HomeMy WebLinkAbout20080727.tiff •
Xcel Energy" Siting and Land Rights
550 15th Street,Suite 700
PUBLIC SERVICE COMPANY Denver,Colorado 80202-4256
Telephone:303.571.7799
Facsimile:303.571.7877
December 3, 2007
Mr. Thomas Honn
Director, Dept. of Planning Services
Weld County
918 10th Street
Greeley, CO 80631
Dear Mr. Honn:
PSCo recently filed with the Colorado Public Utilities Commission (CPUC) an
application for approval of a Certificate of Public Convenience and Necessity (CPCN) to
• construct two simple cycle gas combustion turbines at its Ft. Saint Vrain Generating
Facility within unincorporated Weld County northwest of Platteville. Public Service
seeks to amend the contingency plan that was approved under our 2003 Resource
Plan, and it has requested expedited treatment from the CPUC due to the aggressive
development schedule. Consistent with the review timeframe we are requesting from
Weld County for, "USR 1063 Amendment for the Installation of Two Simple Cycle
Natural Gas Turbines (Units 5 & 6)", our CPUC application asks that the Utilities
Commission render a final decision no later than April 1, 2008.
I have enclosed a copy of the Certificate of Public Convenience and Necessity (CPCN)
for your review pursuant to C.R.S. 29-20-108 and other applicable state statutes.
As we continue working with your staff to meet the submittal requirements for the USR
1063 amendment, please contact Rick Thompson at (303) 571-7284, or me at (303)
571-7281 should you have any questions regarding the enclosed CPCN.
Sincerely yours,
hn Lu o
anage S ing and Land Rights
ublic Se ce Company of Colorado
• Cc: M. Fisher
Enclosures
2008-0727
BEFORE THE PUBLIC UTILITIES COMMISSION , t
• OF THE STATE OF COLORADO ;Uri,
< <
Docket No. n1A-4-11 o9e 2a17 f'„, ?7 P14 4: 32
IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF
COLORADO FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
TO CONSTRUCT TWO COMBUSTION TURBINES AT THE FORT ST. VRAIN
GENERATING STATION, FOR AN AMENDMENT TO ITS CONTINGENCY PLAN,
AND FOR EXPEDITED TREATMENT
MOTION FILED BY PUBLIC SERVICE COMPANY OF COLORADO FOR MODIFIED
PROCEDURE OR IN THE ALTERNATIVE EXPEDITED TREATMENT
Public Service Company of Colorado ("Public Service" or "Company"), through its
legal counsel, pursuant to 4 CCR 723-1400(c) and 1403(a), moves the Commission to
enter an order granting modified procedure under Rule 1403(a) for Commission
consideration of its application, or in the alternative for an order establishing a
• procedural schedule that results in a Commission decision no later than April 1, 2008.
The Company suggests that the deadline for responses to this motion be set as the
same date that interventions in this docket are due. Public Service states as follows in
support of this motion:
1. Public Service files this motion along with its application for a certificate of
public convenience and necessity ("CPCN") to construct additional generating facilities
at the Company's Fort St. Vrain station. The application is necessary because of
termination of a purchase power agreement ("PPA") between Public Service and
Squirrel Creek Energy LLC ("Squirrel Creek Energy").
2. A dispute between the two companies arose in August 2007 when Squirrel
Creek Energy requested a price increase. After analyzing information provided by
• Squirrel Creek Energy, Public Service reached the conclusion that there was a
• substantial risk that Squirrel Creek Energy would not be able to fulfill its obligations
under the PPA. The Company analyzed several alternatives, and determined that the
best option to guarantee its ability to meet its summer 2009 peak power needs would be
to self-build a gas fired peaking facility at its Fort St. Vrain facility. Public Service was
able to successfully conclude negotiations with Invenergy Thermal, LLC, Squirrel Creek
Energy's parent company, to terminate the PPA, and purchase the turbines that would
have been used in the Squirrel Creek project.
3. Public Service must replace the peaking power it was to have obtained from
the Squirrel Creek PPA in order to meet its reserve margin and avoid potential outages
during the summer of 2009. As more fully set forth in the application and accompanying
testimony, the Company analyzed alternatives to the self-build option, and believes that
the self-build proposal set forth in the application represents the best choice for the
• Company and its customers in terms of system reliability and cost. The self-build
proposal will cost the Company and its customers less than the cost under the original
PPA.
4. However, in order to have peaking generation facilities on-line by June of
2009, Public Service must begin construction by April 2008. This requires a
Commission decision granting a CPCN no later than April 1, 2008.
5. While this timeline is tight, as explained in the application and prefiled direct
testimony, no other alternative provides cost-effective power sufficient to meet 2009
summer peak requirements. The Company has diligently attempted to settle this matter
as quickly as possible, and to bring its application before the Commission in an
expedited fashion.
6. Commission Rule 1403 allows the Commission to consider a matter without
• hearing, upon the motion of a party, if the application is uncontested, if a hearing is not
2
required by law, and if the application and accompanying materials are accompanied by
•
attestations as to their accuracy and veracity. The application and materials contain
the requisite sworn statements, and a hearing is not required by law. Public Service
requests that the Commission grant the application without a hearing if the Commission,
after examining any interventions, determines that the application is uncontested.
7. In the alternative, due to the tight construction schedule required, Public
Service asks that the Commission grant expedited treatment of the application so that a
decision will be issued no later than April 1, 2008.
8. Public Service proposes the following schedule:
• Application and testimony filed November 27, 2007
• Interventions filed 30 days after Commission Notice
• Answer testimony and exhibits January 25, 2008
• Rebuttal testimony and exhibits February 5, 2008
• Hearings February 11-15, 2008
• Simultaneous statements of position February 29, 2008
• Commission decision March 26, 2008
9. If this matter proceeds to hearing, Public Service requests that the
Commission hear this matter en banc, because its familiarity with the Company's
resource needs and dockets will allow a more efficient proceeding. If the Commission
chooses to assign the application to an administrative law judge for hearing, Public
Service asks that it grant the motion for an expedited schedule and issue an initial
decision itself.
10. While the proposed schedule is compressed, under the schedule, the
Commission would be issuing a decision a little more than one week less than the
•
3
statutory 120 day timeframe set forth in C.R.S. §40-6-109.5. The Company believes the
•
schedule is fair to potential intervenors and the Staff of the Commission, and will allow
for a thorough hearing of issues related to the application.
11. Public Service does not seek a waiver of response time to this motion.
Rather, it asks the Commission to require responses to be filed along with any
interventions, and that the Commission issue a ruling on this motion as soon as
practicable after the intervention period has expired.
WHEREFORE, Public Service Company of Colorado respectfully requests that
the Commission grant Public Service's Application without a hearing as allowed by Rule
1403(a), or in the alternative grant an expedited schedule as discussed in this motion.
DATED November 27, 2007.
PUBLIC SERVICE COMPANY OF COLORADO
• By
William udley, #26735
Assistant General Counsel
Xcel Energy Services Inc.
1225 Seventeenth Street, Suite 900
Denver, Colorado 80202
(303) 294-2842
Facsimile No. (303)294-2852
bill.dudlev a(�xceleneray.com
RYLEY CARLOCK& APPLEWHITE
Dudley P. Spiller, #7908
Mark T. Valentine, #29986
1999 Broadway, Suite 1800
Denver, CO 80202
T: (303)813-6715
F: (303) 595-5139
dspiller rcalaw.com
mvalentinea rcalaw.com
ATTORNEYS FOR PUBLIC SERVICE
• COMPANY OF COLORADO
4
.
CERTIFICATE OF SERVICE
I hereby certify that the original and fifteen copies of the foregoing Motion for
Modified Procedure or in the Alternative Expedited Treatment were hand-delivered this
g ? day of November, 2007,to:
Doug Dean, Director
Public Utilities Commission
1580 Logan, Office Level 2
Denver, CO 80203
•
-52/tAkC
5
E5
Of COL('':
t).y Xcel EnergysM 2001NOV 27 PM 4: 34
PUBLIC SERVICE COMPANY
IN THE MATTER OF THE APPLICATION OF
PUBLIC SERVICE COMPANY OF COLORADO FOR
A CERTIFICATE OF PUBLIC CONVENIENCE AND
NECESSITY TO CONSTRUCT TWO COMBUSTION
TURBINES AT THE FORT ST. VRAIN GENERATING
STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED
TREATMENT
DOCKET NO. 07A-y/eQE
DIRECT TESTIMONY
AND EXHIBITS
November 2007
• BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
Docket No.
IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF
COLORADO FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY TO
CONSTRUCT TWO COMBUSTION TURBINES AT THE FORT ST. VRAIN GENERATING
STATION, FOR AN AMENDMENT TO ITS CONTINGENCY PLAN, AND FOR EXPEDITED
TREATMENT
Pursuant to C.R.S. §40-5-101, Rules 3002(a)(III), 3102, 3614 and 3615 of the
Commission's Rules Regulating Electric Utilities, 4 CCR 723-3, and Rules 1003 and 1403 of
the Commission's Rules of Practice and Procedure, 4 CCR 723-1, Public Service Company
of Colorado ("Public Service" or "Company"), through its legal counsel, hereby applies for a
certificate of public convenience and necessity ("CPCN") for authority to construct two gas-
• fired combustion turbines at the Company's Fort St. Vrain generating station, for approval of
an amendment to the Company's approved Contingency Plan, and for expedited treatment of
this application. Public Service respectfully states as follows in support of this Application:
The Commission Should Grant a CPCN and Approve an Amendment to the Company's
Contingency Plan
1. Public Service requests a CPCN and an amendment to its Contingency Plan so
that it may implement a new contingency plan to replace power lost due to the termination of
a signed purchased power agreement ("PPA") with Squirrel Creek Energy LLC ("Squirrel
Creek Energy"). The PPA would have provided the Company with power to meet system
peak demands in the summer of 2009 and beyond. The termination of the PPA is a result of
negotiations between Public Service and Invenergy LLC ("Invenergy"), the parent company to
Squirrel Creek Energy, over Public Service's uncertainty regarding Squirrel Creek Energy's
•
1
• ability to adhere to the terms of the PPA and meet its contract deadlines for providing
capacity to meet the Company's 2009 system peak demand.
2. The Squirrel Creek project was selected as a result of competitive bidding in the
2005 All Source Solicitation. The PPA was signed on October 23, 2006. Under the PPA
Squirrel Creek Energy agreed to construct a 525-550 MW combined cycle gas-fired electric
generating facility near Fountain, Colorado, and to sell the output of the project to Public
Service. Squirrel Creek Energy had the option to build the project in two phases. One phase
involved the installation of two 130 MW (nominal summer rating) combustion turbines to be
placed in service by the summer of 2009. The other phase involved conversion of the simple
cycle facility to a combined cycle plant by 2010 by installing a steam turbine. Public Service
intended that the initial, combustion turbine phase of the Squirrel Creek project would be
used to meet the Company's 2009 summer peak demand.
• 3. On August 14, 2007, Squirrel Creek Energy met with Public Service and advised
the Company that it would need an increase in the capacity price of the PPA because of an
escalation in the cost of certain necessary components and an increase in the cost of
engineering and construction contracts. This request was formalized in a letter Squirrel
Creek Energy sent to Public Service on August 20, 2007, in which Squirrel Creek Energy
sought a 16% increase in the capacity price of the PPA and sought changes to other contract
terms including delay damages and contract deadlines for completion of the combined cycle
phase of the project. In the letter, Squirrel Creek Energy also proposed an alternative project
which would have been a simple cycle-only facility at Squirrel Creek. Squirrel Creek Energy
advised Public Service that the revenue stream under the existing PPA was unlikely to allow
Squirrel Creek Energy to finance construction of the project.
4. Public Service rejected the request for a price increase and sought assurances
from Squirrel Creek Energy that it would be able to perform under the terms of the signed
2
• contract. Public Service did not receive the requested assurances and, based upon the
information provided by Squirrel Creek Energy, concluded that the capacity price bid by
Squirrel Creek Energy and set forth in the signed PPA would not support the necessary
investment to allow the project to proceed to completion. The Company concluded that there
was a substantial risk that Squirrel Creek Energy was incapable of meeting the required 2009
in-service date for the combustion turbines. Moreover, allowing a price increase after the
PPA was signed, and just before construction of the project must begin, would threaten the
integrity of the competitive bidding process and would be unfair to Public Service customers
and other bidders.
5. Public Service undertook extensive negotiations with lnvenergy to determine
whether a comprehensive resolution could be reached that would avoid litigation, protect
Public Service's customers, and allow the Company to meet its 2009 service obligations.
• 6. After receiving Squirrel Creek Energy's demand for a price increase in August
2007, Public Service immediately began contingency planning by evaluating its options for
meeting the 2009 summer peak. The options that Public Service considered included
evaluating Squirrel Creek Energy's August 20, 2007 proposals, planning the development of
a project concurrently with the Squirrel Creek project, undertaking additional Demand Side
Management, increasing interruptible load, purchasing capacity from expiring contracts,
accelerating Comanche 3, purchasing capacity from area utilities, and undertaking market
purchases using transmission import capability. The primary goal of the Company was to
ensure reliable service during the summer 2009 peak. The Company's investigation
ultimately resulted in the conclusion that the most reasonable, cost-effective way to assure
adequate capacity to meet the summer 2009 peak was to self-build at the site of the existing
Fort St. Vrain generating station. This site has the advantages of appropriate zoning,
• available water and natural gas supplies, transmission access, and rail access. Local
3
• permitting is also achievable as set forth in the testimony of Public Service witness John
Lupo. No other project, according to Public Service's analysis, could be built in time to meet
the 2009 summer peak.
7. After the Company learned that Squirrel Creek Energy would likely be unable to
construct its project in time to meet the Company's summer 2009 peak and before the
Company concluded the negotiations that led to the agreement terminating the PPA, the
Company began making arrangements that were essential in order to assure that it would be
able to exercise the self-build option in a timely manner. Those crucial arrangements
included reserving two nominal 150 MW Siemens combustion turbines at a nonrefundable
reservation fee of $2.0 million. The prompt reservation of the Siemens combustion turbines
was a prudent measure to assure that the Company had enough capacity to meet its 2009
summer peak, as explained in the testimony of Public Service witness Gregory Ford. The
• $2.0 million reservation fee is included in the total price of the Fort St. Vrain project.
8. As a result of their negotiations, Invenergy and Public Service agreed that the
PPA would be terminated and that the Company will acquire Invenergy's two General Electric
"F" class simple cycle turbines and one steam turbine that would have been used at the
Squirrel Creek site. Public Service will also acquire the leasehold obtained by Invenergy for
the Squirrel Creek site. Public Service will use the two simple cycle turbines in the proposed
Fort St. Vrain project and will sell the steam turbine or use it in a future project, which may
include the proposed repowering of Arapahoe Station. The Company is not seeking recovery
of the cost of the steam turbine at this time.
9. As discussed in its filings in Docket No. 07A-107E, unforeseen circumstances
have changed the nature of the Public Service system since the selections were made in the
2005 All Source bid evaluation. A lower peak demand and energy forecast, and increases in
• renewable energy requirements and demand side management requirements, have reduced
4
• Public Service's energy and capacity needs for 2009, and changed its immediate need to a
need for low cost capacity resources. Changing from a combined cycle facility to a simple
cycle facility meets the Company's needs in 2009 and beyond and reduces excess capacity
in the years 2010 through 2012.
10. As discussed in the testimony of Karen Hyde, the proposed project will cost less
than any of the following: the price set forth in the original PPA, the price increase sought by
Squirrel Creek Energy, or a similar alternative put forth by Squirrel Creek Energy.
Accordingly, the proposed project will save Public Service customers money.
11. There is no question that additional power to meet peak demand in the summer
of 2009 is required, as set forth in Public Service's Commission-approved 2003 Least Cost
Plan and the 2007 Colorado Resource Plan. The 2003 LCP application, and the Company's
application in Docket No. 07A-107E regarding its contingency plan, sets forth in detail the
• analysis which demonstrates the need for peaking resources.
12. If Public Service does not have additional capacity on line by the summer of
2009, there is a real danger of outages because without a replacement for the Squirrel Creek
project, Public Service will be 379 MW short of its 16 per cent reserve margin. Due to
construction time constraints, the only way for this power to be obtained at a reasonable cost
in time to meet the Company's 2009 summer peak is for Public Service to self-build two gas-
fired combustion turbines at Fort St. Vrain. Public Service could not import sufficient power
to cover the peak demand and reserve requirements without new construction because of
transmission constraints into Colorado. A competitive bid process will take too long to
complete, as discussed in the testimony and exhibits of Public Service witness Karen Hyde.
