20060712IPC to ICIP 1-18.pdf

BARTON L. KLINE ISB #1526
MONICA B. MOEN ISB #5734
Idaho Power Company
P. O. Box 70
Boise , Idaho 83707
Telephone: [phone]
FAX Telephone: [phone]
RECEIVED
2006 JUL
PH 4: 52
UTlLW~~~fF ~Ltc
MMISSION
Attorney for Idaho Power Company
Street Address for Express Mail
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR A
CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY FOR THE RATE BASING
OF THE EV ANDER ANDREWS POWERPLANT.
CASE NO. IPC-06-
IDAHO POWER COMPANY'
RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF
IDAHO POWER
COMES NOW , Idaho Power Company ("Idaho Power" or "the Company
and , in response to the First Production Request of the Industrial Customers of Idaho
Power to Idaho Power Company dated June 19, 2006, herewith submits the following
information:
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page
REQUEST FOR PRODUCTION NO.1: On page 10 of Greg Said's direct
testimony he states:
Among the actions recommended by the 2004 IRP was the
acquisition of targeted 88 MW simple-cycle, natural gas-fired
combustion turbine. Consistent with the recommendations of the
2004 IRP, the peaking resource RFP requested proposals for an
MW- 200 MW turnkey electric generation resources located within
the Companys service territory that would meet anticipated peak
energy demands. The flexibility in plant capacity permitted under the
RFP allowed the developers to respond to the RFP with their most
cost-effective proposals.
Please explain in greater detail how the "flexibility in plant capacity" in the
RFP is consistent with the Company s 2004 IRP. Please explain why a simple-cycle
resource of nearly twice the size of the 88 MW facility stated in the Near-Term Action Plan
is consistent with the I RP.
RESPONSE TO REQUEST NO.1: The "flexibility in plant capacity" in the
RFP is consistent with the Company s 2004 IRP on several counts.
First, one of the primary goals of the 2004 IRP was to ensure that the
portfolio of resources selected balanced costs , risks and environmental concerns.
Since there was an active secondary market for combustion turbines when the 2004
IRP (and the subsequent peaking RFP) were being prepared, Idaho Power felt that it
was appropriate to provide flexibility in the RFP to provide bidders an opportunity to
propose a variety of standard turbine sizes capable of meeting the identified peaking
need. As a result of the information obtained in the Bennett Mountain RFP, Idaho
Power knew that it was possible to acquire larger frame combustion turbines at
extremely competitive prices on a $/kW basis. By selecting a larger combustion turbine
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 2
Idaho Power has provided additional internal generation resources capable of meeting
system load in the event of transmission outages, forced outages of other generation
units, extreme weather conditions , or greater than expected load growth. In all of these
instances, the risk of curtailment of firm load is reduced by selecting a larger
combustion turbine. Given the competitiveness of the pricing in the Bennett Mountain
RFP , Idaho Power was able to acquire the incremental 85 MW of capacity (173 MW-
88 MW = 85 MW) at an extremely competitive price - providing additional generation at
minimal cost while improving reliability for customers.
Second , the idea of specifying a range of turbine sizes in the peaking
resource RFP is discussed on page 75 of the 2004 IRP. Incorporating flexibility
turbine sizing in the RFP is consistent with the discussion on page 75 of the 2004 IRP.
And finally, by incorporating a range of sizes in the RFP and ultimately
selecting a 173 MW combustion turbine, Idaho Power has an opportunity to defer
additional generation resources in future resource plans. Deferring a large generation
resource , even for one year, could result in substantial savings for customers.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations , Idaho Power Company, in
consultation with Barton L. Kline , Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 3
REQUEST FOR PRODUCTION NO.2: On page 10 of Greg Said's direct
testimony he states:
The RFP directed respondents to locate the proposed facility at
either the Company s Evander Andrews Power Complex or the
Bennett Mountain Power Plant site or at site of respondent's
choosing.
Please explain why the specific sites of Bennett Mountain and Evander
Andrews were specified in the RFP. In the evaluation process were these two sites given
preference over other sites? If yes, please explain how and why.
RESPONSE TO REQUEST NO.2: The specific locations of the existing
Bennett Mountain and Evander Andrews facilities were identified in the RFP as potential
sites for the proposed peaking resource since those sites had the ability to
accommodate additional resources. In the evaluation process , those two sites were not
given preference over other sites. The merits of each of the sites proposed by the
Respondents were independently evaluated.
The response to this request was prepared by F. Gregory Hall , Principal
Engineer, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 4
REQUEST FOR PRODUCTION NO.3: On page 15 of Greg Said's direct
testimony he states:
Forecasted natural gas prices from the 2004 IRP were used in the
bid evaluation. Forecasted natural gas prices have gone up
substantially since the issuance of the 2004 IRP, but the same price
forecast was utilized in the evaluation of all of the natural gas-fired
project proposals and as a result, projects with lower guaranteed
heat rates had lower fuel costs on dollar per megawatt basis.
Since natural gas prices have "gone up substantially" from those found in
the 2004 IRP, was any consideration given by the Company as to the type of unit included
in the RFP? Please fully explain.
RESPONSE TO REQUEST NO.3: The fact that forecasted natural gas
prices have gone up substantially since the 2004 IRP did not impact the types of
specific resources included in the RFP. In the RFP, the Company sought bids for "
turnkey electric generation resource located within Idaho Power Company s service
territory to meet peak energy demands" with no specific unit types identified.
The response to this request was prepared by Randall R. Henderson, Business
Analyst Power Supply Reporting, Idaho Power Company, in consultation with Barton L.
Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 5
REQUEST FOR PRODUCTION NO.4: On page 20 of Greg Said's direct
testimony he states: However, when consideration of the non-price attributes of the bids
were included, the Siemens proposal received the best combined price and non-price
score.Please explain in detail all of the "non-price attributes" that were considered by the
Company in the evaluation process. Please indicate the weight given each of the "non-
price attributes" in the evaluation process.
