, Idaho 83303
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email olmstead~tfcanal.com
Ted Diehl, General Manager
North Side Canal Company
921 North Lincoln Street
Jerome, Idaho 83338
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email nscanal~cableone.net
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 67
Board of Commissioners of Adams
County, Idaho
Bil Brown, Chair
Board of Commissioners of
Adams County, Idaho
P.O. Box 48
Council, Idaho 83612
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
.. Email bdbrown~frontiemet.net
Birch Power Company
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 11 th East
Idaho Falls, Idaho 83404
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
.. Email tedcætsorenson.net
~?a/~
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH PRODUCTION REQUEST OF THE
NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION TO THE JOINT UTILITIES - 68