13. A CPCN and an amendment to the Company's Contingency Plan are needed
because without the Squirrel Creek project, the Company will be short of peaking power for
• the summer of 2009. The proposed facility represents a solution that is in the best interests
5
• of the customers and the Company, and is a solution that upholds the integrity of the
Commission's competitive bid process.
14. For the above reasons, Public Service believes that public convenience and
necessity require granting this application, and that the Commission should grant an
amendment to the Company's Contingency Plan, deem the Company's costs of this project
to be prudently incurred, and allow the costs of the project to be included in base rates in the
Company's next rate case.
Request for Modified Procedure or Expedited Treatment
15. Public Service asks to have this application considered under the Commission's
modified procedures pursuant to Rule 1403 of the Commission's Rules of Practice and
Procedure, as set forth in a motion filed concurrently with this application. However, if the
Commission determines that the Commission's modified procedures should not apply to this
• application, Public Service respectfully asks that the Commission render a final decision in
this matter according to a proposed schedule set forth in the motion and as also described
below, but no later than April 1, 2008.
16. Construction must begin in April 2008 for the facility to be in commercial
operation in time to meet the Company's summer 2009 system peak. C.R.S. §40-6-109.5
contemplates a final Commission decision within 120 days after the application is deemed
complete, except that the Commission may extend that period if necessary. Public Service
requests an aggressive procedural schedule in order to allow the Company to self-build the
peaking capacity necessary to meet its 2009 summer peak demand. The Company's
proposed procedural schedule is set forth at the end of this application. This timeline is
about a week short of the 120 days set forth in C.R.S. §40-6-109.5.
•
6
• 17. The Company has diligently proceeded with activities necessary to complete the
project on time and has not delayed in any way, as explained in the prefiled testimony and
exhibits of its witnesses.
Direct Testimony and Exhibits
18. Public Service is submitting with this application testimony and exhibits from the
following witnesses:
a. Karen T. Hyde, Vice President, Resource Planning and Acquisition for Xcel
Energy Services Inc. Ms. Hyde explains how the need for this project arose and
provides a general overview of the project. She describes the need for the project,
how the proposed plant fits into the Company's 2003 LCP, the estimated total cost of
the project, the need for a waiver of the Commission's competitive resource
acquisition rules, and the need for expedited consideration of this application.
• b. Gregory L. Ford, Director, Engineering and Design Services for Xcel Energy
Services Inc. Mr. Ford describes the technology used in the plant, the cost of the
project, and the plant site,
c. John Lupo, Manager, Siting and Land Rights, Xcel Energy Services Inc. Mr.
Lupo describes factors that led to the proposal to locate the project at the Fort St.
Vrain generating station and the land use permitting requirements for the proposed
site.
d. Gary Magno, Principal Environmental Analyst for Xcel Energy Services Inc. Mr.
Magno describes the environmental permits required for the project.
e Gerald Stellern, Manager of Transmission Reliability and Assessment for Public
Service. Mr. Stellern describes the transmission network upgrade requirements
associated with the construction and operation of the project. He also explains that
•
7
• the termination of the Squirrel Creek PPA will not impact the Company's Midway-
Waterton transmission project approved by the Commission in Decision No. C07-
0750.
Information Required by Rule 3102
19. Facts Relied Upon to Show that the Public Convenience and Necessity Require
Granting this Application. The above discussion sets forth the facts that demonstrate that the
public convenience and necessity require granting this application. The Company's proposal
is the most cost-efficient way for it to handle the contingency the Company faced and to
guarantee reliable service in the summer of 2009.
20. Estimated Project Costs. The cost of the project is expected to be $201.2
million. This figure includes all costs incurred by the Company to be able to provide reliable
service in 2009. It includes the costs of all Invenergy assets acquired by the Company that
• will be used in the construction of the Fort St. Vrain project, including the GE combustion
turbines, as well as the reservation fee for the Siemens turbines, and construction and
transmission costs associated with the Fort St. Vrain facility. Based upon Public Service's
experience, the final cost should be within +/- 20 percent of this estimate. Public Service has
the resources to develop the project as proposed. The Company will finance the project
using a combination of internally generated funds, debt, and equity. The project will provide
savings to the Company's customers of roughly $10.0 million when compared to the price
under the original PPA with Squirrel Creek Energy and $15.0 million when compared to the
combustion turbine PPA proposal made by Invenergy. Net proceeds from the sale (or
market value) of the steam turbine will be netted against the project price once the sale or
other use of the steam turbine occurs.
•
8
21. Schedule for Construction. The Company must begin construction as soon as
possible after it receives Commission approval, but no later than April 2008. The expected
in-service date is June of 2009. A proposed construction schedule is attached as an exhibit
to the testimony of Gregory Ford.
22. Maps and Electric One-Line Diagrams (IF NEEDED). A general arrangement
diagram of the project is attached as an exhibit to the testimony of Gregory Ford.
23. Alternatives Studied. Public Service has studied several alternatives to the
proposed plant, and concluded that the self-build process is the most efficient and cost
effective way Public Service can meet its 2009 peaking needs. The alternatives considered
include paying the increase demanded by Squirrel Creek Energy for the project contracted
for in the PPA and finding the necessary capacity elsewhere. The alternatives studied are
set forth in the testimony of Karen Hyde.
• 24. Paying the requested price increase would compromise the integrity of the
competitive bidding process and obtaining the power elsewhere is neither realistic nor
economically feasible. Regardless of any negotiated terms, Public Service had significant
doubt that Squirrel Creek Energy could complete the project in time for the 2009 summer
peak. A discussion of these alternatives is set forth in detail in the testimony of Karen Hyde.
It is clear that Public Service cannot obtain the essential resources through a competitive
bidding process. A competitive bidding process would simply take too long to complete the
project in time to meet the summer 2009 system peak demand. Public Service does not
believe it feasible to issue an RFP, receive and evaluate bids, and negotiate contracts in time
for an April 2008 construction start date.
25. Public Service believes that a self-build project will benefit the Company's
customers because there will be a savings as compared to the Squirrel Creek Energy PPA,
• and the self-build option will guarantee reliable service.
9
• 26. Prudent Avoidance Measures. This information is not required for this
application.
27. Information required by Paragraph C of the Rule. This information is not
required for this application.
I. Information Required by Rule 3002(b) and 3002(c)
28. Name and Address of Applicant. The applicant is Public Service Company of
Colorado. Public Service's principal office is located at 1225 Seventeenth Street, Suite 1000,
Denver, Colorado 80202. Public Service is a Colorado Corporation.
29. Name under Which Applicant will Provide Service In Colorado. All operations
conducted by the Company in Colorado are conducted under the name of Public Service
Company of Colorado, under the trade name of Xcel Energy.
30. Representatives to Whom Inquiries Concerning the Application Should be Made.
• Copies of all notices, other correspondence, and all inquiries concerning this application
should be sent to:
Karen T. Hyde
Vice President, Resource Planning and Acquisition
Xcel Energy Services, Inc.
550 15th Street
Suite 1000
Denver, Colorado 80202
(303) 571-6513
Facsimile No. (303) 571-6273
karen.t.hyde@xcelenergy.com
Paula M. Connelly, Esq.
Assistant General Counsel
Xcel Energy Services Inc.
1225 Seventeenth Street
Suite 900
Denver, Colorado 80202
(303) 294-2222
Facsimile No. (303) 294-2194
paula.connelly@xcelenergy.com
•
10
• William M. Dudley, Esq.
Assistant General Counsel
Xcel Energy Services Inc.
1225 Seventeenth Street
Suite 900
Denver, Colorado 80202
(303) 294-2842
Facsimile No. (303) 294-2852
bill.dudley@xcelenergy.com
and
Dudley P. Spiller, Esq.
Mark T. Valentine, Esq.
Ryley, Carlock and Applewhite
1999 Broadway, Suite 1800
Denver, Colorado 80202
(303) 863-7500
Facsimile No. (303) 595-3159
dspiller@rcalaw.com
mvalentine@rcalaw.com
31. Agreement to Comply with 4 CCR 723-3002(b)(IV)-(VI). Public Service has read,
• and agrees to abide by, the provisions of 4 CCR 723-3002(b)(IV)-(VI).
32. Description of Existing Operations and General Colorado Service Area. Public
Service provides electric and gas public utility service within Denver and in numerous areas
throughout the state of Colorado. The Company also provides steam service within the
downtown area of Denver. A full listing of Public Service's existing operations and service
area is set forth in Public Service's tariffs on file with the Commission.
33. Location of Hearing. If a hearing is held on this application, Public Service
prefers that the hearing be held at the Commission's offices in Denver, Colorado.
34. Acknowledgment. Public Service has read and agrees to abide by the provisions
of 4 CCR 723-3002(b)(Xl)(A)-(C).
35. Statement Under Oath. An attestation signed by Karen T. Hyde, Vice President,
Resource Planning and Acquisition, verifying that the contents of the application are true,
•
11
• accurate, and correct is attached hereto as Exhibit 1. Exhibit 1 contains the name, title, and
the complete address of the affiant, as required by 4 CCR 723-3002(b)(XII).
36. Information Required by Rule 3002(c'. Public Service hereby incorporates by
reference the following information, which is on file with the Commission in Docket No. 06M-
525EG:
a. A copy of Public Service's Amended Articles of Incorporation, which was
last filed on October 3, 2006;
b. The name, business address and title of each of Public Service's officers
and directors, which was last filed on November 9, 2007;
c. The names and addresses of affiliated companies that conduct business
with Public Service, which was last filed on November 9, 2007;
d. The name and address of Public Service's agent for service of process,
• which was last filed on October 3, 2006;
e. A copy of Public Service's most recent audited balance sheet, income
statement, and statement of retained earnings, which was last filed on April 2, 2007.
Proposed Procedural Schedule
37. If the Commission determines that its modified procedure should not apply to this
project, Public Service respectfully proposes the following procedural schedule in order to
assure that construction of this project may commence on time and that construction may be
completed in time to meet the Company's summer 2009 peak load.
• Application and testimony filed November 27, 2007
• Interventions filed 30 days after Commission Notice
• Answer testimony and exhibits January 25, 2008
• • Rebuttal testimony and exhibits February 5, 2008
12
• • Hearings February 11-15, 2008
• Simultaneous statements of position February 29, 2008
• Commission decision March 26, 2008
WHEREFORE, Public Service requests that the Commission enter an order
A. Granting the Company's application for a CPCN to construct two combustion
turbines at Fort St. Vrain;
B. Approving an amendment to the Company's Contingency Plan to reflect the
Commission's grant of the CPCN and the loss of the Squirrel Creek Energy PPA;
C. Deeming the Company's expenditures on the project to be prudent, including
the Company's expenditures on the Siemens turbines;
D. Allowing recovery of the costs of the project beginning in the Company's next
rate case: and,
• D. Granting the Company's concurrently filed motion for approval under modified
procedure, or in the alternative, granting an expedited procedural schedule.
DATED November 27, 2007.
PUBLIC SERVICE COMPS' e OLORADO
By:
William udley, #26735
Assistant General Counsel
Xcel Energy Services Inc.
1225 Seventeenth Street, Suite 900
Denver, Colorado 80202
T: (303) 294-2842
F: (303) 294-2852
bill.dudleyaxcelenergy.com
•
13
• RYLEY CARLOCK & APPLEWHITE
Dudley P. Spiller, #7908
Mark T. Valentine, #29986
1999 Broadway, Suite 1800
Denver, CO 80202
T: (303)813-6715
F: (303) 595-5139
dspiller 5!rcalaw.com
mvalenti nena.rcalaw.com
ATTORNEYS FOR PUBLIC SERVICE
COMPANY OF COLORADO
CERTIFICATE OF SERVICE
I hereby certify that the original and fifteen copies of the foregoing Application were
hand-delivered this,23 day of November, 2007, to:
Doug Dean, Director
• Public Utilities Commission
1580 Logan, Office Level 2
Denver, CO 80203
•
14
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
* * * * *
• IN THE MATTER OF THE APPLICATION )
OF PUBLIC SERVICE COMPANY OF )
COLORADO FOR A CERTIFICATE OF )
PUBLIC CONVENIENCE AND NECESSITY ) DOCKET NO.07A- E
TO CONSTRUCT TWO COMBUSTION )
TURBINES AT THE FORT ST.VRAIN )
GENERATING STATION, FOR AN )
AMENDMENT TO ITS CONTINGENCY )
PLAN,AND FOR EXPEDITED TREATMENT )
STATE OF MINNESOTA )
) ss.
CITY AND COUNTY OF HENNEPIN )
VERIFICATION
The undersigned, being under oath, says that she is Vice President, Resource Planning and
Acquisition of Xcel Energy Service Inc., the service company subsidiary of Xcel Energy Inc., the
registered public utility holding company parent of Public Service Company of Colorado. The
• undersigned further says that she has reviewed the Application and the supporting documentation and
has knowledge of the factual matters set forth herein. Under penalty of perjury the undersigned
declares that all statements made in the Application and supporting documents are true and complete to
the best of her knowledge. The undersigned understands that any statement made in violation of this
oath shallconstitute grounds for dismissal of the application or revocation of any authority granted.
3 O !'SIWE S1M d:',10e0Ci 40TMW Wil1C•MIi•`!�SQUurn; ;Titi Hyde
Vice President,Resource Planning and Acquisition
Subscribed and sworn to before me this day of November 2007.
:2
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Notary Pu-lib-
My Commission expire 4.t Jai>d, : 1140 .
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OF COL~
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es) Xcel EnergysM 21107NOV 27 PH L : 34
PUBLIC SERVICE COMPANY
IN THE MATTER OF THE APPLICATION OF
PUBLIC SERVICE COMPANY OF COLORADO FOR
A CERTIFICATE OF PUBLIC CONVENIENCE AND
NECESSITY TO CONSTRUCT TWO COMBUSTION
TURBINES AT THE FORT ST. VRAIN GENERATING
STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED
TREATMENT
DOCKET NO. 07A--Vgct E
DIRECT TESTIMONY
AND EXHIBITS
November 2007
•
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
Docket No.
IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF
COLORADO FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
TO CONSTRUCT TWO COMBUSTION TURBINES AT THE FORT ST. VRAIN
GENERATING STATION, FOR AN AMENDMENT TO ITS CONTINGENCY PLAN,
AND FOR EXPEDITED TREATMENT
DIRECT TESTIMONY AND EXHIBITS OF KAREN T. HYDE
• ON
BEHALF OF
PUBLIC SERVICE COMPANY OF COLORADO
November 2007
•
•
1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A. My name is Karen T. Hyde. My business address is 550 15th Street, Suite
3 1000, Denver, CO 80202.
4 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
5 A. I am employed by Xcel Energy Services Inc., the service company subsidiary
6 of Xcel Energy Inc., which is the public utility holding company parent of
7 Public Service Company of Colorado ("Public Service" or the "Company").
8 My title is Vice President, Resource Planning and Acquisition.
9 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS DOCKET?
10 A. I am testifying on behalf of Public Service.
• 11 Q. HAVE YOU PREPARED A STATEMENT OF YOUR EXPERIENCE AND
12 QUALIFICATIONS?
13 A. Yes. That statement is included as Attachment A.
14 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
15 A. The purpose of my testimony is to support the Company's application for a
16 certificate of public convenience and necessity to construct and operate two
17 combustion turbines at the site of the Company's Fort St. Vrain generating
18 station near Platteville, Colorado and an amendment to the Company's
19 Contingency Plan. I refer to this project as the Fort St. Vrain project for
20 simplicity.
21 Q. WHY HAS PUBLIC SERVICE FILED THIS APPLICATION?
22 A. Public Service has filed this application because of the termination of a
• 23 significant purchased power agreement ("PPA") entered into as part of the
1
• 1 2003 Least Cost Plan ("LCP") in the 2005 All Source solicitation. Pursuant to
2 that PPA, Public Service was to purchase the output of the a gas-fired
3 combined cycle generating plant to be constructed at Squirrel Creek, near
4 Fountain, Colorado. That project is known as the "Squirrel Creek project".
5 Q. WHAT IS THE SQUIRREL CREEK PROJECT?
6 A. The Squirrel Creek project was planned to be a 525-550 MW combined cycle
7 project bid by Invenergy LLC ("Invenergy") into the 2005 All Source
8 solicitation. The Squirrel Creek project was selected by Public Service as
9 part of the Least Cost Plan through the bid evaluation process. A purchased
10 power agreement was executed on October 23, 2006 for Squirrel Creek
11 Energy LLC ("Squirrel Creek Energy), a subsidiary of Invenergy, to construct
• 12 a 525-550 MW combined cycle facility to be in service in 2009. The PPA
13 contained a provision allowing the combustion turbines to come on-line in
14 2009 and the steam turbine to come on-line in 2010. Squirrel Creek Energy
15 exercised that option by letter to Public Service.