RESPONSE TO REQUEST NO.4: The confidential information
requested is available for examination in the Idaho Power Company Legal Department
located in the Company s corporate offices. Please contact Sandra Holmes at 388-
2688 to arrange a time to review the requested material.
The response to this request was prepared by Monica Moen, Attorney
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 6
REQUEST FOR PRODUCTION NO.5: Were any of the non-price
attributes given more weight in the evaluation process than other non-price attributes? If
, please fully explain.
RESPONSE TO REQUEST NO.5: The confidential information
requested is available for examination in the Idaho Power Company Legal Department
located in the Company s corporate offices. Please contact Sandra Holmes at 388-
2688 to arrange a time to review the requested material.
The response to this request was prepared by Monica Moen, Attorney II
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 7
REQUEST FOR PRODUCTION NO.6: Please provide the results of final
cost model run performed for the selected Siemens unit. Results provided should include
(A) Load factor and/or the hours the unit is expected to be on line; (B) The times of the
year when the unit is expected to be on line; (C) Variable costs associated with the unit's
operation; (D) Full kWh costs of the unit; (E) Input assumptions used in the cost model
runs such as carrying costs , fuel costs, depreciation rates , M&O costs, etc.
RESPONSE TO REQUEST NO.6: The confidential information
requested is available for examination in the Idaho Power Legal Department located in
the Company s corporate offices. Please contact Sandra Holmes at 388-2688 to
arrange a time to review the requested material.
The response to this request was prepared by Monica Moen, Attorney Idaho
Power Company, in consultation with Barton L. Kline , Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 8
REQUEST FOR PRODUCTION NO.7: In "Response of Idaho Power
Company to Filed Comments" in Docket No. IPC-04-, Idaho Power s 20041RP
docket, Idaho Power stated:
New generating resource additions in the Pacific Northwest are
expected to utilize coat natural gas, or possibly wind, since no new
large hydro-power projects are anticipated. If new natural gas-fired
projects are to be built to serve loads in southwest Idaho, there are
two obvious options; build or acquire additional natural gas pipeline
capacity from the Pacific Northwest to southwest Idaho and locate
the generator near the load in southwest Idaho, or locate the
generator near the existing natural gas pipelines in the Pacific
Northwest, acquire pipeline capacity and then build additional
electric transmission line capacity to southwest Idaho. Studies
indicate that over the lifetime of the projects. it is less expensive to
build the natural Gas pipeline capacity and locate the Generator at
the load.
Page 6, underscoring added.
Please provide copies of the referenced studies , including all Aurora model
runs, etc., supporting that statement.
RESPONSE TO REQUEST NO.7: A draft copy of the referenced study
Joint BPA and Northwest Gas Association Study of Wires and Pipes" is attached
hereto as "Response to Request No.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations, Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 9
REQUEST FOR PRODUCTION NO.8: In the same "Response of Idaho
Power Company to Filed Comments" at page 5, Idaho Power stated:
Finally, the ability to fund DSM programs at levels indicated by the
IRP is an ongoing concern. While Idaho Power believes that an
increase in the DSM Tariff Rider is an appropriate mechanism for
recovery of program costs, ongoing funding for these DSM program
costs is unresolved at this time.
Please detail what steps Idaho Power has taken to resolve its "ongoing
concern" relative to "the ability to fund DSM programs at levels indicated by the IRP" since
it filed its Response in December 2004?
RESPONSE TO REQUEST NO.8: On December 6 , 2004 , the Company
filed an application with the Commission requesting authorization to increase the funds
generated by the Idaho Energy Efficiency Tariff Rider (Rider) from 0.5 % to 1.5 % of
base revenues (Case IPC-04-29). On May 13, 2005, the Commission issued Order
No. 29784 authorizing an increase to the Rider from 0.5 % to 1 .5 % of base revenues
with caps on irrigation and residential monthly contributions of $50.00 and $1.
respectively. The increased Rider will provide adequate funding to allow the Company
to successfully administer the DSM programs at the levels identified in the 2004 IRP.
The response to this request was prepared by Maggie Brilz, Director
Pricing, Idaho Power Company, in consultation with Barton L. Kline, Senior Attorney,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 10
REQUEST FOR PRODUCTION NO.9: Reference the same passage of
the "Response" quoted in No.8 above. Please explain what is meant by the phrase
ongoing funding for these DSM program costs is unresolved at this time" and detail
(quantify) the impact the unresolved ongoing funding has had on Idaho Power s DSM
programs.
RESPONSE TO REQUEST NO.9: At the time that the above-referenced
statement was made, Order No. 29784 had not yet been issued. As a result, the
Company was uncertain of its ability to fully recover the costs associated with the
implementation and operation of the six DSM programs identified by the 2004 IRP.
With the issuance of Order No. 29784, those funding concerns have been resolved
without any impact to the successful implementation of the DSM programs.
The response to this request was prepared by Maggie Brilz, Director
Pricing, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney,
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page
REQUEST FOR PRODUCTION NO.1 0: Please provide an organizational
chart indicating all of the personnel at Idaho Power who are responsible for creating and
implementing DSM programs as of January 1 , 2004; January 1 , 2005; and January 1
2006; please include the individual's name, job description and job title.
RESPONSE TO REQUEST NO. 10: The information requested is
attached hereto as "Response to Request No.1 0.
Organizational charts for January 1 , 2004-2006 along with a brief
description of the job responsibilities of each position are included with this response.
The organizational chart provides the job title; however, individual names are not
provided in accordance with the Company s policy on maintaining employee privacy.
In addition to the staffing for persons directly responsible for creating and
implementing DSM programs , the Company also utilizes various staff members within
the organization such as Delivery Services Representatives (account representatives),
Market Segment Coordinators , and Customer Satisfaction Coordinator to assist with the
creation and implementation of DSM program activities.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations, Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 12
REQUEST FOR PRODUCTION NO. 11: Please reconcile Mr. Said's direct
testimony at page 10 to the effect that the selected winning proposal to construct a 170
MW simple cycle is "consistent" with the IRP of"a targeted 88 MW simple cycle.