16 Q. YOU STATED THAT THE REASON FOR FILING THE APPLICATION IN
17 THIS DOCKET IS THE TERMINATION OF A PPA. WHAT DO YOU MEAN?
18 A. On August 14, 2007, employees of Invenergy, the parent company of Squirrel
19 Creek Energy, met with my staff to inform us that among other things,
20 escalation in the price of equipment and engineering and construction
21 services made it unlikely that Squirrel Creek Energy could finance the project
22 under the current PPA. In other words, the price in the signed PPA would no
23 longer support the necessary investment in the plant and allow Squirrel Creek
•
2
• 1 Energy to attract investors to fund the project. In a letter dated August 20,
2 2007, Squirrel Creek Energy sought changes to the Squirrel Creek PPA that
3 would increase the price and change certain other contract terms including
4 delay damages and contract deadlines for the staged combined cycle
5 completion. Squirrel Creek Energy also proposed a new alternative: a simple
6 cycle project at Squirrel Creek in which project construction would conclude
7 after the combustion turbines were placed in operation and the project would
8 not be converted to a combined cycle facility. I have included a copy of this
9 letter as Exhibit KTH-1 to my testimony.
10 Q. HOW DID PUBLIC SERVICE REACT TO THE PROPOSED CHANGES?
11 A. We were both surprised and alarmed by those proposed changes. The
12 project was scheduled to come on-line for the summer of 2009, which was
13 less than two years away. We already knew that the staging of the combined
14 cycle in-service date left Public Service a little short of capacity in the summer
15 of 2009 and it was immediately apparent that a failure of the project to meet
16 that in-service date would be very difficult to overcome. We rejected Squirrel
17 Creek Energy's proposed price increase and sought performance under the
18 terms of the PPA. Importantly, we also sought assurances that Squirrel
19 Creek Energy was taking the steps needed to ensure that the project stayed
20 on track for a commercial operation date of June 2009.
21 Q. GIVEN THE INFORMATION PUBLIC SERVICE HAD ABOUT THE
22 PROJECT, WHAT WAS THE LIKELIHOOD, AS OF AUGUST 2007, THAT
•
3
• 1 THE SQUIRREL CREEK PROJECT WOULD HAVE COME ON-LINE ON
2 TIME?
3 A. While it is difficult to say with certainty, I believe that the odds were too high
4 that it would not have come on-line on time. There are several reasons for
5 this. First, Squirrel Creek reported that project cash flows were insufficient to
6 support financing the project. Second, Squirrel Creek reported that market
7 conditions made its planned fixed-price turnkey EPC contract unavailable.
8 Contractors were only offering time and materials contracts. That meant that
9 Squirrel Creek Energy would still not know the full cost to build the project,
10 thus casting more doubt on the ability of Squirrel Creek Energy to finance and
11 complete the project. Third, Squirrel Creek Energy reported that certain
• 12 contractual terms related to the in-service date of the combined cycle portion
13 of the project were giving potential lenders concerns. These three factors
14 together introduced substantial and significant risk that Squirrel Creek Energy
15 would not be able to finance the project when it had planned to in April of
16 2008. The inability to finance or delays in financing the project would likely
17 have caused the project either to fail in the April 2008 time frame, which
18 would have been too late to start any contingency plan, or the project would
19 have been significantly delayed. I should note that our initial reaction was
20 that all of these elements were in Squirrel Creek Energy's control and were
21 part of the signed and effective PPA. However, rather than focusing on
22 Squirrel Creek Energy's issues, over which we had no control, the Company
•
4
• 1 focused on how it could best ensure that needed generation would come on-
2 line to meet the summer peak in 2009.
3 Q. WOULD THE LACK OF CAPACITY FROM THE SQUIRREL CREEK
4 PROJECT HAVE IMPACTED PUBLIC SERVICE'S ABILITY TO MEET ITS
5 LOAD IN 2009?
6 A. Yes. This lack of capacity from the Squirrel Creek project would have been
7 difficult to overcome because the Company counted on the Squirrel Creek
8 project to come on-line on time in compliance with the PPA. Without the
9 Squirrel Creek project, we would have been 379 MW short of meeting our
10 load and a 16% reserve margin in the summer of 2009. We assessed the
11 resources that might be available to us for the summer of 2009, including
• 12 additional demand side management ("DSM"), interruptible load, capacity
13 from expiring contracts, market purchases using transmission import
14 capability, accelerating Comanche 3's completion date, and capacity
15 available from area utilities. We found that we could not fill that 379 MW need
16 with available resources. No resources or combination of resources could
17 meet the need for the summer of 2009 without new construction. We
18 therefore concluded that the simple cycle capacity from Squirrel Creek or a
19 replacement project was essential for system reliability in 2009.
20 Q. DOES PUBLIC SERVICE NEED THE CAPACITY THAT WOULD HAVE
21 BEEN GENERATED BY THE FULL BUILD-OUT OF THE SQUIRREL
22 CREEK PROJECT TO A COMBINED CYCLE FACILITY?
•
5
• 1 A. Not at this time. When we recalculate our resource needs in 2009 through
2 2012, taking into account all of the changed circumstances that have
3 occurred since we evaluated the bids in the 2005 All Source RFP, our
4 resource need is no longer best satisfied by the full capacity that would have
5 been provided under the Squirrel Creek combined cycle PPA. Our current
6 peak and energy forecast is lower than it was when we evaluated the 2005 All
7 Source bids. In addition, our DSM projections and renewable energy
8 additions are higher than they were when we evaluated the 2005 All Source
9 bids. With these changes, our system will still eventually need combined
10 cycle energy, but that need will be delayed until 2013 and 2014. In addition,
11 when Comanche 3 comes on-line by the summer of 2010, the system will be
• 12 long on capacity for the summers of 2010 through 2012. Thus, changing the
13 Squirrel Creek capacity from a 525-550 MW combined cycle to a 260 MW
14 simple cycle project reduces the Company's "long" position in those years
15 and saves money.
16 Q. SINCE THE FORT ST. VRAIN PROJECT IS ONLY A 260 MW
17 COMBUSTION TURBINE PROJECT AND THE COMPANY IS
18 PROJECTING A 379 MW RESOURCE SHORTFALL IN THE SUMMER OF
19 2009, HOW WILL THE COMPANY FILL THE GAP AND MEET ITS LOAD
20 AND RESERVE REQUIREMENTS?
21 A. We plan to use our transmission import capability to purchase short-term
22 capacity for the summer of 2009 in the amount of about 119 MW. Because
23 Squirrel Creek Energy elected to stage the Squirrel Creek project and
•
6
• 1 therefore that project would have only provided, at most, a simple cycle
2 project on-line in the summer of 2009, we would have had to rely on short-
3 term capacity to fill that need in 2009, just as we will with the Fort St. Vrain
4 project.
5 Q. DID THE COMPANY CONSIDER GIVING INVENERGY THE PRICE
6 INCREASE IT REQUESTED?
7 A. Yes, but we rejected that option for several reasons. Those reasons were:
8 • A need to preserve the integrity of the bidding process;
9 • Concerns regarding the continued ability of this developer to perform
10 under the PPA regardless of the price increase; and,
11 • A desire to capture the benefits of converting the project to a simple
• 12 cycle project to produce customer savings.
13 Q. WHAT IS THE NATURE OF YOUR CONCERN REGARDING THE
14 INTEGRITY OF THE BIDDING PROCESS?
15 A. We are concerned with the integrity of any future bid process if any bidder is
16 left with the impression that its contract is not really a binding agreement, but
17 rather is an option to develop a project at a price to be negotiated at a later
18 time. We are concerned that if bidders ever had this impression, they would
19 "low ball" their bids and then later raise the bid prices when alternative options
20 available to the company had become limited or unavailable. It would also be
21 difficult, if not impossible, to evaluate, compare, and choose bids if prices
22 could later be changed. The price change requested by Invenergy for the
23 Squirrel Creek project is material — a 16% increase in the demand payment.
•
7
• 1 No price advantage would be gained for our customers through what is
2 intended as a "competitive" acquisition process if such substantial price
3 increases could be passed through during the project development phase of a
4 project. The price increase calculation based on the Squirrel Creek Energy
5 proposal is detailed in Exhibit KTH-2
6 Q. WOULD YOU STILL BE CONCERNED WITH THE CONTINUED ABILITY
7 OF THE DEVELOPER OF THIS PROJECT TO PERFORM UNDER THE
8 PPA AT THE PLANNED LOCATION EVEN IF IT WERE ALLOWED THE
9 REQUESTED PRICE INCREASE?
10 A. I would.
11 Q. WHY WOULD YOU STILL BE CONCERNED?
• 12 A. Squirrel Creek Energy said that it was unable to obtain a fixed priced EPC
13 contract for this project, which means that, even with the price increase it
14 requested, the project would still be exposed to continued project cost
15 escalation that could jeopardize financing. Again, waiting to know the fate of
16 this project until project financing is secured means that the Company would
17 lose alternatives to build replacement capacity by the summer of 2009.
18 Q. PLEASE DESCRIBE THE BENEITS ASSOCIATED WITH MOVING FROM
19 A COMBINED CYCLE TO A SIMPLE CYCLE COMBUSTION TURBINE
20 PROJECT.
21 A. As described earlier, the ability to terminate the original contract offered
22 savings because a smaller project results in less excess capacity in the years
23 2010-2012 than the Squirrel Creek project.
•
8
• 1 Q. WERE YOU ABLE TO FIND A PROJECT TO SERVE AS A CONTINGENCY
2 FOR THE SQUIRREL CREEK PROJECT?
3 A. Yes. During the time that we were negotiating with Squirrel Creek Energy,
4 the Company was also developing resource options for the Colorado
5 Resource Plan and identified Fort St. Vrain as a likely site for expansion.
6 When we received the news from Invenergy in August of problems with the
7 Squirrel Creek project, we quickly focused in on Fort St. Vrain as a resource
8 that could serve as a back-up to the Squirrel Creek project and the
9 corresponding PPA.
10 Q. DID SELECTION OF FORT ST. VRAIN AS A SUBSTITUTE LEAD THE
11 COMPANY TO STOP WORK ON THE SQUIRREL CREEK PROJECT?
• 12 A. No. For some time, we worked in parallel on Fort St. Vrain and the Squirrel
13 Creek project. However, we determined that maintaining parallel projects
14 would quickly get very expensive. As I mentioned, Invenergy's plan was to
15 finance the Squirrel Creek project in April 2008. Given that the majority of the
16 project risks would materialize and come together at that time, we initially
17 believed it was necessary to develop in parallel, at least through April 2008, a
18 back-up project. As Mr. Ford explains, the tight timeline for a 2009 in-service
19 date requires that significant funds be expended prior to the needed start of
20 construction in April 2008. The necessary activities include the purchase of
21 major equipment, engineering, and the costs to permit a project. These
22 activities would all be largely completed before we would know if Squirrel
23 Creek Energy was able to finance the project. The expenses for the back-up
•
9
1 project would be prudently incurred because of the serious concerns that I
2 have described regarding the ability of Squirrel Creek to perform under the
3 PPA.
4 Q. DID PUBLIC SERVICE TAKE ANY STEPS TO ENFORCE THE PPA?
5 A. Yes. Under the PPA, the Company had claimed an anticipatory breach
6 based on the August 20, 2007 letter. Squirrel Creek rejected that claim and
7 indicated that it had performed under the PPA to date. As a consequence,
8 there was no clear path to immediate termination of the PPA. The parties
9 could have continued the debate regarding the need for assurances and
10 Squirrel Creek Energy's situation with the project, as well as various
11 resolutions to the problem, well beyond the time when the opportunity to
• 12 deploy alternatives had passed. While I lacked confidence that Squirrel
13 Creek Energy would obtain financing, I also could not guarantee this result
14 and, therefore, if we undertook development of a self-build contingency
15 project without reaching some agreement with Squirrel Creek Energy or
16 Invenergy, there was a potential that customers would be faced with the most
17 costly option — two projects when only one was needed. Therefore, we
18 looked for ways to reduce the need to have two projects proceeding in
19 parallel.
20 Q. HOW DID PUBLIC SERVICE RESOLVE ITS DISPUTE OVER THOSE
21 ISSUES WITH INVENERGY?
22 A. After carefully examining all other options, including a dual path, Public
23 Service and Invenergy entered into an agreement that would result in
•
10
• 1 adequate power supply for Public Service in 2009 and also not result in
2 significant new costs (such as increasing the price of the existing contract or
3 embarking on two parallel projects). The result of these extensive
4 discussions led to Public Service acquiring certain assets from Invenergy,
5 which it intends to deploy at Fort St. Vrain. As part of that transaction, the
6 Squirrel Creek PPA was terminated on November 16, 2007. In this way, we
7 can move forward with only one project — a two-combustion turbine addition
8 at Fort St Vrain.
9 Q. PLEASE DESCRIBE THE FORT ST. VRAIN PROJECT.
10 A. The project involves building a simple cycle generation plant at our Fort St.
11 Vrain facility. The project will consist of two peaking combustion turbines
• 12 obtained from Invenergy, the technology and engineering of which is
13 explained in more detail in the testimony of Public Service witness Gregory
14 Ford. It will be relatively easy to integrate the two facilities into the existing
15 plant. Together, the turbines will produce 260-300 MW of peaking power
16 depending on the season. As peaking facilities, they will operate for only a
17 small portion of the year, during the summer under peak load conditions.
18 Building this facility will allow the Company to maintain its 16 percent reserve
19 margin with a shortfall of only about 119 MW of needed additional short-term
20 capacity, and thus dramatically reduce the likelihood of outages in the
21 summer of 2009. The Company will be able to meet the June 2009 in-service
22 date with this self-build project only if construction begins in April 2008 at the
23 absolute latest.
•
11
• 1 Q. WILL CUSTOMERS SAVE MONEY BY TERMINATING THE SQUIRREL
2 CREEK PPA AND BUILDING THE FORT ST. VRAIN PROJECT?
3 A. Yes. I have looked at the economics in two ways and each shows a savings
4 to customers. First, I looked at the near term impacts by comparing the cost
5 under the original Squirrel Creek combined cycle contract to the costs of Fort-
6 St. Vrain for the period 2009-2012, which shows a savings of $9,736,390 on
7 a 2007 present value basis. Second, I looked at the cost of Fort St. Vrain
8 compared to the cost of Squirrel Creek Energy's proposal to downsize the
9 Squirrel Creek project from the original combined cycle configuration to a
10 simple cycle project— essentially the same project that we propose to build at
11 Fort St. Vrain, which shows a savings of $14,523,288, on a 2007 present
• 12 value basis. However, even if such savings did not exist, I believe that the
13 Commission should approve the construction at Fort St. Vrain because of the
14 uncertainty surrounding the Squirrel Creek project, which essentially left the
15 Company with no perfect options.
16 Q. CAN YOU EXPLAIN HOW YOUR CALCULATIONS WERE MADE?
17 A. Yes. First, I included all of the project costs (without the steam turbine),
18 including the Siemens reservation fee, the gas and electric interconnection
19 costs, the costs of transmission upgrades and other costs related to the
20 planned Squirrel Creek interconnection.
21 As Mr. Ford explains, the reservation fee to Siemens was a prudently
22 incurred expense. When we started looking at our ability to develop a back-
23 up project for the Squirrel Creek project in August 2007, we quickly found that
•
12
•
1 the market for combustion turbines was very tight. We were able to find
2 equipment for delivery on a schedule that would have supported an in-service
3 date of June 2009 but we were required to pay $2.0 million for the exclusive
4 right to negotiate to purchase those turbines. Because we were able to
5 acquire turbines from Invenergy, we did not convert that option to a purchase
6 order. We believe that this expenditure is a prudently incurred cost given the
7 uncertainty around Squirrel Creek Energy's performance and we therefore
8 include it in the cost of the Fort St. Vrain project.
9 The Company is requesting recovery of this amount paid by moving
10 this reservation fee from construction work in progress ("CWIP") to a
11 regulatory asset. Public Service proposes the amortization period for the
12 regulatory asset established for the payment to Siemens to be 5 years. This
13 period is consistent with periods established in the past by the Commission.
14 Based on the proposed amortization period, the annual amortization would be
15 $400,000.
16 Q. CAN YOU DESCRIBE IN MORE DETAIL THE ANALYSIS IN EXHIBIT KTH-
17 3?
18 A. Yes. This analysis looks only at the years 2009-2012. We picked these
19 years, because our Colorado Resource Plan ("CRP") shows that the
20 Company has capacity needs in 2013. Switching from a combined cycle
21 project to a combustion turbine project means that customers will have less
22 capacity on the system for the years 2009-2012. For the years 2010-2012,
23 the additional capacity of the combined cycle facility would have been excess
•
13
• 1 capacity in the system, so the lower capacity actually saves customers money
2 in those years. We estimated the energy savings lost because the lower heat
3 rate combined cycle project will not be built. The net savings to customers is
4 about $10.0 million on a 2007 present value basis. For this analysis, we did
5 not estimate savings beyond 2013, even though they will exist, because the
6 CRP will fill this need. We think that the Commission can be confident of the
7 savings depicted in Exhibit KTH-3. Note that Exhibit KTH-3 shows savings
8 during the highest cost years of the Fort St. Vrain project because of the way
9 utility revenue requirements are calculated.
10 Q. COULD THE SAME SAVINGS BE CAPTURED BY HAVING SQUIRREL
11 CREEK ENERGY BUILD THE COMBUSTION TURBINE PPA OPTION
12 THAT IT PROPOSED IN ITS AUGUST 20, 2007 LETTER?
13 A. No. Exhibit KTH-4 shows that the Squirrel Creek combustion turbine option is
14 actually more expensive over the life of the Fort St. Vrain project than the
15 Company's Fort St. Vrain proposal.
16 Q. CAN THE COMPANY FILL THIS RESOURCE NEED THROUGH A
17 COMPETITIVE BIDDING PROCESS?
18 A. No. There is insufficient time for another competitive bidding process for this
19 project. As Mr. Ford explains, construction of the FSV project must start in
20 April 2008 in order to bring the project on-line before the summer of 2009.
21 Mr. Magno explains that the air permitting process timeline requires that an
22 air permit had to be filed in November 2007. Mr. Lupo explains that the land
23 use permitting process requires that a land use application had to be filed in
•
14
• 1 November 2007. There simply isn't adequate time to hold a competitive
2 bidding process, evaluate bids, negotiate contracts, and have a replacement
3 project permitted and constructed in time to meet the summer of 2009
4 resource need. Construction must begin in April 2008 for the project to be
5 completed on time.
6 Q. HOW DOES THE CONSTRUCTION TIMELINE AFFECT THE TIMELINE
7 FOR THIS APPLICATION?
8 To construct the project, we need a CPCN, which is the subject of this filing.
9 We ask the Commission for expedited treatment of the application so that we
10 have a Commission decision in slightly less than 120 days. The CPCN
11 application timeline needs to run in parallel with the timeline for the other
• 12 permits.
13 Q. WHAT ARE THE LIKELY HOURS OF OPERATION OF THE PLANT?
14 A. The proposed Fort St. Vrain plant will be a peaking plant and therefore will
15 only operate when the system load is at its highest. As Mr. Magno explains,
16 to facilitate the air permitting of the project, the project will be permitted as a
17 minor source, which will limit the generation to about 8.4% per year or 735
18 hours. In modeling, we estimate that the facility will be dispatched less than
19 that.
20 Q. IS IT IN THE PUBLIC INTEREST FOR PUBLIC SERVICE TO BUILD AND
21 OPERATE THIS PLANT ITSELF?
22 A. Yes.
23 Q. WHY?
•
15
• 1 A. There are several reasons for this. First, a self-build project will provide the
2 highest level of assurance that the project will come on-line for the summer of
3 2009. Second, in building this project we save about $10.0 million compared
4 to the Squirrel Creek Energy PPA, which Invenergy notified us could not be
5 completed at that price, and we save $15.0 million compared to Squirrel
6 Creek Energy's combustion turbine-only proposal. Most importantly, we
7 remove the uncertainty around Squirrel Creek Energy's ability to perform
8 under the PPA and we can start the Fort St. Vrain project in time to have that
9 project on-line by the summer of 2009. A final consideration that we did not
10 attempt to quantify in our benefits analysis is that by exercising a self-build
11 option, we will avoid the capital lease accounting issues that are discussed in
• 12 detail by George Tyson and Teresa Madden in the Company's recent
13 Colorado Resource Plan filing.
14 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
15 A. Yes.
•
16
• Attachment A
Statement of Qualifications
Karen T. Hyde
I have a Bachelor of Science in Metallurgical Engineering from Lafayette College
and a Master of Science in Mineral Economics from the Colorado School of Mines.
I began my career at Public Service 18 years ago. I have held various positions
including, Research Analyst where I forecasted regional economics as well as customer
and sales growth, Planning Engineer and Senior Planning Engineer in System Planning,
where I negotiated power purchase agreements, amendments to Power purchase
agreements and financing documents for PPAs. In System Planning, I also performed
production cost and expansion planning modeling and provided expert testimony in the
1993 IRP and FSV CPCN dockets on these topics on behalf of Public Service.
In 1995, I became a Business Development Analyst where I developed pricing
for Public Service's bids under various wholesale requests for proposals and I worked
on a team looking at restructuring various purchased power contracts. I eventually led
that team and become Team Lead over Purchased Power administration for New
• Century Energy. In 1998, I was promoted to Manager, Purchased Power. In 2002, I
was promoted to Director, Purchased Power. In this position, I was responsible for all
long-term purchased power contract negotiation and administration for all of Xcel
Energy's utility operating companies. In 2006, I was promoted to the position of Vice
President, Resource Planning and Acquisition. In this position I am responsible for
ensuring that the Company acquires sufficient generation and gas transportation
resources to meet its customer needs across the Xcel Energy operating companies, I
am also responsible for long-term wholesale requirements sales and for securing
transmission system access for native load. I have provided testimony before the
Colorado Public Utilities Commission in support of QF contract restructuring, new
purchased power contracts, the Purchased Capacity Cost Adjustment, the 2004
renewable RFP, and for approval of the projects associated with the 1999 IRP and the
2003 LCP. I provided policy testimony in the 2003 LCP contingency plan. I have also
provided testimony in Texas, New Mexico, Minnesota, and at the Federal Energy
Regulatory Commission.
Prior to working for Public Service, I worked as a forecaster for Baltimore Gas
and Electric and as a Lead Nuclear Engineer for the Department of Defense.
•
Exhibit KTH-1
Squirrel Creek Energy LLC
• One South Wacker Drive
Suite 2020
Chicago,IL 60606
August 20,2007
VIA EMAIL
Jeff Klein
Manager,Structured Purchases
Xcel Energy
1099 18th Street, Suite 3000
Denver,CO 80202
RE:Squirrel Creek Development Options
Dear Jeff:
As we discussed with your team in Denver last week,Squirrel Creek Energy has encountered
some totally unforeseen cost and schedule challenges. The purpose of this letter is to outline
the EPC market shifts causing those challenges,their impact on the schedule and pricing of
the project,and to propose a few options on how we might move forward.
Invenergy has a long history of success in delivering projects to Xcel,and we place
tremendous value on our relationship.
• Since we executed our agreement with you last year we have invested significant resources in
developing the plant which has resulted in:
• Fxecution of a 50 year ground lease with the Colorado State Board of Land
Commissioners
• Noticing to the Federal Land Managers of the comment period ending September
15,2007 for the draft air permit(application 06EP1170,Plant ID No. 041/1998)by
the Colorado Department of Public Health and Environmental
• Rezoning of the site to Planned Heavy Industrial District by El Paso County(PHID-
06-001)
• Issuance of Use Subject to Special Review(AL-06-012)by El Paso County
• Controlling the plants full water requirement until the end of October
We bid and contracted the project assuming the CTs would be sourced from the secondary
market at reduced cost,but despite the associated cost savings,the EPC market for all buyers
has changed markedly in the last six months with unprecedented demand for power plant
equipment,material and labor. This was unforeseen even though we have diligently priced
the EPC scope for the plant several times in the last year. Consequently,given the magnitude
of the pricing changes we received in July,we must reluctantly raise these issues. For your
reference,we have attached the history of our EPC evaluation showing the magnitude of the
cost changes(Exhibit A).
•
•
In order to address these issues,we are offering two PPA amendment proposals for your
consideration. The first maintains the existing contract,with the project reaching CT COD in
2009 and converting to CC in 2010. The major change in this proposal is an increase in the
capacity payment. Additionally,we have raised a few additional issues that we would hope
to address as part of the amendment. This proposal is attached as Exhibit B.
The second proposal reduces the impact of the escalating prices of the EPC services by
reducing the scope to a simple cycle project. This project would also meet a summer 2009
COD. This proposal is attached as Fxhibit C. Please note,however,that though the water
requirement is greatly reduced and the construction timeline is shortened under this option,
Squirrel Creek Energy would need to amend its Special Use Permit(SUP). If Xcel selects
this option we expect that this SUP amendment can be completed to meet the schedule
requirements,but we would need some contract flexibility in order to accommodate this
issue.
We realize that you operate in a complex regulatory environment,and making contract
changes of this nature,even if you determine that they are in the best interest of your
customers,cannot be accomplished overnight. However,we do face some pressing decisions
regarding financial commitments on water,the electrical interconnection,and major
equipment. As such,our ability to maintain the 2009 COD will largely be a function of how
•
quickly we can work together to determine a path forward. With several critical expenditures
coming up for the project,we will need to execute an amendment by September 15 to
maintain the schedule and pricing set forth in the proposals. For your reference,we have
outlined the critical timeline issues that we face in Exhibit D.
In closing,while this situation creates real challenges for both of us,we are confident that
even with the proposed changes,Squirrel Creek Energy will be competitive resource for
PSCo,with costs lower than any alternative,and online to meet your summer 2009 needs.
We realize that the timeline is challenging for resolution,but will make all possible resources
available so that we might find an approach that allows us to continue to meet your
generation needs.
Please feel free to call me if you would like to discuss this further.
you,
D.
SQUIRREL CREEK ENERGY LLC
cc: Karen Hyde
Jeff Hild
•
•
Exhibit A—EPC Evaluation
Date Contractors Providing Quotes Range of Quotes
10/2006 Signing of the PPA $221
11/2006 TIC/UE,Fluor,Worley $214-229
ParsonsBE&K
12/2006 TIC/UE,Fluor,Worley $219-243
Parsons/BE&K,CH2MHIT L
02/2007 TIC/UE,Fluor,Worley $230-247
Parsons/BE&K
07/2007 TIC/UE;Gemma/BAEAC $277-287
Note: Above EPC Pricing does not include Combustion Turbines(2)and Steam
Turbine. The supply cost of these major three major pieces of equipment and auxiliaries
• (typically 28-33%of total EPC Costs)has not been subjected to the industry's escalation.
The Owner has not used the current market value of these three major pieces of equipment in
its evaluation.
•
•
Exhibit B—Combined Cycle Proposal
Description The terms below would be implemented into the current contract
between Squirrel Creek Energy LLC and Public Service of Colorado
in the form of an amendment.
Price The Capacity Price(Sec. 8.1)after May I,2010 would increase from
$6.61/kw-month to$7.75/kw-month
Start Charge The Payment for Turbine Starts(Sec.8.6)would be reduced from
being starts based at$14,875/turbine-start on NG to the greater of(a)
$13,500/turbine-start on NG,or(b)$450 per fired hour,and from
$22,313/turbine-start on oil to the greater of(a)$21,000/turbine-start,
or(b)$675 per fired hour
Delay
Damages Delay Damages(Sect. 12.4(A)(1))for COD of the combined cycle
would not begin to accrue until May 1,2010,and would accrue at
$100/MW-day following August 31,2010 until termination.
• Defaults Defaults for delays(Sec. 12.1(C)(2))would be revised to allow for 440
days of delays(vs.380),and 530 days total(including the IE extension
and Major Equipment Malfunction)(vs.470)
NG Delivery
Pressure The required pressure for delivered natural gas(Sec.5.5(C)(iii))would
be reduced from 550 psi to 500 psi at the delivery meter
The foregoing terms and conditions are for discussion purposes only,and any final
agreement is subject to further internal review by each party. The parties shall only be
bound when terms of the transaction are set forth in a definitive agreement
411
Exhibit C—Simple Cycle Proposal
Description The terms below would be implemented into the current contract
between Squirrel Creek Energy LLC and Public Service of Colorado
in the form of an amendment. This proposal only coven the major
commercial issues. Implementation would involve larger changes to
conform to the purpose of a simple cycle agreement
Configuration
The facility would be a two unit,GE 7FA dual fuel,simple cycle
facility,similar to Spindle Hill
Price The Capacity Price(Sec. 8.1)be$5.55/kw-month beginning upon the
CT Operation Date,and escalate annually by 2%
Start Charge The Payment for Turbine Starts(Sec. 8.6)would be reduced from
being starts based at$14,875/turbine-start on NG to the greater of(a)
$13,500/turbine-start on NG,or(b)$450 per fired hour,and from
$22,313/turbine-start on oil to the greater of(a)$21,000/turbine-start,
• or(b)$675 per fired hour
Delay
Damages Delay Damages(Sect. 12.4(Ax1))would cease upon CT Operations
Date,and the Relief Payments(Sec. 8.7)would be eliminated
Defaults Defaults for delays(Sec. 12.1(CX2))would be reverted to those set
forth in 12.1(C)(1),provided,however,that the CT Operation Date
will replace the Commercial Operations Date for the purposes of
triggering the default
NG Delivery
Pressure The required pressure for delivered natural gas(Sec.5.5(C)(iii))would
be reduced from 550 psi to 500 psi at the delivery meter
The foregoing terms and conditions are for discussion purposes only,and any final
agreement is subject to further internal review by each party. The parties shall only be
bound when terms of the transaction are set forth hr a definitive agreement
•
•
Exhibit D—Decision Timeline
Payment
Date Project Commitment ($MM) Impact of Missing Commitment
09/01/2007 GE Combustion Estimate$1-2 Price increase for Combustion
Turbine Dual Fuel MM Turbines' Dual Fuel Conversion.in
Conversion the Field,instead in GE Greenville
Factory. GE Field Service and Parts
more expensive in Field. Applies to
Combined and Simple Cycle costs.
9/15/2007 EPC Contractor $12MM(Over 1. COD date of the Combined
Limited NTP for Long 5 Months of Cycle will be pushed
Lead Items and LNTP) outward based on next
Locking Prices and available equipment
Available Equipment manufacturer slots(e.g.Long
Manufacturing Slots. Lead Items: Critical High
Energy Pipe,HRSOs,Main
345kV Transformers,etc).
• 2. EPC Prices will continue to
escalate on Combined and
Simple Cycle based on
commodity and equipment
demands/reduced
competition. Also,current
potential EPC Contractors
may book other jobs,
reducing competition.
09/15/2007 LGIA Second Letter of $2 MM+ Loss of Owner's Capital if PPA is
Credit Interest terminated.
10/31/07 Water Closing $5 MM Water Contract Default,$250,000
liquidated damages
11/1/2007 Locking Available $5MM(Over 6 COD date of the Simple Cycle will
Equipment Months of be pushed outward based on next
Manufacturing Slots. LNTP) available equipment manufacturer
slots(e.g.Long Lead Items: Main
345kV Transformers,Iso-Phase Bus
etc).
•
EXHIBIT KTH-2
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Xcel EnergysM 2°°lN0V 27 NI 4134
PUBLIC SERVICE COMPANY
IN THE MATTER OF THE APPLICATION OF
PUBLIC SERVICE COMPANY OF COLORADO FOR
A CERTIFICATE OF PUBLIC CONVENIENCE AND
NECESSITY TO CONSTRUCT TWO COMBUSTION
TURBINES AT THE FORT ST. VRAIN GENERATING
STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED
TREATMENT
DOCKET NO. 07A--yi,q E
DIRECT TESTIMONY
AND EXHIBITS
November 2007
•
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
Docket No.
IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF
COLORADO FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
TO CONSTRUCT TWO COMBUSTION TURBINES AT THE FORT ST. VRAIN
GENERATING STATION, FOR AN AMENDMENT TO ITS CONTINGENCY PLAN,
AND FOR EXPEDITED TREATMENT
NOTICE OF CONFIDENTIALITY: A PORTION OF THIS DOCUMENT HAS BEEN
FILED UNDER SEAL.