RESPONSE TO REQUEST NO. 11: Please see the response to Request
For Production No.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations, Idaho Power Company, in
consultation with Barton L. Kline , Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 13
REQUEST FOR PRODUCTION NO. 12: Please explain why PURPA
generation additions occur outside of the IRP process.
RESPONSE TO REQUEST NO. 12: PURPA additions do not occur
outside of the IRP process. A generation estimate for all PURPA projects under
contract at the time the IRP is developed is included in the IRP existing resources.
PURPA projects under contract include projects that are operational as well as projects
that have an approved contract and are in various stages of development.
The response to this request was prepared by Randy C. Allphin , CSPP
Contract Administrator, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 14
REQUEST FOR PRODUCTION NO. 13: In response to a question at the
bottom of page 13 of his direct testimony about the decision to delay the peaking project
by one year, Mr. Said states that "the Company evaluated the most prudent use of its
resources and determined that other short-term alternatives other than this project could
meet the projected peak energy needs for the summer of 2007." Please provide copies of
the reverenced evaluation(s) and determination(s). Include any work papers , studies
AURORA model runs and economic evaluations.
RESPONSE TO REQUEST NO. 13: A copy of the analysis that examined
expected changes in Idaho Power s forecast surplus/deficit position and a memorandum
summarizing the analysis are attached hereto as "Response to Request No. 13.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations , Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 15
REQUEST FOR PRODUCTION NO. 14: When and by whom was the
determination referenced in No. 13 above made? Please provide all available
documentation relative to said determination , including notes , memoranda and
correspondence.
RESPONSE TO REQUEST NO. 14: The analysis and memorandum
produced in response to Request for Production No. 13 was prepared by Karl
Bokenkamp; additional supporting analysis was prepared by Rick Haener.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations, Idaho Power Company, in
consultation with Barton L. Kline , Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 16
REQUEST FOR PRODUCTION NO. 15: On page 14 of his direct
testimony, Mr. Said refers to an additional 50 megawatts of market purchases and
associated transmission. Please provide details of these transactions, including counter
party(ies), price, transmission path, cost of power and cost of transmission. Please
provide copies of all relevant documentation , including contracts, agreements , term sheets
etc.
RESPONSE TO REQUEST NO. 15: Idaho Power has not yet entered
into any transactions to acquire the additional 50 MW of market purchases and
associated transmission reference on page 14 of Mr. Said's direct testimony.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations , Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 17
REQUEST FOR PRODUCTION NO. 16: Please provide documentation
supporting the 22.8 million dollar figure referenced on the top of page 19 of Mr. Said'
testimony.
RESPONSE TO REQUEST NO. 16: See Idaho Power Company
Response to Request No. 24 of the First Production Request of Commission.
The response to this request was prepared by Randall R. Henderson
Business Analyst Power Supply Reporting, Idaho Power Company, in consultation with
Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 18
REQUEST FOR PRODUCTION NO. 17: Please provide copies of all
transmission studies, whether definitive or preliminary, related to the proposed project.
RESPONSE TO REQUEST NO. 17: The information requested is
voluminous and , as a result, is available for examination in the Idaho Power Company
Legal Department located in the Company s corporate offices. Please contact Sandra
Holmes at 388-2688 to arrange a time to review the requested material.
The response to this request was prepared by Monica Moen, Attorney
Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 19
REQUEST FOR PRODUCTION NO. 18: Should the Commission deny
Idaho Power s request for a certificate of public convenience and necessity, what supply or
demand reduction alternative options would the Company turn to in the summer of 2007
(sic )(2008)?
RESPONSE TO REQUEST NO. 18: Please refer to the Response to
Request No. 13. If the Commission denies Idaho Power s request for a certificate of
public convenience and necessity, Idaho Power would most likely consider several
alternatives to meet peak-hour loads during the summer of 2008. These alternatives
include: (1) additional firm market purchases and the associated transmission necessary
to deliver the energy to the east side of Idaho Power s system, (2) transmission system
expansions to increase import capacity, (3) expansion of the Irrigation Peak Rewards
program (which is already being investigated), (4) developing advertising messages that
ask consumers to reduce their peak-hour consumption , and (5) utilizing diesel or other
temporary gensets.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations, Idaho Power Company, in
consultation with Barton L. Kline , Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 20
- ~~-~~-~---_.
IDAHO POWER COMPANY
O, BOX 70
BOISE, IDAHO 83707
RECE\VED
100& JUl \ I PM 4: 5 \
IDAHO fUB~JC
UTILITIES COM\~ISSION
An IDACORP Company
July 11 , 2006
Jean D. Jewell , Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. O. Box 83720
Boise , Idaho 83720-0074
Re:Case No. IPC-06-
Idaho Power Company s Response to the First Production
Request of the Industrial Customers of Idaho Power
Dear Ms. Jewell:
Please find enclosed for filing an original and two (2) copies of Idaho Power
Company s Response to the First Production Request of the Industrial Customers of Idaho
Power regarding the above-described case.
I would appreciate it if you would return a stamped copy of this transmittal letter
to me in the enclosed self-addressed stamped envelope.
Very truly yours
~~
(P-
Monica B. Moen
MBM:sh
Enclosures
Telephone [phone] Fax [phone], E-mail MMoen(Widahopower.com
REQUEST FOR PRODUCTION NO. 19: What is the retail rate impact of
Mr. Said's request at page 20 for the Commission to approve inclusion of the total project
investment in the Company s rate base for ratemaking purposes? Assume for purposes of
answering this question that the total project investment includes 60 million dollars for the
generating plant and 22.8 million dollars for associated transmission and substation
improvements. Please provide supporting work papers.
RESPONSE TO REQUEST NO. 19: There is no current retail rate impact
associated with the Company s application for a Certificate of Convenience and
Necessity. The actual incremental revenue requirement to be requested by the
Company will depend upon circumstances that exist at the time of an application for
recognition of the Evander Andrews project in the Company s rate base , revenue
requirement and rates. The earliest a future retail rate impact would occur would
probably be in 2008 once the Evander Andrews power plant is in service.
application to change the Company s rates in 2008 to reflect the Evander Andrews
power plant could either be a part of a general rate case or a single issue rate case as
was the case for inclusion of the Bennett Mountain power plant costs.