DIRECT TESTIMONY AND EXHIBITS OF GREGORY L. FORD
• GLF-2: Overall Project Construction Costs—As of November, 2007 x 1000 (2007 $
with an escalation allowance to 2009)
GLF-3: Milestone Summary Schedule for Major Construction Activities.
•
•
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
Docket No.
IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF
COLORADO FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
TO CONSTRUCT TWO COMBUSTION TURBINES AT THE FORT ST. VRAIN
GENERATING STATION, FOR AN AMENDMENT TO ITS CONTINGENCY PLAN,
AND FOR EXPEDITED TREATMENT
• DIRECT TESTIMONY AND EXHIBITS OF GREGORY L. FORD
ON
BEHALF OF
PUBLIC SERVICE COMPANY OF COLORADO
November 2007
•
•
1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A. My name is Gregory L. Ford. My business address is 414 Nicollet Mall, MP7,
3 Minneapolis, Minnesota 55401.
4 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
5 A. I am employed by Xcel Energy Services Inc., the service company subsidiary
6 of Xcel Energy Inc., which is the public utility holding company parent of
7 Public Service Company of Colorado. My title is Director, Engineering and
8 Design Services.
9 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS DOCKET?
10 A. I am testifying on behalf of Public Service Company of Colorado ("Public
• 11 Service" or the "Company").
12 Q. HAVE YOU PREPARED A STATEMENT OF YOUR EXPERIENCE AND
13 QUALIFICATIONS?
14 A. Yes. That statement is included as Attachment A.
15 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
16 A. The purpose of my testimony is to support the Company's application for a
17 certificate of public convenience and necessity to construct a natural gas-fired
18 simple cycle electric generation addition at the Company's existing plant at
19 Fort St. Vrain. My testimony provides an overview of the need for this
20 generating facility, a description of the technology and major equipment
21 required for the plant, the operating characteristics of the plant, a discussion
22 of the facility costs and the basis of these costs, risk factors involved in
1
• 1 constructing the plant and Public Service's strategy for mitigating that risk,
2 and a discussion of fuel supply arrangements.
3 Q. WHAT IS THE FORT ST. VRAIN PROJECT?
4 A. The Fort St. Vrain project is a project to construct and install two (2) new
5 peak-load gas-fired simple cycle electric generating units located at the Fort
6 St. Vrain generating station ("Fort St. Vrain"). The units are "F" class
7 combustion turbines designed specifically for peaking service and will be
8 designated as Units 5 and 6 at Fort St. Vrain. Exhibit GLF-1 contains a
9 preliminary general arrangement drawing of the existing site with the addition
10 of the two (2) units. The estimated "all-in" construction cost of the project,
11 including external interconnection costs and other costs, is $201.2 million, as
• 12 of November 2007. The necessary transmission and distribution facility
13 upgrades and the natural gas infrastructure upgrades are accounted for
14 separately within Public Service Company and are estimated at $5.0 million
15 for the transmission connection and grid upgrades and $2.0 million for the gas
16 infrastructure. The transmission facility upgrades are discussed in the
17 prefiled testimony of Gerald Stellern. The natural gas infrastructure upgrades
18 are discussed later in this testimony.
19 Q. WHAT CIRCUMSTANCES HAVE CREATED A NEED FOR THIS
20 PROJECT?
21 A. The primary circumstance that created a need for this project is the
22 substantial uncertainty regarding the performance by Squirrel Creek Energy
23 LLC ("Squirrel Creek Energy") under its purchased power agreement with the
•
2
•
1 Company for the purchase of capacity and energy from a generation project
2 that Squirrel Creek Energy was planning to construct at Squirrel Creek. near
3 Fountain, Colorado. The circumstances relating to the need for the Fort St.
4 Vrain project are described in greater detail in the testimony of Karen Hyde.
5 However, the bottom line is that the Company must have 379 MW of
6 additional generating capacity in order to meet the summer 2009 peak, the
7 only viable way for the Company to obtain that capacity in such a constricted
8 time frame is to self-build the project, and the site that makes the most sense
9 is the Fort St. Vrain site.
10 Q. DID THE CONSTRICTED TIME FRAME AFFECT THE COMPANY'S
11 APPROACH TO THIS PROJECT?
• 12 A. Yes. Once the Company learned that there was substantial uncertainty
13 regarding Squirrel Creek Energy's ability to perform under the PPA, the
14 Company needed to evaluate alternative resource options. The only feasible
15 option was to purchase and add combustion turbines to our system. The
16 combustion turbine market has been very active over the last year and the
17 availability of combustion turbines is limited. Delivery of new combustion
18 turbines is now approaching twenty-four (24) months from date of order and
19 the availability of "grey-market" or resale equipment has nearly disappeared.
20 We initiated a quick request of the major combustion turbine suppliers by
21 telephone to determine if any of them had two (2) "F" class combustion
22 turbines available for mid-2008 delivery. The vendors contacted were
23 Siemens, General Electric, and Mitsubishi. Of these only Siemens had
•
3
• 1 equipment available and we immediately initiated negotiations to place a
2 reservation for these machines. At the same time, we initiated a search of the
3 "grey market" for "F" class machines that have been placed in storage and
4 are available for sale. We found three potential machines, but put the
5 investigation on hold pending outcome of the Siemens negotiations. Our
6 experience with purchasing from the "grey market" is that due diligence and
7 purchase agreements take several months to complete. An agreement was
8 reached with Siemens to reserve the two combustion turbines based on
9 payment of a reservation fee of $1,000,000 each. This payment held the
10 machines until a formal contract could be negotiated and signed. In the
11 meantime, negotiations were initiated with Invenergy to resolve the
• 12 uncertainty over Squirrel Creek Energy's ability to perform under the PPA.
13 Those negotiations resulted in what is a comprehensive resolution of the
14 issues between the parties. Public Service has agreed to acquire the Squirrel
15 Creek assets. As a result, the Company no longer needs the Siemens
16 combustion turbines it reserved, and released the reservation on those
17 turbines.
18 Q. THE COMPANY PAID A RESERVATION FEE FOR THE SIEMENS
19 TURBINES. WHAT HAS BECOME OF THAT RESERVATION FEE?
20 A. The reservation fee was a non-refundable deposit to Siemens to hold
21 equipment for purchase that was already in the manufacturing cycle. Without
22 the reservation fee, Siemens would have continued to market the equipment
23 on a first-come-first-serve basis. The Company believes the reservation fee
•
4
• 1 was a prudent expenditure, in essence an insurance policy that guaranteed
2 its ability to provide reliable service in 2009. If the negotiations with Invenergy
3 had not been successful, it is quite possible that the Company would not have
4 been able to find turbines in sufficient time to complete a reasonable
5 contingency plan.
6 Q. AT THE TIME THE COMPANY PAID SIEMENS THE RESERVATION FEE,
7 WAS IT ABSOLUTELY NECESSARY TO MAKE THAT PAYMENT?
8 A. Yes.
9 Q. WHY?
10 A. Other parties were actively evaluating purchase of the equipment we needed
11 in order to meet their own, similar, capacity needs and the Company had to
• 12 be sure that turbines were available to meet the capacity resource need in
13 2009. As a regulated public utility, we have an obligation to provide adequate
14 and reliable service. The reservation fee assured our ability to meet the 2009
15 summer peak.
16 Q. PLEASE PROVIDE A BRIEF OVERVIEW OF THE SPECIFIC
17 TECHNOLOGY THAT THE COMPANY WILL USE.
18 A. Public Service has purchased the three Squirrel Creek turbines and will be
19 utilizing the combustion turbines at its existing Fort St. Vrain facility. These
20 machines are General Electric F-class combustion turbines with a nominal
21 summer rating of 130 MW. They are nearly identical to the three GE units
22 already in service at Fort St. Vrain, but will not be installed with exhaust gas
23 heat recovery equipment, because they are intended only to meet short term
•
5
• 1 peak power requirements. Nor will they be attached to the existing steam
2 turbine currently in operation at the station since the capacity of the steam
3 turbine is already fully utilized.
4 Q. ARE THE TURBINES READY FOR COMMERCIAL USE?
5 A. No. The turbines are being purchased on an as-is basis, and will require
6 refurbishment before commercial operation at the Fort St. Vrain site. The
7 refurbishment work will be completed as part of the relocation and assembly
8 process and will include all updates (Technical Information Letters or TILs)
9 issued by General Electric since the equipment was manufactured.
10 Q. WHY DID PUBLIC SERVICE SELECT NATURAL GAS-FIRED SIMPLE
11 CYCLE TECHNOLOGY FOR THE PROJECT?
• 12 A. The selection of the natural gas-fired simple cycle combustion turbine
13 technology was based upon the Company's 2003 resource plan for meeting
14 the Company's generation capacity needs in the summer of 2009.
15 Q. WHEN IS THIS PLANT NEEDED?
16 A. Based on the current and projected capacity resource need of Public Service,
17 additional capacity is required in 2009 to meet system demand and reserve
18 requirements. It is crucial that this plant have a commercial in-service date of
19 June 2009 in order to meet the Company's summer peak load in 2009.
20 Q. IN ORDER TO MEET THAT IN-SERVICE DEADLINE, WHEN MUST
21 CONSTRUCTION BEGIN?
22 A. The latest date that construction may begin and still meet the June 2009 in-
23 service date is April 2008.
•
6
•
1 Q. WHAT STEPS HAS THE COMPANY TAKEN TO ACQUIRE MAJOR
2 FACILITIES AND EQUIPMENT TO CONSTRUCT THE PLANT?
3 A. The need to proceed with this project as a Public Service self-build project
4 was identified in late August 2007. Preliminary work had been completed
5 earlier this year to review several existing sites for potential additional
6 generation or repowering opportunities. Fort St. Vrain was considered the
7 best site for addition of new combustion turbines due to the large site and flat
8 terrain. The combustion turbine equipment that Public Service has obtained
9 from Invenergy Thermal LLC is required to meet the commercial operation
10 requirement for the summer of 2009.
11 Q. IN YOUR JUDGMENT MR. FORD, WILL PUBLIC SERVICE BE ABLE TO
. 12 ACQUIRE NECESSARY TURBINES IN TIME TO MEET THE JUNE 2009
13 IN-SERVICE DATE?
14 A. Yes.
15 Q. WHAT IS THE ESTIMATED TOTAL INSTALLED COST OF THE
16 PROJECT?
17 A. The costs are $192.1 million for the project. A detailed breakdown of the
18 project cost is provided in confidential exhibit GLF-2.
19 Q. CAN YOU EXPLAIN IN GREATER DETAIL WHAT THAT TOTAL
20 INCLUDES?
21 A. Yes. However, I should caution that, at this stage of the project, these are
22 preliminary estimates. In Public Service's experience, the final project costs,
23 when completed and in-service, should be within a range of +1- 20% of this
•
7
•
1 preliminary cost estimate. In general, the project cost estimate includes
2 materials, labor, escalation, indirect costs, interconnection costs and a project
3 contingency.
4 Q. WHAT WAS THE METHOD THE COMPANY USED TO ESTIMATE
5 PROJECT COSTS?
6 A. Major equipment items and their costs have been identified through direct
7 negotiations with the suppliers and are budgetary until final contracts are
8 signed. The installation hours and costs for the major equipment are based
9 on information from previous projects and knowledge of the current Colorado
10 labor market. Numerous line items have been identified for each of the major
11 categories listed above with material and labor hours estimated for each.
. 12 Engineering costs and contractor overheads are based on previous
13 experience of Company staff on similar projects.
14 Q. DOES THE TOTAL PROJECT COST INCLUDE THE COST OF THE
15 RESERVATION FEE PAID TO SIEMENS FOR TURBINES THAT WILL NOT
16 BE USED IN THE PROJECT?
17 A. It does.
18 a WHY ARE YOU INCLUDING THAT COST?
19 A. Until the negotiations with Invenergy to terminate the Squirrel Creek Energy
20 PPA were completed, Public Service had to proceed with development of the
21 option to buy combustion turbines on the open market and develop the
22 project at Fort St. Vrain to cover the capacity resource need for 2009. We are
23 continuing to work with Siemens to apply a portion, or all, of the reservation
•
8
• 1 fee to future purchases of new major equipment. If our negotiations with
2 Siemens are successful, this will reduce the Fort St. Vrain project costs.
3 Q. DOES THE PROJECT ESTIMATE INCLUDE THE PURCHASE PRICE FOR
4 THE SQUIRREL CREEK STEAM TURBINE?
5 A. No. Our intent is to sell the steam turbine, or apply the turbine to a project
6 such as the proposed Arapahoe repowering project. A conservative estimate
7 of a resale price for this turbine was excluded from the project cost estimate.
8 If we can sell the turbine for a net higher price, we will decrease the FSV
9 project cost by the amount we receive in the market. If we were to apply the
10 turbine to the proposed Arapahoe repowering project the assigned turbine
11 price will be allocated to that project.
• 12 Q. HAS THE COMPANY IDENTIFIED FACTORS THAT COULD HAVE A
13 SIGNIFICANT IMPACT ON THE PROJECT COSTS?
14 A. Yes. There are always risks associated with the development of any new
15 power plant. The shorter the project duration, the easier it is to quantify and
16 control these risks. For natural gas generation, such as simple cycle facilities,
17 the project duration is typically two to three years. On such projects,
18 component and construction contracts can be awarded within a year of
19 project start. As a result a large portion of the total project cost (nearly 50%)
20 can be fixed as the project is initiated. The largest risk at this point will be the
21 cost of construction labor. Experienced labor is in short supply due to the
22 large number of projects in progress in the United States.
•
9
• 1 Q. DOES PUBLIC SERVICE HAVE SYSTEMS AND PROJECT PROCEDURES
2 AVAILABLE TO ALLOW IT TO MANAGE THE CONSTRUCTION RISK
3 FACTORS FOR THE NEW PROJECT?
4 A. Yes. Various contracting strategies can help hedge against much of the
5 routine construction risks for this type of project. Some of these contracting
6 strategies include: 1) enter a full lump-sum engineering, procurement, and
7 construction contract (sometime referred to as "Turnkey"), where the
8 Company hires one firm or group to manage the entire project under a fixed
9 price for a fixed scope and schedule similar to the Highbridge Repowering
10 Project nearing completion in Minnesota; 2) hire an engineering/design firm to
11 work with the Company and divide the project up into various equipment
• 12 purchases and construction contracts such as is being done at the Riverside
13 Repowering project in Minnesota; 3) utilize the internal resources of Xcel
14 Energy to manage the project by dividing the project into various equipment
15 purchases and construction contracts, similar to the way in which Xcel Energy
16 built coal plants in its Texas region (which are among the lowest cost plants in
17 the country) and which is the way Public Service is constructing its new plant
18 at Comanche; and/or 4) variations of the preceding approaches. Each of
19 these approaches has its costs, risks, and benefits. Other utilities are using
20 one or more of these approaches - with no clearly preferred approach. The
21 Company is still evaluating these strategies and is keeping most options
22 open. The cost estimates that I have provided assume a mixture of the
23 second and third approaches due to the time constraints on the project.
•
10
• 1 Q. HAS PUBLIC SERVICE SELECTED ANY CONTRACTORS TO DESIGN
2 AND BUILD THE PLANT?
3 A. We have completed a formal Request For Proposal (RFP) process for
4 selecting an engineering firm to work with our staff to develop the detail
5 design for the project. Formal proposals were submitted November 2, 2007.
6 Award of the engineering and detailed design contract was completed on
7 November 21, 2007. Utility Engineering will be providing the design support
8 for the project. A single contract for construction is anticipated and will be
9 awarded in the next few months. We are currently anticipating the start of
10 construction to be April 2008.
11 Q. WHAT IS THE STATUS OF THE PROJECT?
• 12 A. The agreement for transfer of the combustion turbines has been negotiated
13 with Invenergy Thermal LLC and is executed. The contract for main step-up
14 transformers is in negotiation. The air permit application was filed on
15 November 7, 2008. Detailed information for the Land Use Permit is being
16 developed with submittal in November 2007.
17 Q. CAN THE EXISTING FORT ST. VRAIN SITE ACCOMMODATE THE NEW
18 GENERATING FACILITY?
19 A. Yes. The existing site can easily accommodate the addition of two
20 combustion turbines due to the large amount of land that is part of the facility.
21 See Exhibit GLF-1.
22 Q. WILL THE PROJECT USE ANY EXISTING FACILITIES?
•
11
• 1 A. Yes. The new units will utilize the existing water system for small amounts of
2 cooling and for the inlet evaporative coolers. The existing bridge crane is
3 anticipated to be extended to provide heavy lift capabilities for maintenance.