In that case , the Company identified $50.3 million of power plant costs and
$7.7 million of transmission and interconnection facilities costs for a total of $58.0 million
in total project costs. The Company quantified the associated incremental revenue
requirement associated with the Bennett Mountain project at $13.5 million. This
quantification included expenses such as property taxes, property insurance and
depreciation expenses, but excluded expenses such as operating and maintenance
expenses. Power supply expense impacts were likewise not included , but were
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 21
ultimately captured in PCA computations. The Company has not quantified the
incremental revenue requirement associated with the Evander Andrews project.
However, assuming the ratio of incremental revenue requirement to total project costs
($13.5 million / $58 million = 23.3 percent) from the Bennett Mountain application might
be similar in an Evander Andrews application, an estimated incremental revenue
requirement for an $82.8 million project would be $19.3 million.
The response to this request was prepared by Gregory W. Said , Manager
of Revenue Requirement , Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
DATED at Boise , Idaho, this 11th day of July 2006.
(p~
MONICA B. MOEN
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 22
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 11th day of July, 2006 , I served a true and correct
copy of the within and foregoing IDAHO POWER COMPANY'S RESPONSE TO FIRST
PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER upon
the following named parties by the method indicated below, and addressed to the following:
Commission Staff Hand Delivered
Donovan Walker US. Mail
Deputy Attorney General Overnight Mail
Idaho Public Utilities Commission FAX
472 W. Washington (83702)-X Email Donovan.walker(gJpuc.idaho.gov
O. Box 83720
Boise, Idaho 83720-0074
Industrial Customers of Idaho Power Hand Delivered
Peter J. Richardson, Esq.----.L US. Mail
Richardson & O'Leary Overnight Mail
515 N. 27th Street FAX
O. Box 7218 Email peter(gJrichardsonandoleary.com
Boise, Idaho 83702
Don Reading Hand Delivered
Ben Johnson Associates US. Mail
6070 Hill Road Overnight Mail
Boise, Idaho 83702 FAX
Email dreading(gJrnindspring.com
Mountain View Power, Inc.Hand Delivered
Ronald L. Williams US. Mail
Williams Bradbury, P.Overnight Mail
O. Box 2128 FAX
Boise, Idaho 83701 -X Email ron(gJwilliamsbradbur com
Robert D. Looper, President Hand Delivered
Mountain View Power, Inc.----.L US. Mail
1015 W. Hays Street Overnight Mail
Boise, Idaho 83702 FAX
Email rlooper(gJspellc.com
~(b.
Monica B. Moen
CERTIFICATE OF SERVICE , Page
ID AH POWER CO MP ANY
CASE NO. IPC-O6-
FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO. 7
DRAFT
Joint BP A and Northwest Gas Association Study of Pipes and Wires
Executive Summary
A key finding was that making valid comparisons be
physics of the two systems. Natural gas pipelines
localized effects as a result of capacity expansions
interconnected and redundant.
fpipes and wires ell as how
ho finances the project? 2)
Bonneville Power Administration (BP A) and the Northwest Gas Association (NGA) agreed to stud
economics of delivering energy to load centers via electrical transmission lines versus natural
One objective was to determine which is more economically efficient. A second objective
determine whether the Federal Energy Regulatory Commission s (FERC) pricing rules
outcomes that do not comport with economic efficiency; in other words, whether FE
tilt the playing field toward a less than optimal economic outcome.
The Work Group compared the economic costs, reliability, delivery effic
factors associated with energy delivery to a generator located near a I
pipeline versus from an electric generator located near a gas pipeli
a lOO-mile electrical transmission line.
Both pipelines and electric grid exp
mile of each alternative-natura
transmission per unit of ener
pipeline would be more
associated benefits, an
case- and site-specific
etween the two systems and to
ost-recovery for capacity
as pipelines and electric power
ies is t fthe benefits accrue solely to one party, that
, in addition to whatever other costs it must pay to
probably for most cases, a natural gas pipeline
party than an expansion of the electric grid. So, the
; one is incremental, the other is rolled in. However, if the
eneration interconnection the two cases would be identical; the
sts in either case.
cons in pricing principles is one thing; assuming that the merchant transmissionnatu pipeline industry will transfer to the electric industry is quite another. Our
bt on e prospects ofFERC's vision of merchant electric transmission springing up to
k congestion coming to fruition in the Pacific Northwest.
onc1ude that, the benefits and costs of both systems may vary widely depending on site-
lrcumstances. Both systems now are planned and developed separately. We recommend that
ver possible, energy planning and development should incorporate both electrical and natural gas
stems to optimize an integrated system, thereby providing the greatest benefits for society.
2/26/2004
Joint BPA and Northwest Gas Association Study of Pipes and Wires
Specifically, the Work Group compared the economic
efficiency (energy losses), and other factors associated
generator located near a load center via a 100- ile na
generator located near a gas pipeline deliv electri
100-mile electric transmission line.
pipeline and use electrical
the distribution system.) This is
ration of Pipes vs. Wires
Bonneville Power Administration (BP A) and the Northwest Gas Association (NG
agreed to study the economics of delivering energy to load centers via electric
transmission lines versus natural gas pipelines. One objective was to dete
more economically efficient. A second obj ective was to detennine wh
Energy Regulatory Commission s (FERC) pricing rules could creat
not comport with economic efficiency; in other words, whether
tilt the playing field toward a less than optimal economic ou
Staff from BPA's Transmission Busines
belong to the NGA began t dy in
participants.) This pape s the
Methodology
ical generation is located adjacent to the load
es gas from a main interstate pipeline to the
lcted in the bottom portion of Figure
an , we assumed that the distance to be covered in either scenarioile at is, we compared a pipeline to an electric transmission line, each
e further assumed that the amount of power output from the generator
0 MW. Work Group expertise was tapped to detennine that: 1) a 20-inch
se nearly all costs are determined on a per-mile basis, this is not a critical assumption. There are no
omies of scale for distance; i., costs are directly proportional to distance of the line.