4 The existing substation will be expanded to provide the additional bays
5 required for interconnection. The existing natural gas metering station will be
6 expanded to provide the fuel for the new units. The existing control room and
7 operations and maintenance staff will be utilized to operate and maintain the
8 new units. The existing railroad spur will be used to bring in the new
9 equipment. The plant electrical system will be interconnected to allow station
10 service to be shared.
11 Q. ARE THERE ANY ISSUES WITH THE SITE DUE TO THE INDEPENDENT
• 12 SPENT NUCLEAR FUEL STORAGE INSTALLATION ("ISFSI") LOCATED
13 AT THE SITE?
14 A. Yes, but Public Service will be able to meet U.S. Department of Energy
15 requirements for the site. The Company's consultant on this issue, CH2M-
16 WG Idaho, LLC, has determined that no formal regulatory approval is
17 required to construct the generation additions at Fort St. Vrain Station, except
18 for Public Utilities Commission approval. The Fort St. Vrain ISFSI Materials
19 License SNM-2504 no longer requires Nuclear Regulatory Commission
20 ("NRC") approval prior to any new gas pipeline installation within one-half mile
21 of the storage facility. Public Service need only analyze and report any
22 planned new infrastructure within one half-mile of the storage facility, which it
23 will do. Public Service will follow its consultant's recommendation that the
•
12
• 1 gas line installation address the same directed jet release concern raised by
2 the NRC in 1995, by installing a low pressure automatic isolation valve. This
• 3 would mean that two independent failures would be required before a threat
4 to the ISFSI could develop.
5 Q. HAS THE COMPANY STUDIED THE WATER REQUIREMENTS AND FUEL
6 RESOURCES FOR THE FACILITY?
7 A. It has. The water requirement for simple cycle combustion turbines is very
8 small. Modifications to the existing water system are anticipated to allow the
9 addition of the two units. The natural gas supply to the site has been
10 evaluated. Supply pressure and flow to the existing metering station has
11 been deemed adequate to add the two units. A new gas line from the
• 12 metering station to the new units will be required as well as changes in the
13 connection of the metering station to the interstate gas pipelines.
14 Q. WHAT IS THE EXPECTED PLANT EFFICIENCY/PLANT HEAT RATE?
15 A. Each unit is anticipated to have a full load capacity of approximately 141 MW
16 based on average annual ambient conditions and a heat rate of
17 approximately 10,482 BTU/kW-hr. The nominal full load winter rating is 155
18 MW. The nominal full load summer rating is 130 MW. These values are
19 based on the performance information available from the Invenergy due
20 diligence and internal evaluation.
•
13
• 1 Q. HOW WILL THE EFFICIENCY OF THIS PLANT COMPARE TO THE
2 EFFICIENCY OF THE COMPANY'S OTHER SIMPLE CYCLE POWER
3 PLANTS?
4 A. The efficiency of these units is better than any of the existing simple cycle
5 units owned by the company. This is due to the new equipment being larger
6 and incorporating state-of-the-art design. Older units are smaller and have
7 somewhat higher heat rates (lower efficiency).
8 Q. WILL CUSTOMERS BENEFIT FROM THE PLANT EFFICIENCY?
9 A. Yes.
10 Q. HOW WILL THEY BENEFIT?
11 A. By having large units available to handle peak system needs and to provide
• 12 backup to the wind generation being added to the system.
13 Q. WHAT IS THE PLANT'S AVAILABILITY FACTOR AND HOW DOES THAT
14 COMPARE WITH THE AVAILABILITY OF THE COMPANY'S OTHER
15 UNITS?
16 A. The availability of these units is anticipated to be equivalent to the three
17 "frame 7" combustion turbines currently at the FSV site. The General Electric
18 7FA Combustion Turbines have proven to be a very reliable machine. We
19 would expect to see availabilities in the range of 90% to 95% for this
20 equipment.
21 Q. HOW DID PUBLIC SERVICE SELECT THIS SITE FOR THE NEW PLANT?
22 A. In order to accommodate the fast response required, addition to an existing
23 site was the only feasible option that was available to the Company.
•
14
• Q. WHY IS THE INSTALLATION OF THE TWO TURBINES OCCURRING AT
2 THE FORT ST. VRAIN STATION INSTEAD OF THE SQUIRREL CREEK
3 SITE?
4 A. This "brownfield" site offers the advantage of existing land with natural gas,
5 water, transmission, and operations and maintenance personnel. All of these
6 existing resources provide an opportunity to save on costs that would be
7 incurred with a new site. We have looked at Invenergy's planned Squirrel
8 Creek site as a direct comparison and feel that installation of the simple cycle
9 portion of the project at that site would cost more than our estimated cost for
10 Fort St. Vrain Units 5 and 6, as explained in Karen Hyde's testimony. Public
11 Service has adequate water at the Fort St. Vrain site, and believes that
• 12 permitting will be a simpler task given that the Fort St. Vrain station is already
13 zoned for industrial use, as explained in the testimony of John Lupo.
14 Q. WHY IS THERE SUCH A COST DIFFERENTIAL?
15 A. No land cost, an existing rail spur and road access to the site, existing
16 operations and maintenance personnel and facilities, natural gas available at
17 the site boundary, and transmission access on-site are all contributing factors.
18 Q. WHAT WERE THE FACTORS THAT FAVORED LOCATING THE NEW
19 UNIT AT FORT ST. VRAIN SITE?
20 A. All of the items identified above contribute favorably to adding new units at
21 this site.
•
15
• 1 Q. HAS THE COMPANY MADE ARRANGEMENTS FOR FUEL SUPPLY FOR
2 THE PLANT?
3 A. Yes. The Fort St. Vrain facility has access to two gas transmission pipelines.
4 Public Service has a 24-inch line adjacent to the site that currently supplies
5 the facility and has available capacity. Colorado Interstate Gas Company
6 ("CIG") has a 12-inch line also adjacent to the site that operates at a slightly
7 higher pressure and has capacity available. Public Service plans to connect
8 the CIG line into the Fort St. Vrain metering station and expand the metering
9 station with a parallel installation to serve the new units. Between the two
10 lines, the available capacity is sufficient to serve all of the plant demands and
11 retain sufficient supply pressure. Negotiations are proceeding with CIG to
4. 12 complete the necessary interconnection agreement. A new line from the
13 metering stations to the units is required and included in the estimated project
14 scope and cost.
15 Q. DOES PUBLIC SERVICE ANTICIPATE ANY PROBLEMS IN OBTAINING
16 FUEL FOR THE NEW PLANT?
17 A. No.
18 Q. DOES THE COMPANY HAVE A SCHEDULE FOR MAJOR
19 CONSTRUCTION ACTIVITIES ON THE PROJECT?
20 A. Yes. Confidential Exhibit GLF-3 is a milestone summary schedule for major
21 construction activities.
•
16
• 1 Q. HAS THE COMPANY STUDIED POTENTIAL ENVIRONMENTAL IMPACTS
2 FROM THE CONSTRUCTION AND OPERATION OF THE PROJECT
3 PLANT?
4 A. Yes. The testimony of Company witness Gary Magno addresses this issue.
5 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
6 A. Yes.
•
•
17
• Attachment A
Statement of Qualifications
Gregory L. Ford
Mr. Ford is the Director of Engineering & Design Services in the Engineering &
Construction Department. He has worked in the consulting and owners engineering
management role within the electric power industry for 34 years. The experience has
been with Gilbert/Commonwealth Engineering, Inc. in Jackson, MI for 11 years; HDR
Engineering, Inc. in Minneapolis, MN for 13 years; and NRG Energy, Inc. in
Minneapolis, MN for 7 years prior to joining Xcel Energy, Inc. ("Xcel Energy") in 2004.
Project experience has ranged from initial development through acceptance testing on
both new and retrofit projects and has included significant involvement in permitting
activities. Technologies have included boilers (stoker, fluid bed, gas, oil, municipal solid
waste, and pulverized coal); steam turbines (10 to 1200 MW); combustion turbines (4 to
240 MW) in both simple and combined cycle configurations; low and high head hydro;
district heating & cooling; control systems; ash handling & disposal; coal handling;
cooling water systems; environmental retrofits including fabric filters, precipitators,
SCRs, low NOx burners, and fuel switching to PRB; and overall Balance of Plant
systems and equipment.
• Greg was the Power and Energy as well as Environmental section manager for the
Minneapoils office while at HDR Engineering and was the Executive Director of
Engineering while at NRG Energy. NRG management responsibilities included bidding
and negotiating major contracts for new and retrofit projects domestically and
internationally with construction budgets up to $1.0 billion.
While at Xcel Energy, Greg has been responsible for managing the bidding and
negotiation of the major equipment supply and furnish and installation contracts for the
Comanche 3 project near Pueblo, Colorado. He has also been responsible for the
management and administration of the Engineering and Design Departments within
Engineering & Construction for all jurisdictions of Xcel.
Greg is a registered Professional Engineer in Michigan and Minnesota. Greg is also a
member of ASME. Greg has a BSME degree from Colorado State University. Greg
currently is a member of the Coal Utilization Research Council (CURC) and the EPRI
P66 Advanced Coal-IGCC Program.
•
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• CONFIDENTIAL EXHIBIT GLF-2
THIS HAS BEEN FILED UNDER CONFIDENTIAL SEAL
I
CONFIDENTIAL EXHIBIT GLF-3
•
THIS HAS BEEN FILED UNDER CONFIDENTIAL SEAL
•
•
OF COL
� U111_ItIEi.
XceI EnergysM 2007 NOV 27 PM 4: 34
PUBLIC SERVICE COMPANY
IN THE MATTER OF THE APPLICATION OF
PUBLIC SERVICE COMPANY OF COLORADO FOR
A CERTIFICATE OF PUBLIC CONVENIENCE AND
NECESSITY TO CONSTRUCT TWO COMBUSTION
TURBINES AT THE FORT ST. VRAIN GENERATING
STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED
TREATMENT
DOCKET NO. 07A- 94q E
DIRECT TESTIMONY
AND EXHIBITS
November 2007
• BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
Docket No.
IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF
COLORADO FOR APPROVAL OF A CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY TO CONSTRUCT TWO COMBUSTION TURBINES AT THE
FORT ST. VRAIN GENERATING STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED TREATMENT
DIRECT TESTIMONY OF JOHN LUPO
ON
• BEHALF OF
PUBLIC SERVICE COMPANY OF COLORADO
November 2007
•
1 Q. WHAT IS YOUR NAME AND BUSINESS ADDRESS?
2 A. My name is John Lupo. My business address is 550 15th Street, Suite 700,
3 Denver, Colorado 80202.
4 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
5 A. I am employed by Xcel Energy Services Inc., the service company subsidiary
6 of Xcel Energy, Inc., the public utility holding company parent of Public
7 Service Company of Colorado ("Public Service" or the "Company"). My title is
8 Manager, Siting and Land Rights. My primary responsibility is to manage and
9 supervise the siting, permitting, and land rights acquisition for new facilities of
10 Xcel Energy subsidiaries in Colorado, Texas, and New Mexico.
11 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS DOCKET?
12 A. I am testifying on behalf of Public Service.
13 Q. HAVE YOU PREPARED A STATEMENT OF YOUR EXPERIENCE AND
14 QUALIFICATIONS?
15 A. Yes. The statement is included with my testimony as Attachment A.
16 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
17 A. My testimony supports the Company's application for a certificate of public
18 convenience and necessity to construct a 260 megawatt ("MW")(nominal
19 summer rating) natural gas-fired simple cycle electric generation addition at
20 the Company's existing plant at the Fort St. Vrain generating station. In
21 particular, my testimony discusses land use permitting requirements for the
22 proposed plant.
23 Q. WHAT IS THE PREFERRED PROJECT SITE?
•
1
• 1 A. Our existing generating facility at Fort St. Vrain is the preferred site because
2 key infrastructure is already in place and Public Service owns sufficient real
3 estate to accommodate the proposed addition. With respect to infrastructure,
4 the site offers ready access to adequate supplies of natural gas, as well as
5 adequate injection capacity on the electric transmission system. The site's
6 existing electrical and mechanical systems, and its water and wastewater
7 systems can be readily adapted to add the proposed plant. Moreover, the
8 site has good regional highway and rail access, and well-developed roads
9 and parking on site. Another advantage of the site is that it is already zoned
10 for industrial use.
11 Q. IS THERE A SITE PLAN?
12 A. Yes, Public Service witness Gregory Ford's testimony includes an exhibit
•
13 showing the existing plant and a preliminary site plan.
14 Q. WHERE WILL THE NEW PLANT BE LOCATED AT THE EXISTING SITE?
15 A. The new facility, which consists of two gas-fired combustion turbines (CTs),
16 will be located adjacent to the existing Fort St. Vrain generating plant.
17 Specifically, it will be due east and directly in line with the three existing CTs
18 on an east-west axis.
19 Q. WHY HAS THE COMPANY CHOSEN THIS CONFIGURATION?
20 A. This configuration provides efficient integration with existing electrical and
21 mechanical systems at the plant. The configuration is possible because the
22 topography of the site is flat and Public Service owns more than adequate
23 property to accommodate this design. From a civil engineering perspective,
•
2
• 1 this site is attractive because it will require only minimal grading to prepare
2 the site for construction.
3 The location of the new turbines in relationship to the existing plant
4 helps to minimize community impacts, such as visual quality and noise.
5 These impacts are mitigated by the plant's location in the geographic center
6 of the property, which affords a buffer zone of more than 2,800 acres around
7 the plant.
8 Q. WHAT LOCAL LAND USE PERMITS WILL THE COMPANY BE REQUIRED
9 TO OBTAIN?
10 A. The existing Fort St. Vrain plant operates under a Use by Special Review
11 ("USR") permit issued by Weld County. Since the County issued the original
• 12 USR permit in 1994, it adopted "1041 Land Use Regulations." These rules
13 govern the development of "Areas and Activities of State Interest," including
14 major facilities of a public utility. For this project, Weld County will require
15 Public Service to amend its existing USR permit. The permit application will
16 be processed through the County's 1041 review procedures.
17 Q. PLEASE DESCRIBE THE PERMITTING PROCESS.
18 A. Certainly. After Public Service submits its application, Weld County will
19 review the application for compliance with the 1041 submittal requirements.
20 Once the County deems the application complete, it will refer the application
21 to several local, county, and state "referral" agencies for review and comment.
22 All referral agency comments will be forwarded to Public Service, which will in
23 turn provide responses to the County. The County will then schedule a public
•
3
• 1 hearing before the Weld County Planning Commission. Property owners
2 within 1,320 feet of the plant's property boundary will be notified of this
3 hearing. The Planning Commission will make a recommendation to the
4 Board of County Commissioners to either approve or deny the application, or
5 approve it with conditions. The application will then be scheduled for a public
6 hearing before the Board of County Commissioners, which will make a final
7 decision on the application.
8 Before the two public hearings, the Company will host at least one
9 community meeting to describe the project and answer any questions. While
10 such informational meetings are not a formal requirement of the permitting
11 process, the County encourages them, and Public Service typically holds
• 12 such meetings as part of its normal planning and development activities.
13 Q ARE ANY LAND USE APPROVALS REQUIRED OTHER THAN THE WELD
14 COUNTY PERMITS DESCRIBED?
15 A. No. While "greenfield" power plant development typically requires local
16 zoning approvals, this project will not require local zoning approvals because
17 the site is already zoned for industrial land uses.
18 Q. PLEASE EXPLAIN THE TIME FRAME IN WHICH THE COMPANY WILL
19 OBTAIN THE PERMITS.
20 A. Public Service is currently assembling the application package which it plans
21 to submit to Weld County in November of 2007. Once the County deems the
22 application complete, it will send the application to referral agencies, which
23 will review the application in December and January of 2008. The Planning
•
4
• 1 Commission will hear the application in February 2008. In March of 2008, the
2 Board of County Commissioners will hear the application and hopefully render
3 a final decision. This approval schedule would allow plant construction to
4 begin in April 2008.
5 Q. DOES PUBLIC SERVICE ANTICIPATE ANY TIMING PROBLEMS IN
6 OBTAINING THE PERMIT?
7 A. No. Although the Thanksgiving, Christmas, and New Year holidays may
8 slightly impact the overall permit schedule, the Company believes it will be
9 successful in obtaining the required permits in time to begin construction in
10 April 2008 for a June 2009 in-service date. My staff and I have discussed the
11 project and schedule with officials at the Weld County Planning Department,
12 and they indicated it is possible to secure a land use permit by the end of
•
13 March 2008, assuming we submit a complete application package and
14 provide timely responses to any concerns that may arise during the process.
15 Q. DOES PUBLIC SERVICE ANTICIPATE ANY SUBSTANTIVE PROBLEMS
16 IN OBTAINING THE PERMIT?
17 A. No. Given that the site is already permitted for industrial use, and given that
18 the facility will be located in the middle of a 2800 acre tract, the Company
19 expects little opposition. Noise, dust, and other emissions, will be minimal.
20 Q. ARE ANY LAND USE PERMITS REQUIRED FOR THE TRANSMISSION
21 UPGRADES DISCUSSED BY PUBLIC SERVICE WITNESS GERALD
22 STELLERN?
•
5
• 1 A. No. The Company already owns the easements and property necessary for
2 these upgrades, and there will be no changes in the use of those properties.
3 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
4 A. Yes.
•
6
• Attachment A
Statement of Qualifications
John Lupo
John manages Xcel Energy Service Inc.'s Siting & Land Rights (S&LR) group in
Denver, overseeing land planning and acquisition efforts for utility developments in
Colorado, Texas, and New Mexico. He has over 10 years of experience in
managing complex and often-controversial facility siting and environmental planning
projects for electric transmission lines, high-pressure gas lines, and power plants.
For seven years prior to becoming manager of the S&LR group, John was an
analyst with Xcel Energy's Resource Planning & Acquisition department, where he
contributed to the development of Resource Plans for Public Service Company of
• Colorado and Northern States Power ("NSF"). In this role he acted as project
manager for several competitive resource solicitations and evaluations. He also
managed Xcel Energy's Renewable Development Fund, an NSP program. Prior to
joining Public Service, John was a senior associate with Hammer, Siler, George
Associates, a national economic land development consultancy, for four years. John
also practiced landscape architecture and land planning for four years with the
Winter Park ski area and Gage Davis Associates.
John holds a Bachelors of Science in Landscape Architecture from Penn State and a
Masters of Urban & Regional Planning from the University of Colorado. He has
sponsored written and oral testimony before Colorado and Minnesota regulatory
agencies, as well as the Federal Energy Regulatory Commission.
•
ipcttx}
OF COL
uil!_ITIL5
Xcel EnergysM 2001N0'd 27 PM 4: 34
PUBLIC SERVICE COMPANY
IN THE MATTER OF THE APPLICATION OF
PUBLIC SERVICE COMPANY OF COLORADO FOR
A CERTIFICATE OF PUBLIC CONVENIENCE AND
NECESSITY TO CONSTRUCT TWO COMBUSTION
TURBINES AT THE FORT ST. VRAIN GENERATING
STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED
TREATMENT
DOCKET NO. 07A--y/Qq E
DIRECT TESTIMONY
AND EXHIBITS
November 2007
•
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
Docket No.
IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF
COLORADO FOR APPROVAL OF A CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY TO CONSTRUCT TWO COMBUSTION TURBINES AT THE
FORT ST. VRAIN GENERATING STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED TREATMENT
• DIRECT TESTIMONY OF GARY MAGNO
ON
BEHALF OF
PUBLIC SERVICE COMPANY OF COLORADO
November 2007
•
• 1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A. My name is Gary Magno. My business address is 4653 Table Mountain
3 Drive, Golden, Colorado, 80403.
4 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
5 A. I am employed by Xcel Energy Services Inc., the service company
6 subsidiary of Xcel Energy Inc., the public utility holding company parent of
7 Public Service Company of Colorado ("Public Service" or the "Company").
8 My title is Principal Environmental Analyst.
9 Q. ON WHOSE BEHALF ARE YOU TESTIFYING?
10 A. I am testifying on behalf of Public Service Company of Colorado ("Public
11 Service" or"Company").
12 Q. HAVE YOU PREPARED A STATEMENT OF YOUR EXPERIENCE AND
13 QUALIFICATIONS?
14 A. Yes. That statement is included as Attachment A.
15 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
16 A. The purpose of my testimony is to support the Company's application for a
17 certificate of public convenience and necessity to construct a 260
18 megawatt ("MW") natural gas-fired simple cycle electric generation
19 addition at the Company's existing plant at Fort St. Vrain. The General
20 Electric turbines to be used are more thoroughly described in the
21 testimony of Public Service witness Gregory Ford. In particular, my
22 testimony discusses the air quality permitting requirements applicable to
23 the plant, emission limits, and the timeline the Company will use to obtain
•
1
• 1 the necessary environmental approvals to construct the new plant. I also
2 discuss water and wastewater issues, and solid waste and other
3 environmental permitting requirements associated with the construction
4 and operation of the proposed new units.
5 Q. WHAT AGENCIES HAVE REGULATORY OVERSIGHT FOR
6 ENVIRONMENTAL PERMITTING REQUIREMENTS THAT APPLY TO
7 THESE UNITS?
8 A. The new units will be subject to extensive permitting and regulatory
9 oversight by the Colorado Department of Public Health and Environment
10 ("CDPHE"). CDPHE is primarily responsible for implementing various
11 federal and state laws applicable to the facility, such as the Clean Air Act,
• 12 the Clean Water Act, the Solid Waste Disposal Act, and their state
13 counterparts. The U.S. Environmental Protection Agency ("EPA") is
14 responsible for helping to ensure that CDPHE properly implements federal
15 law through federally enforceable state implementation plans. All of the
16 environmental issues associated with the construction and operation of
17 the new units will be subject to regulatory requirements imposed by
18 CDPHE.
19 Q. WHAT ARE THE PERMITTING REQUIREMENTS ASSOCIATED WITH
20 AIR EMISSIONS FROM THESE NEW UNITS?
21 A. The two new units will be permitted as a minor modification to an existing
22 major source, per the general permitting requirements of Colorado Air
23 Quality Control Commission, Regulation No. 3. In particular, the new units
2
• 1 will (1) be subject to the federal New Source Performance Standards
2 ("NSPS") associated with Stationary Combustion Turbines; (2) be required
3 to obtain construction and operating permits under federal and state
4 programs; and, (3) meet other regulatory requirements associated with
5 their emissions, including continuous monitoring and Clean Air Act Title IV
6 allowance obligations.
7 Q. WILL PERMITTING AS A MINOR MODIFICATION PLACE
8 OPERATIONAL LIMITS ON THESE NEW UNITS?
9 A. Yes. To be classified as a "minor modification," the project must not result
10 in an increase in emissions greater than certain thresholds for various
11 pollutants regulated under the Clean Air Act. In this case, oxides of
• 12 nitrogen, or NOx, is the limiting pollutant. The minor modification threshold
13 for NOx is 40 tons per year. NOx emissions from the two new units will be
14 limited to less than 40 tons per year by restricting the capacity factor of the
15 units to approximately 8.4 percent of the hours in the year, or
16 approximately 735 hours per year at full load. This limited operation is
17 sufficient for Public Service's needs under its 2003 Least Cost Plan
18 because the plant will only be used to meet peak demand requirements
19 and to provide backup to wind generation that is being added to the Public
20 Service system.
21 Q. WHAT IS THE NSPS REGULATION?
22 A. NSPS is a requirement under the federal Clean Air Act that has been
23 incorporated into state law. NSPS requires that all new major sources in a
•
3
• 1 specific source category must meet emission control limits. For stationary
2 Combustion Turbines, the limits applicable to the new units are found in
3 federal regulations at 40 C.F.R. Part 60, Subpart KKKK. Generally,
4 Subpart KKKK requires that new units control NO, emissions.
5 Q. HOW WILL THESE UNITS BE DESIGNED TO MEET THE
6 REQUIREMENTS OF SUBPART KKKK OF THE NSPS?
7 A. The new units will be equipped with dry low-NO, combustors designed to
8 meet the NSPS NO, emission rate limit of 15 parts per million. The
9 projected NO, emission rate for new combustion turbines is in the range of
10 9 ppm.
11 Q. WILL THE NEW UNITS BE SUBJECT TO THE MAJOR SOURCE
• 12 PREVENTION OF SIGNIFICANT DETERIORATION ("PSD")
13 PERMITTING PROGRAM?
14 A. No. Permitting these new units as a minor modification to an existing
15 major source means the project is not subject to the PSD permitting
16 requirements.
17 Q. WHAT PRE-APPLICATION MONITORING INFORMATION IS
18 REQUIRED FOR A MINOR MODIFICATION PERMIT?
19 A. There is no meteorological or ambient monitoring data required as part of
20 a minor modification permit application.
21 Q. WILL THE ADDITION OF THESE UNITS HAVE AN ADVERSE IMPACT
22 ON AIR QUALITY?
•
4
• 1 A. No. Under the minor source permitting requirements, Public Service is
2 required to use calculated emissions from the plant in an approved
3 computer dispersion model to predict the air quality impacts of the
4 Company's proposed operations. Public Service has completed
5 dispersion modeling for the project that shows the new combustion
6 turbines will not cause or contribute to violations of the National Ambient
7 Air Quality Standards, the air standards set by EPA to protect human
8 health and the environment.
9 Q. WHAT OTHER AIR QUALITY REQUIREMENTS APPLY TO THE
10 PROJECT?
11 A. The new plant will also be required to comply with the requirements of the
• 12 SO2 emissions trading program found in Title IV of the Clean Air Act.
13 When Congress added the program to the Act, it set a national cap on
14 emissions of SO2 and required EPA to allocate tradable rights to emit SO2
15 (known as allowances) to each of the nation's power plants. Each power
16 plant owner can use its allowances to emit SO2 from its own plant or sell
17 some of the allowances to another plant owner to cover its emissions.
18 These new units will not receive any SO2 allocations from EPA. Public
19 Service will be required to purchase SO2 allowances for the plant on the
20 national allowance market or use surplus allowances generated by other
21 controlled units in the Xcel Energy system — that is Public Service and its
22 sister utility operating companies, Northern States Power Company, a
•
• 1 Minnesota corporation, Northern States Power Company, a Wisconsin
2 corporation, and Southwestern Public Service Company.
3 Q. WHAT OTHER KINDS OF ADDITIONAL AIR PERMITS ARE REQUIRED
4 FOR THESE NEW UNITS?
5 A. In addition to the minor modification air emission permit for the two
6 combustion turbines, Public Service will be required to incorporate these
7 units into the existing Clean Air Act Title V operating permit for the site
8 within 12 months of commencing operations of these new units.
9 Q. WHAT DOES THIS INVOLVE?
10 A. A Title V permit modification must be submitted to the Air Pollution
11 Control Division within 12-months from the time the new combustion
• 12 turbines go on-line. The permit modification incorporates all the specific
13 permit conditions contained in the air emission construction permit into the
14 Title V permit for the Fort St. Vrain station. The permit modification also
15 outlines the recordkeeping and reporting requirements necessary to show
16 compliance with all permit limits for the new turbines.
17 Q. WHAT ARE THE PROJECTED EMISSIONS FOR THIS FACILITY?
18 A. The projected emissions are as follows in Ibs/MMBtu and tons/year:
19 Lbs / MMBtu Tons/Year
20 NO, 0.037 39.9
21 CO 0.018 19.9
22 PM 0.012 13.3
23 SO2 0.003 3.7
24 CO2 119 128.9
•
• 1 Q. WHAT KINDS OF MONITORING, REPORTING, AND RECORD
2 KEEPING REQUIREMENTS WILL BE IMPOSED ON THESE NEW
3 UNITS?
4 A. Under the Clean Air Act Title IV program, Continuous Emission Monitors
5 will be installed on the combustion turbine stacks to monitor SO2, NOx,
6 CO2, and fuel flow rate. Data from these monitors are stored on a
7 common computer system and reported to EPA and CDPHE on a
8 quarterly basis. These emission monitoring systems must also meet very
9 stringent quality assurance requirements that include daily calibrations,
10 periodic calibration gas audits, and annual relative accuracy tests. Once
11 the new units go into operation, the requirements of the minor modification
• 12 permit will be incorporated into the site Title V permit, which requires
13 significant record keeping, semi-annual deviation reporting, and annual
14 compliance certifications.
15 Q. HOW LONG WILL IT TAKE TO OBTAIN THE NECESSARY AIR
16 EMISSION PERMIT FOR THIS PROJECT?
17 A. The Company has a plan in place to obtain the necessary minor
18 modification air emission construction permit for this project in April 2008.
19 Public Service has met with the Colorado Air Pollution Control Division
20 ("APCD") staff to discuss the details of the project and the specific
21 requirements for the permit application. The Company submitted the air
22 permit application for the two new combustion turbines on November 7,
23 2007. Based on our discussions with the APCD staff at the preapplication
•
7
• 1 meeting, we believe that the necessary air emission construction permit
2 for the project will be issued in April 2008.
3 Q. WILL EMISSIONS FROM THE NEW UNITS POSE ANY HAZARD TO
4 PUBLIC HEALTH AND SAFETY?
5 A. No. The permitting requirements discussed above are designed to protect
6 the public health, safety, and well being. Based on the ambient air quality
7 standards that are established to protect human health and the
8 environment, and the dispersion modeling analysis referenced above, the
9 emissions from these new units will have no impact on public health and
10 safety.
11 Q. WHAT KIND OF WATER QUALITY REGULATION WILL APPLY TO
. 12 THE PROJECT?
13 A. Like the Clean Air Act, the Clean Water Act is administered by CDPHE.
14 Water discharged from an industrial operation into waters of the state of
15 Colorado must obtain a discharge permit under the Colorado Discharge
16 Permit System ("CDPS"). The CDPS permit is the state counterpart to the
17 Clean Water Act's National Pollutant Discharge Elimination Permit. These
18 permits require treatment of water to specific water quality levels prior to
19 discharge into a stream or waterway.
20 There will be no wastewater discharges from the new combustion
21 turbines other than storm water runoff from the area around the turbines.
22 This storm water will be collected in a new storm water retention pond.
23 There will be no discharges to waters of the state from this retention pond.
•
8
• 1 Q. WHAT OTHER WATER QUALITY REQUIREMENTS ARE APPLICABLE
2 TO THE FACILITY?
3 A. Public Service will be required to obtain a construction storm water
4 discharge permit from CDPHE to authorize storm water discharges from
5 the construction area during construction of the new units. In addition, the
6 Company will need to obtain a minimal discharge permit to address any
7 wastewater generated during construction.
8 Q. WHAT KINDS OF SOLID WASTE WILL THESE NEW UNITS
9 GENERATE ONCE THEY ARE IN OPERATION?
10 A. The new combustion turbines will not generate any solid waste during
11 normal operation. Small quantities of waste lubricating oils may be
12 generated during periodic maintenance of the units.
13 Q. DOES THE COMPANY ANTICIPATE ANY PROBLEMS IN OBTAINING
14 THE REQUIRED PERMITS ACCORDING TO ITS TIMELINE?
15 A. No. Public Service has obtained minor modification air permits of this type
16 in the past within the time-frame noted above.
17 Q. WILL THE NEW COMBUSTION TURBINES USE ANY WATER?
18 A. Yes, but the consumptive water use of the simple cycle combustion
19 turbines is minimal and can be adequately supplied by the existing water
20 rights for the Fort St. Vrain Station.
21 Q DOES THIS CONCLUDE YOUR TESTIMONY?
22 A. Yes.
•
9
• Attachment A
Statement Of Qualifications
Gary Magno
As a Principle Environmental Analyst in the Environmental Services organization for
Xcel Energy Services Inc., I have responsibility for the air quality permitting and
compliance programs for Public Service Company of Colorado ("PSCo") facilities. My
primary responsibilities include major source air permitting and Title V permit
compliance for PSCo's coal and natural gas electric generating stations here in
Colorado. I am the project lead for the permitting of the proposed plant. I was also the
technical lead for the permitting of a new 750 MW Comanche 3 coal-fired unit in
. Pueblo and continue to work on special projects such as strategic planning to address
new regulatory requirements like regional haze, ozone non-attainment, and the control
of mercury emissions from coal-fired boilers.
I have a Bachelor of Sciences degree in Environmental Resources Management from
the Pennsylvania State University and over 28 years of experience working in the field
of air quality compliance for utility and industrial sources.
I have previously testified numerous times before the Colorado Air Quality Control
Commission and at several subcommittee hearings before the Pennsylvania State
Legislature.