2/26/2004
Figure 1
Illustration of Pipes
vs. Wires Comparison
New 1500 MW
Generator Existing Transmission System
'J)
:Jf ~r500 kV
lines
......
C1)
p:;
Existing 1500 MW
Load
'J)
..........,....
i:j
New 1500
MW Load
:;,,~-- -- -- ----- --- ------- -- -- ---
New 1500 MW
Generator
2/26/2004
diameter pipe would be the optimal size of a pipe capable of delivering sufficient
(250 million cubic feet of gas per day? (mmcf/d)) to the plant; and 2) a 500 k
would be sufficient to deliver the output of the 1500 MW plant to the load.
s s is that losses are ignored. Weost 0 e 100 mile 500 kV line. However
ignored. Natural gas pipelines also use fuel for
equate pressure in the pipeline. This use is
similar magnitude. Therefore the two effects
For analyzing costs, we considered varied terrain and ownership.
to ensure that exactly the same assumptions are used by BP A fi
and NGA companies for gas pipelines, we believe that the f;
to afford reasonable comparisons for purposes of this s
Pipeline estimates may not reflect the cost of all water
terrain being traversed. Significant water cro 'ngs w
pipeline somewhat but have little bearing st elec
additional water crossings could add a fe n doll
alternative, which is a small percentage i
pelines are capital intensive. To test sensitivity, capital costser s using various interest rates ranging from 7.0 percent to 12.
nt rate corresponds approximately to BPA's Treasury borrowing
0 percent rate corresponds closely to the average cost of capital in the
r for these projects. Similarly, it is a rate close to what BP A has been quoted
mers who have expressed an interest in project financing. Because the
2 This assumes a plant heat rate of approximately 7 000 BtuJkWh.
3 As will be shown below, not only are the projects inherently not substitutable (meaning that an either/or
comparison is a false one), the way the costs typically are recovered for pipelines differs from the way
transmission costs are recovered.
2/26/2004
The costs are shown in Table 1 , Cost Comparison. The transmission
the left, the pipeline costs on the right. The top three rows show
capital costs per mile, capital costs per 100 miles, and the ann
maintenance (O&M) costs (or their equivalent.) The box
payment required to payoff the capital investment, bot
percent cost of capital. Next, the annual costs are com
annual capital payment and the annual O&M c sts.
various units and displayed below. Specifi , value
and per MWh under various load factors. CUffe
for illustrative purposes.
, the
pipeline companies who participated in this study have an average weighted cost
capital of 8.75 percent, results are shown for that, as welL
Because these projects are
than those costs to dete
mile of electrical tr
unit costs of e1ec
ct into servic typically 24
d compression additions as
his period allows for pre-
gineering and preparation of
process including final
on equipment and physical
e required to get commercial
f the pipeline, otherwise known as the
cess can be as short as two weeks.
lines, we assume that planning, which would
would nonnally take a year. Environmental work
, but would more likely take up to two years. Finally,
would take an additional two years.
observations in light of the foregoing come to mind. First, this hypothetical
smission project is cheaper than current rates. In other words, the dollar per kW-year
4 The costs shown here are economic costs for the purpose of comparing the amount of resources required
to develop each alternative. It is not a rate analysis. That means that meaningful comparisons can be
drawn among the alternatives concerning the overall cost that society would pay to develop either pipes or
wires. However, a quite different analysis would be required to compute actual rates. As such, using these
figures as proxies for rates or tolls would be misleading. Although BP A's transmission rate is shown for
illustrative purposes, and although the costs shown would roughly approximate rate effects, the two are not
strictly comparable.
2/26/2004
Finally, if it were true that one could simp
everything else the same it is clear that pi
$100,000,000
cost of this project is less than what BPA currently charges customers for point-to-
p .
transmission service. Thus, the project would meet the "or test"S and would be r
into rates.
Second, when expressed on an energy basis, this shows how economic
can be. Using a 65% load factor, which approximates the typical
the fully allocated transmission costs are less than $2 per M
line were to reduce re-dispatch costs (or other congestion a
of more than $2/MWh, the line would pay for itself, at I
(However, the incidence of specific customers' costs co
dispatch compared to new transmission capacity.
$8,058,640.518589.
000 000 000000
$9,058.640 $10 518 590 $13,414366
$6.$7.$8.
$12.$12.$12.
$0.$0.$1.
$1.$1.$1.
st ("Annual Payment, 30 years ) and "Total Costs per year" is
ow natural gas pipelines or their customers would view the cost of
mers through a transportation rate spanning the life of a facilities, annual
on rate are more representative measures of the customers obligations.
is i n lines are a means of transporting energy, sometimes over
oth transport two of the significant energy resources in ourres s are partially substitutable; either can be used to heat water or
pIe. But the differences are significant as well.
obably most importantly, the physics of the systems differ. In an electrical
verything is integrated-it is one large machine. Any disturbance, anywhere on
tern, is "felt" everywhere else on the system, virtually instantaneously. Because of
, the system is planned and built on an integrated basis.
5 The "or test" is discussed below.
2/26/2004
One planning criterion unique to electrical systems is known as the N-l criterion.
this criterion, the system (including new system additions or capacity expansi
planned such that if the worst possible contingency occurs, the system wil
deliver power to load. In other words, if the worst possible thing happ
in the case at hand, the new line fails--the system can still meet
exists in the natural gas pipeline system.
The natural gas delivery system also is planned on an i
account what is there already, and recognizes options fI
system is arterial. It resembles, at least in so respec
flows from large pipelines to ever-smalle eventu
the network ( cal) are
rt shows the si ation for an
load via two 500 kV
, it has two 500 kV lines
s down, the load can still be
n this example is 3000
W. Adding a third 500 kV
able capacity to 3000 MW.
ation differs. The bottom part of the figurea r (in this case represented by 250 mmcf/d of gasIe ith an additional 250-mmcf/d load, one newto e expanded loads. In this case, if either pipeline shuts
loa can be met, except to the extent storage is available at the
trical system is planned for single and credible double line outages (these are a
e event that could take out two facilities). Lines typically experience 1.75 outages
er year. They are involved in overlapping outages with another line 0.01 times per year.
6 A more commonly used term in the natural gas industry is LDC, which stands for Local Distribution
Company. Generically speaking, however, both gas and electric companies serve loads and therefore may
be termed Load Serving Entities.
7 This is a simplified view from both the electric and gas point of view. It is used only for illustrative
purposes for the points in the text.
2/26/2004
A single gas pipeline experiences 0.03 outages per year, which is comparable to the
for double transmission line outages. Although pipelines experience fewer outa
transmission lines, the outages are often more catastrophic and the duration 0
outages is typically much longer. Single line outages typically last 220
double line outages last 108 minutes. Although specific data on pipel'
available, they are expected to last several days to weeks. This ti
the storage availability. Therefore, the overall reliability/avail
arguably is lower than the transmission system. (These stat"
Statistics " Office of Pipeline Safety (u.S. Department 0
Special Programs Administration). http://ops.dotgov/sta
the past, what we are
er) appears to be heading
If risks of line failures were equal, the electric
as compared to the gas arterial. However
compared and, in both cases, are miniscule
failure are situation-specific and depend 0
study.
y, they are 1) Financing-
Funding - Who actually
current ratepayers? 4) What
ssues are described in the following
em based on forecasts of load and resources. BP A, un ook the transmission investments it detennined were
ith a high degree of probability. Some transmissionre n uded in the network's costs. These included, for example, theal ery facilities. So
, "
network" refers to the high voltage grid in the
less of where on the network an investment was made it was financed by
ed into rates charged to all network customers. Because the network is
ted, upgrades help to provide backup transmission and to maintain voltage
ut the system, so that all customers benefit from maintaining reliability. Since
stomers benefit, all customers pay. FERC historically has been supportive of this
nd of pricing for all electric utilities.
2/26/2004
Today s world is different. Now there are a variety of customers-generators, LSEs
marketers who buy and sell power and move it across the network. Under the Ope
Access Transmission Tariff (OA TT) customers generally fall into two categori
Network customers (served under the Network (or NT) rate) and Point-to-P .
customers (served under the PTP rate.) All customers pay for usage of
depending either on their load (NT) or their reserved capacity (PTP
BP A continues to make investments on behalf of its treaty
including the expected load growth of its NT customers.
consideration. In the simplest tenns, reliability projects
improve (or avoid degradations in) reliability. lternati
according to a variety of factors, including c 0 dete
returns the greatest economic benefit in a 0 the r
mer has the option of
the cost of capacity
finance the costs of the
n behalf of its other
needed only to meet specific
era!. Because the investment
stomer, that customer must come
ERC's so called "or test." According to that
ge its customer under these circumstances either theme ost, but not both. The "but for test" is about who
e "or test" is about how much they pay.
ts fi cial investment, the customer receives a credit on its transmission
credit is sufficient to repay the customer for its financial investment because
ould be applied according to prevailing transmission costs. In other words
g transmission rates are credited to the customer s account to repay its financial
ent. In the case at hand, for example, the customer would invest $186 million
us interest) to finance the new 100-mile capacity addition. At current rates of
8 Or, more precisely, who takes the risk.
2/2612004
$12.l6/kW-year, the customer s bill would be credited with that price times the amo nt
of transmission acquired until such time as the principal and interest were repaid
enew
the $186
ts books
repays
gainst
s paymg
To the customer the investment becomes a sunk cost and transmission is
as long as it takes to repay the investment. Thus, there is a tangible ec
the customer for its investment. As we will see, this is similar to h
financed and funded.
Note that while the customer takes the risk by financin
project. The distinction is important and, as we will s
world envisioned by FERC. Let's say the Hoozit Gen
million project that is the subject of this repo 9 BPA
including interest charges, and adjusts its
the investment (and investor, Hoozit) by
Hoozit's transmission usage. Once the i
for subsequent transmission usage.
For the other network c
principal), had BP
would be the diffe
project than the U.
then be re aid, wit
generation (or load)
recover costs and all
re ratepayers on the
e if the "OR" test
new service exceeded the
e incremental cost exceeded the
ew customer.
future direction. How does Hoozit benefit byall eive any money for its investment, just a creditill y a tangible economic benefit? The answer is yes
eneurial decision-making. It is instructive to compare
ther ellers. Some other sellers may have purchased long-term
ission out of existing capacity. Like Hoozit, these sellers
ission costs as "sunk " because they are required to pay for the
egar ess of whether they use it. Other sellers may connect to the system
transmission rights and take the risk of using non-firm transmission as
n average, at today s rates
, "
free" transmission means that Hoozit has about
advantage over these other sellers who to pay for transmission as they use it.
sellers would then avoid the $186 million investment, but would have to pay about
/MWh for transmission, when transmission is available and it is economic for the
9 Assume the "or test" does not trigger. That is the usual case.
2/26/2004
Predicting where FE
, but the general
FERC Standard M
related ac ' . . s, bcount
not up
fthe
est of the
sellers to run their generators. If transmission were not available at any time, the se
that depend on nonfinn transmission could not sell the power from their generat
Note that whether Hoozit sees the transmission investment as a sunk cos
when the decision is made. Prior to undertaking the project financin
question Hoozit faces is whether paying up front for the new tran
worth it compared to facing the congestion costs and risks it
expansion not made. At that point, there is no sunk cost.
undertakes the financial investment, it owns transmissio
Moreover, on the path in question, because Hoozit has
congestion costs, while any other party witho nn rig
in time, the transmission appears to be free gener
initial investment (financing the 1500 M 'ty exp
transmission service clearly was not free.
ork. FERC proposes that
etwork. (By this, they
on rates.) Generators
LSEs, generators, and
costs, primarily redispatch costs
edge congestion cost risk by the acquisition of
, in the case of R TO West, Catalogue
can be acquired through existing rights, by auction
, or by funding the investment in transmission capacity
ding is envisioned by FERC to be the key to developingex ns. This is more than participant financing, as is possible in. Th ustomer pays for the project and receives in return an amount of
e period. Regardless of how a customer acquires its CRRs , their value is as
mst congestion costs.
, Hoozit gets a financial credit worth about $2/MWh over the life of its contract.
morrow, Hoozit gets CRRs as a hedge against congestion costs. Economically, there
to Other costs such as those equivalent to today s Transmission Scheduling charges applicable to all
schedules may apply, but are not relevant to this analysis,
2/26/2004
That's not all. Once Hooz
increased and congesti
nodes) may increas
one location to red
congestion costs ofWInners ers.
on the
rofit from funding the
zit waits, someone else may
n the latter case, it wouldn'
may be reduced as a result of lower
shouldn t be much difference, at least in principle. Both represent advance purchases
transmission services. In fact, differences may and probably will arise.
One obvious difference is that today Hoozit knows that other similarly situ
will incur essentially the same level of transmission costs, either as up :fr
new construction with credits, take or pay transmission payments fo
transmission out of existing capacity, or pay as you go transmissi
tenn finn and nonfinn transmission. Tomorrow, Hoozit will
investing a known amount for a network expansion and r
facing an uncertain amount of congestion costs in the fu
congestion costs it faces when it makes its investment, b
congestion costs it faces subsequently. In addif , its in
transmission capacity) will have its own effi other
some predictable, some not. On top of tha capac
generation) will further change the various ion co
the value of the CRRs, as compared to cre ay
oday s system, for the same reasons.
ozit would have a clear $2/MWh advantage over
d be greater under the SMD proposal, or less; but it
of aying for the rolled in costs of the transmission system is thatt pa r the embedded costs of transmission. There is really no such
r test." If the generator detennines that the avoided congestion costs are
finance and fund the capacity expansion, regardless of how that cost
average embedded costs.
y, FERC contemplates that regional state advisory boards would infonn
nsmission providers when new generation capacity is required to meet resource
2/26/2004
adequacy standards as loads grow. This would be similar to today s network planni
reliability. These costs would be rolled into the transmission provider s compan
and passed along to all LSEs. This is viewed by FERC as a backstop. It beli
avoiding congestion costs will provide sufficient economic incentives to
participants to fund transmission capacity expansion.
For the case at hand
is for the transport
of the new 20" pip
pays for the embearteria
al service
existing
n of the
who
sts)
Sion.
11 costs
ipelines
Natural Gas Pi eline Fundin and Pricin
FERC defines three types of pipeline projects: an expa
(such as the case that is the basis for this report), a proj
customers (analogous to transmission upgrades for reli
two. The Commission s policy is that no sub' ies sh
benefit must fund expansions for addition ice. If
cannot be demonstrated, existing custom 0 be h
Expansion shippers must be willing to p
of the project. (See Appendix 2, Curren
for more detail.)
r who pays the average, or
customers benefit from the
enerator pays only the embedded
ower transmission pricing construct for new
customers is that the shipper does not necessarily
does have to fund the project. If the pipelineree tract terms, the pipeline owner, perhaps using a variety
shi ers, undertakes the financing and funding for the project.
aid by the rates that are charged to the shipper(s.) No shippers
e s will pay any of the costs of the capacity addition. It will beby e shipper. This corresponds to financing, funding and paying for
ities on the electric grid, but not to the hypothetical network expansion
where.
II If, however, the pipeline expansion can be achieved by looping an existing line and the toll is less than
the existing toll, the costs are rolled into existing rates. This would be similar to expansions of the electric
grid for reliability purposes.
2/26/2004
nes and electric power
tablish clear and
As stated previously, there is no perfect analogy or substitutability between a pipeline
a transmission line. The closest thing to an electric network would be the main t
the pipeline system. All gas must pass through these arterials. Branching pipe
however, have a clearly defined physical point of delivery and mayor may
interconnect with other pipelines.
Expansion shippers mayor may not increase the capacity of an e .
analogous to expanding electrical network capacity. Generall
would be at least some benefit to existing customers. Ther
expanded service mayor may not have to pay an increme
case that most closely resembles the hypothetical case at i
Although this pipeline-pricing concept differs
transmission capacity expansions, it appear
under FERC's SMD NOPR. Shippers who
pipeline rate, regardless. It is a sunk cost i
equivalent to saying there is zero cost for
would face zero cost transmi der th
alleviate the costs of con ey in
expansion, just as a sh' inc
alleviate "congestion cost
here from 40% to 50% less
of energy via electrical
vanta of pipelines increases directly as
distances-and 100 miles is reasonably
lly efficient.
be consistent across both pipelines and electric
In ases, existing consumers are protected against the
pan ns. If they benefit from the expansion they will pay
costs; if they don t benefit, they will pay nothing additional.
clear that merchant electrical transmission will be forthcoming
env ons.
c and gas transmission systems are planned independently. Planning the
system in a more integrated fashion could bring additional benefits to
nsumers. Generally, it will be cheaper to transport gas to load centers, but there
2/26/2004
Consistent with our findings, we do see plants
and building pipe, but fewer cases of locatin
transmission; for example, the Gray s Har
pipeline spur was built from the 1-5 corrid
sometimes dominate decisions about plant
effect is. As it was beyond the ope of t
which to rely.
ocess to identify
tnering of electric
prospective generators. The
I time and for system planners.
er one, but in both systems working in
are many circumstances in which electrical transmission upgrades would be m
economIC.
Recommendations and Next Ste
As the region s energy needs continue to grow and change, consume
integrated planning and development of the energy delivery syst
pipelines will be cheaper than electric transmission lines, esp
but as we found, there are numerous instances where elec
even the only alternative.
ng natural gas pipelines and for electric
be consistent. However, while merchantnd developed in the pipeline industry, it is not in the
stry. It remains to be seen whether FERC's vision of network
ted largely by merchant transmission will be fulfilled.
ed at FERC's decisions and how utilities are required to finance and fund
nsions. We did not, however, examine actual cases of merchant
n. On the electrical side, in the Pacific Northwest, there are practically none.
notable exception is the transmission required for generation interconnection
looks very much like merchant pipeline additions. However, that is far removed
m merchant transmission on the electric grid, an unproven concept in the region.
2/26/2004
As we noted, it is often the case that the direct beneficiaries of a pipeline addition ca
identified. Because they have a property right with a clear economic value, fina
requires rates of return somewhere in the 8 to 12 percent range, depending on
equity costs. In other words, it is a fairly low risk transaction.
Such is not the case for merchant electric transmission. Recall tha
transmission in the future goes beyond financing the investme
credits on one s bill. In the future, merchant electric trans
fund the investment and receive Congestion Revenue Ri
transmission owner thereby acquires a property right, w
unknown economic value. It is easy to imagine that the
would be much higher than we observe with line ow
willing to undertake such investments in t
Although R TO West, the proposed regio
Northwest, will have backstops to ensure
when or even whether R T will ac
owners will always be C's j
merchant transmiss
We recommend fu
about the charact
ordi
gr.
c Northwest, gas pipelines
gy. However, we did not
ver such a distance, the
i s become more economic than
IOns a uired as are with Alternating
lower. ffsetting that, a converter station is
n fact, their cost prevents DC lines from being
ot l' the regional transmission grid, TransCanada
g t ssibility of building a DC line from Northern Alberta to
While that project is not to transmit electric power generated byces it is not far-fetched to imagine another Canadian entity proposingectl the gas field and transmitting electric power via DC lines to the
est, or even California. Whether it would be economic to do so is unknown.
mend that the same regional body consider long distance energy transport in
y and to report on its findings. We also caution readers of this report to limit our
ings to the Pacific Northwest region.
2/26/2004
Supporting Members ofNGA
Appendix 1
Participants in BP A/NGA Study
Bonneville Power Administration
Northwest Gas Association (NGA)
A vistacorp
Kevin Christie
Jan Caldwell
2/26/2004
Appendix 2
Current FERC Expansion Rate Policy for Gas Pipelines
In the Policy Statement, the Commission defined three
projects: an expansion project to provide additional se
to existing customers by replacing existing fa . ities, i
additional flexibility; and a project that c s an e
improvements for existing customers. U Com
existing shippers should not have the rat their
the pipeline has built an expansion to pr ice t
customers' rates can be in for pr imp
project combines an ex th im to increase existing line
facilities are neede
The Commission s September 15 , 1999 Policy Statement12 on proposed gas pr .
established a no-subsidy policy favoring incremental pricing of pipeline
thereby changing the Commission s previous policy of giving a presum
rate treatment for pipeline expansions. The Commission found that r
sends the wrong price signals by masking the true cost of capaci
shippers seeking the additional capacity.
hat is made possible because of earlier, costly
disadvantaged because incremental pricing
lving a subsidy from existing customers because
the full cost of the construction that makes their new
sion indicated that the issue of the rate treatment for suchili e that always should be resolved in advance, before thethe line. Typically, pipelines file to apply current system rates for the
agr e to address rate issues in the pipelines next rate case.
12 Citing Certification of New Interstate Natural Gas Pipeline Facilities (Policy Statement), 88 FERC ~
227 (1999), clarification 90 FERC ~ 61,128 (2000), further clarification, 92 FERC ~ 61 096 (2000).
2/26/2004
IDAHO POWER COMPANY
CASE NO. IPC-06-
FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO. 10
Customer Relations & Research
DSM Programs
Jan uary 2004
Energy Efficiencyr--Leader
Program Specialist -
Residential
Program Specialist -
'--
Residential
Customer Relations & Research
DSM Programs
January 2005
Energy Efficiency f---Department
Leader Assistant
Economic Analyst
Program Specialist -
Industrial
I----Program Specialist -
Commercial
Program Specialist -
Special Needs
Program Specialist -
Residential
Program Specialist -
Residential
L - - - - - - - - - - - - - - - - - - - - - Market Segment
Coordinator -
Irrigation
Customer Relations & Research
DSM Programs
January 2006
Energy Efficiency
Leader
Department
Assistant
Economic Analyst
Program Specialist -
Industrial
Program Specialist -
Commercial
Program Specialist -
Special Needs
Program Specialist -
Residential
Program Specialist -
Residential
Program Specialist -
Irrigation
L-
------ --- ------- - -----
Market Segment
Coordinator -
Irrigation
Customer Relations & Research
DSM Programs
Brief Job Descriptions
Energy Efficiency Leader: The Leader position is responsible for supervising all aspects of
development, implementation , and management of the Company s demand-side management
programs, including regulatory reporting and regional representation of the Company in energy efficient
associations.
Program Specialist-Residential: Responsible for energy efficiency and/or demand response
programs for residential customers including program design, process development, system
integration, marketing and communications, contract management, and daily operations.
Program Specialist-Industrial: Responsible for energy efficiency and/or demand response programs
for industrial customers including program design, process development, system integration, marketing
and communications, contract management, and daily operations.
Program Specialist-Commercial: Responsible for energy efficiency and/or demand response
programs for Commercial customers including program design , process development, system
integration , marketing and communications, contract management, and daily operations.
Program Specialist-Special Needs: Responsible for energy efficiency and/or demand response
programs for customers with special needs including program design, process development, system
integration, marketing and communications , contract management, and daily operations.
Market Segment Coordinator -Irrigation: Responsible for representing irrigation customers
interests in programs and other Company activities. Responsible for energy efficiency and/or demand
response programs for irrigation customers including program design , process development, system
integration, marketing and communications, contract management, and daily operations.
Economic Analyst: Responsible for demand-side management analysis, financial, statistical, and
economic analyses to determine company, customer, and societal impact of DSM programs.
Department Assistant: Responsible for administrative support for the energy efficiency and demand-
side management staff.
IDAHO POWER COMPANY
CASE NO. IPC-O6-
FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO.
Response to Request No.
The information requested is CONFIDENTIAL and
is not provided to Mountain View Power