•
;dam
OF COL ;
U FILIfIES t
Xcel Energy" 7001 NOV 27 PM 4: 34
0
PUBLIC SERVICE COMPANY
IN THE MATTER OF THE APPLICATION OF
PUBLIC SERVICE COMPANY OF COLORADO FOR
A CERTIFICATE OF PUBLIC CONVENIENCE AND
NECESSITY TO CONSTRUCT TWO COMBUSTION
TURBINES AT THE FORT ST. VRAIN GENERATING
STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED
TREATMENT
DOCKET NO. 07A--y/ i E
DIRECT TESTIMONY
AND EXHIBITS
November 2007
• BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
Docket No.
IN THE MATTER OF THE APPLICATION OF PUBLIC SERVICE COMPANY OF
COLORADO FOR APPROVAL OF A CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY TO CONSTRUCT TWO COMBUSTION TURBINES AT THE
FORT ST. VRAIN GENERATING STATION, FOR AN AMENDMENT TO ITS
CONTINGENCY PLAN, AND FOR EXPEDITED TREATMENT
DIRECT TESTIMONY AND EXHIBITS OF GERALD M. STELLERN
• ON
BEHALF OF
PUBLIC SERVICE COMPANY OF COLORADO
November 2007
411
•
1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A. My name is Gerald M. Stellern. My business address is 550 15th Street,
3 Denver, Colorado 80202.
4 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
5 A. I am employed by Public Service Company of Colorado ("Public Service" or
6 "Company"). My title is Manager of Transmission Reliability and Assessment.
7 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS DOCKET?
8 A. I am testifying on behalf of Public Service.
9 Q. HAVE YOU PREPARED A STATEMENT OF YOUR EXPERIENCE AND
10 QUALIFICATIONS?
11 A. Yes. That statement is included as Attachment A to my testimony.
• 12 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
13 A. The purpose of my testimony is to support the Company's application for a
14 certificate of public convenience and necessity to construct two combustion
15 turbines at the Fort St. Vrain generating station (the "Fort St. Vrain Project").
16 In particular, my testimony discusses the transmission network upgrades that
17 are necessary to deliver the full output of the Fort St. Vrain Project to
18 customer load. I also address the continued need for the Midway-to-Waterton
19 345 kV transmission line authorized by the Commission in Decision No. C07-
20 0750 ("Midway-Waterton").
21 Q. DOES THE COMPANY CURRENTLY HAVE ENOUGH TRANSMISSION
22 AVAILABILITY TO DELIVER THE OUTPUT OF THE FORT ST. VRAIN
• 23 PROJECT TO PUBLIC SERVICE LOADS?
1
• 1 A. No. Network upgrades will be required in order to reliably deliver the
2 additional generation to customer loads.
3 Q. WHAT TRANSMISSION FACILITY UPGRADES OR MODIFICATIONS AND
4 ASSOCIATED COSTS ARE REQUIRED TO DELIVER THE OUTPUT OF
5 THE FORT ST. VRAIN PROJECT TO PUBLIC SERVICE CUSTOMER
6 LOADS?
7 A. The transmission network upgrades required for delivering project generation
8 to the Public Service loads include:
9 a) Upgrading the two Ft. Lupton — Fort St. Vrain 230 kV lines (circuit
10 numbers 5311 and 5329) from their present 500 MVA (1255A, 100 deg C
11 conductor temp) continuous thermal rating to approximately 545 MVA
• 12 (1367A, 110 deg. C conductor temp), or 109% of the present rating.
13 These upgrades would include replacing the conductor on a 2.5-mile
14 section of these lines at an estimated cost of $645,000 total for both
15 circuits.
16 b) Replacing some line termination conductor at the Cherokee substation
17 for the Cherokee — Lacombe 230 kV line (circuit number 5057) at a cost of
18 approximately $10,000 - $15,000.
19 c) Replacing some line termination conductor at the Hogback substation
20 for the Lookout - Hogback— Soda Lakes 115 kV line (circuit number 9794)
21 at a cost of approximately $20,000 - $30,000.
22 d) Installing a second 230/115 kV, 280 MVA autotransformer at Valmont
23 substation. This project is planned to be completed by the summer of
•
2
• 1 2010, but installation of the autotransformer would need to be expedited
2 for completion by May 2009 by utilizing a transformer from another project.
3 e) Upgrading the 230 kV switchyard interconnection at Fort St. Vrain to
4 allow for connection of the Fort St. Vrain Project, at an estimated cost of
5 approximately $2.0-4.0 million.
6 Q. WHAT WOULD THE CONSTRUCTION TIMELINE BE FOR THE
7 UPGRADES YOU HAVE DESCRIBED?
8 A. All of the described work can be completed by the Transmission Function
9 prior to the May 2009 in-service date for the Fort St. Vrain project.
10 .Q. ARE THERE ANY SITING OR RIGHT-OF-WAY ISSUES WITH RESPECT
11 TO THE UPGRADES?
• 12 A. Siting and right-of-way issues are described in the prefiled direct testimony of
13 John Lupo.
14 Q. DOES THE COMPANY EXPECT TO FILE ANY APPLICATIONS WITH THE
15 COMMISSION FOR CERTIFICATES OF PUBLIC CONVENIENCE AND
16 NECESSITY WITH RESPECT TO THE UPGRADES THAT YOU
17 DESCRIBED?
18 A. No. The upgrades mentioned above would not require a CPCN pursuant to
19 Commission Rule 3206, 4 CCR 723-3.
20 Q. OTHER COMPANY WITNESSES HAVE TESTIFIED THAT THE FORT ST.
21 VRAIN PROJECT REPLACES A PLANNED PROJECT TO CONSTRUCT A
22 525-550 MW COMBINED CYCLE PLANT AT SQUIRREL CREEK,
23 COLORADO. HOW DOES THE TERMINATION OF THE SQUIRREL
3
• 1 CREEK PPA AFFECT THE COMPANY'S MIDWAY-WATERTON 345KV
2 PROJECT FOR WHICH THE COMMISSION HAS ALREADY GRANTED
3 THE COMPANY A CPCN?
4 A. The Midway-Waterton project was granted a CPCN from the Commission in
5 the summer of 2007 to accommodate the Squirrel Creek generation project.
6 Public Service is currently working on implementing this transmission project
7 by May 2010. Although the Midway-Waterton 345kV transmission project
8 was planned specifically for Squirrel Creek generation, the Company believes
9 that the project is essential regardless of the status of Squirrel Creek. The
10 Company will make an appropriate filing with the Commission to reflect the
11 cancellation of the Squirrel Creek generation project, and to explain why the
• 12 project is still required.
13 Q. CAN YOU SUMMARIZE THE REASONS WHY THE MIDWAY-WATERTON
14 PROJECT IS STILL REQUIRED?
15 A. The main reason Midway-Waterton project is still needed is to facilitate long-
16 range plans for transmission development to meet requirements for Senate
17 Bill 07-100. In its filings for Senate Bill 07-100, Public Service indicated that
18 the Eastern Plains Transmission Project ("EPTP") was part of the long-range
19 plan to accommodate additional resources in Energy Resource Zones #2 and
20 #3. (East central Colorado and Southeast Colorado) To help facilitate that
21 long-range plan, the Company executed a memorandum of understanding
22 with Tri-State Generation and Transmission Company ("TSG&T") on October
23 26, 2007 to assess the preliminary feasibility of Public Service's participation
•
• 4
• 1 as a joint owner in the EPTP project. TSG&T and Public Service have met to
2 discuss preliminary feasibility studies and will continue to evaluate the
3 feasibility of Public Service's joint ownership of the EPTP.
4 The EPTP has been planned and studied based on the assumption
5 that the Midway-Waterton 345kV project would be operational by 2010. The
6 EPTP includes a termination at the Midway Substation, and studies show that
7 the Midway-Waterton 345kV Project is required to mitigate unacceptable
8 impacts to Colorado Springs Utilities' transmission network.
9 Q. ARE THERE ANY OTHER REASONS FOR THE CONTINUED NEED FOR
10 THE MIDWAY-WATERTON PROJECT?
11 A. Yes. Even if EPTP was not built, it is likely that the Midway-Waterton 345kV
12 project would be required to facilitate any additional resource development in
•
13 southeast Colorado (energy zone 3 from Senate Bill 07-100). It would help
14 accommodate renewable and other generation resource interconnections
15 anywhere along the Front Range transmission path between Daniels Park
16 and Comanche, or along the transmission path between Comanche and
17 Lamar.
18 Q. WILL THERE BE ANY SAVINGS RELATED TO TRANSMISSION AS A
19 RESULT OF THE TERMINATION OF THE SQUIRREL CREEK PPA?
20 A. Yes. Public Service Transmission Function will not be required to install
21 network upgrades for interconnection at the Squirrel Creek Energy Center.
22 These costs were estimated at $8.585 million in the facility study dated
23 December 20, 2006.
•
• 1 Q. ARE THERE ANY EXPENDITURES ON TRANSMISSION THAT WILL BE
2 SUNK COSTS AS A RESULT OF THE TERMINATION OF THE SQUIRREL
3 CREEK PPA?
4 A. Yes. Public Service Transmission Function will have spent approximately
5 $230,000 for Network Upgrades for Interconnection at Squirrel Creek Energy
6 Center that would be sunk costs.
7 Q. DID PUBLIC SERVICE ENERGY SUPPLY OR MERCHANT FUNCTION
8 REQUEST ANY TRANSMISISON RELATED STUDIES ASSOCIATED WITH
9 THE FORT ST. VRAIN PROJECT?
10 A. Yes. Public Service's "Merchant Function" submitted an initial study request
11 to Public Service's "Transmission Function"' on August 31, 2007. Public
• 12 Service Merchant Function executed a special study agreement (NQ-2007-2)
13 with Transmission Function on Sept 27, 2007. Public Service Transmission
14 Function has evaluated the transmission request and has completed studies
15 in a final report dated October 19, 2007. Transmission Function updated that
16 final report with additional information on October 24, 2007. Those studies
17 were posted on the Company's OASIS site and are labeled NQ-2007-2. A
18 copy is attached to my testimony as Exhibit GMS-1.
"'Merchant Function"and "Transmission Function"refer to the division of Public Service functions as
between employees involved in planning and constructing transmission network facilities and those
involved in generation and trading activities, utilizing the Company's transmission facilities. FERC
Order No. 2004, Standards of Conduct for Transmission Providers, requires the separation of a
company's transmission and its merchant functions. A Transmission Function employee cannot
discuss information regarding the Company's transmission planning with a Merchant Function
employee unless the information has been posted on OASIS or is otherwise made publicly available.
•
6
• 1 On October 24, 2007 Public Service Energy Supply submitted a
2 generation interconnection request for 280 MW (summer net facility rating) of
3 increased generating capacity at Fort St. Vrain. The Transmission Function
4 will label this request as GI-2007-11. Pursuant to the FERC Large Generator
5 Interconnection Procedures ("LGIP") Transmission Function will process this
6 request. The study should be completed within 60-90 days after the two
7 parties have executed a study agreement and will evaluate the facility
8 requirements, cost and schedule for the Interconnection at the Fort St. Vrain
9 switchyard.
10 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
11 A. Yes.
•
•
7
• Attachment A
Statement of Qualifications
Gerald M. Stellern
I graduated from the University of Missouri-Rolla in December of 1973. I
started my career at Public Service Company of Colorado in 1974. My career
started in the Electric Planning and Analysis group where I worked for approximately
15 years working as a Transmission Planning Engineer, and later as the Supervisor
of Loads and Resources Planning. My job function was primarily to produce a
customer demand load forecast and to acquire adequate resources to meet that
customer demand. I received my Professional Engineer's license from the State of
Colorado in 1978.
• In 1990 my career directed me to Operations and the Operations Control
Center. I worked as Senior Operations Engineer, Manager of the Transmission and
Substation desk, Operations Manager, and Manager of the Real Time Engineering
group. In this capacity I performed all functions related to managing and operating
the Transmission assets of PSCo and the interconnected Transmission system.
In 2005, I became the Manager of Transmission Reliability Assessment for
PSCo, in which I have responsibility for the capital transmission budget as well as
planning the Transmission system of PSCo to meet the growing needs of our
customers to ensure reliability for the customers. I am also responsible for
responding to customer requests for generation, transmission and load
interconnections by performing technical studies and to determine any Network
upgrades required to accommodate the request. In 2006 and 2007 the Planning
•
• function has completed approximately 30 generation interconnection study reports,
several transmission study reports and a multitude of load interconnection reports.
•
•
Exhibit No. GMS-1
• Interconnection Non Queued Study — Final Report (Revised)
Request # NQ-2007-2
150 MW CTG #'s 5 & 6 (300 MW total) Additions at Fort St. Vrain
Generation Plant in Summer 2009
PSCo Transmission Planning
October 24, 2007
Executive Summary
On or about August 31, 2007 Public Service Company of Colorado (PSCo)
Transmission Planning received a generation interconnection request to determine the
potential impacts of installing two simple-cycle gas-fired combustion turbine generators
(CTG 5 & CTG 6) at its Fort St. Vrain (FSV) generation plant located north of Denver in
Weld County, Colorado. Each CTG is to be rated for an output capacity of 150 MW
summer and 180 MW winter, with a planned in-service date of no later than June 1,
2009. The request was predicated on the stated assumption that the previously
planned new Squirrel Creek Energy 500 MW combined cycle plant to be located south
of Denver near Fountain, Colorado may not be completed by the summer of 2009. This
request was studied as strictly a Network Resource (NR)1, with no investigation
• performed as to the details or costs associated with the installation and interconnection
of the two new CTGs and associated transformation and protection (breakers, etc.) into
the existing 230 kV station at FSV. This investigation included steady-state power flow
studies only, and did not include any transient dynamic stability, or short-circuit analysis.
The request was studied as a stand-alone project only, with no evaluations made of
other potential new generation requests that may exist in the LGIR queue, other than
the generation projects that are already approved and planned to be in service by the
summer of 2009. The purpose of this special study was to evaluate the potential
impacts on the PSCo transmission infrastructure to inject the additional 300 MW
(summer) into the FSV 230 kV bus, and deliver the additional generation to native PSCo
loads. This project cost to install the transmission system infrastructure (NR) upgrades
necessary to accommodate the added FSV generation has been evaluated by
Engineering, with the details of these upgrades identified in the Power Flow Study
Results and Conclusions, and the Appendix sections of this report. Refer to Figure 1 for
details illustrating the basic transmission system in the FSV region.
Based upon the investigations completed, the required transmission upgrades
should be achievable by the summer of 2009. The work required consists of:
I Network Resource Interconnection Service shall mean an Interconnection Service that allows the
Interconnection Customer to integrate its Large Generating Facility with the Transmission Provider's Transmission
System(1)in a manner comparable to that in which the Transmission Provider integrates its generating facilities
to serve native load customers;or(2)in an RTO or ISO with market based congestion management,in the same
manner as all other Network Resources.Network Resource Interconnection Service in and of itself does not convey
transmission service.
•
NQ-2007-2-FSV300RAL-Final2.doc Page 1 of 15
Last Rev 10-24-07 Ray LaPanse
Exhibit No. GMS-1
• • Replacing the conductor on a 2.5 mile section of the Ft. Lupton— FSV 230 kV
double circuit line. Estimated cost$645k.
■ Minor line termination upgrades (conductor jumpers, relay settings changes,
etc.), or utilize the 4-hr. emergency ratings capability of existing bus conductor at
six substations. Estimated cost$30k (total).
■ Expedite from May 2010 to May 2009 the previously approved and budgeted
project to install a second 230/115 kV, 280 MVA autotransformer at Valmont
Substation. Estimated cost$4.7 million (previously approved and
budgeted).
Stand Alone Study Results
The stand-alone results assume that the new generation interconnecting at the FSV 230
kV bus is modeled in the power flow case at full output, or approximately 300 MW, and
the rest of the generation and loads in the power flow model reflect a heavy summer
load, heavy north-to-south (HSHN) stressed 2009 case (see Power Flow Study Models
section below).
Energy Resource (ER):
This special study assumes that the generation equipment can be installed such that
it interconnects into the 230 kV transmission bus at FSV. No investigations as to the
feasibility of, or costs associated with the interconnection facilities have been done
as part of this study.
• Network Resource (NR):
The Customer can provide the full 300 MW FSV generation additions, once some
modifications have been completed to the PSCo transmission system infrastructure.
Following is a list of the lines and autos that either incur new single contingency (N-
1) overloading, or that become significantly overloaded as a result of adding 300
MW of new generation at FSV (two 150 MW CTGs, G5 & G6 summer rating) in
heavy summer 2009 power flow cases (i.e., 5% or more differential loading between
the case with FSV new generation at 300 MW vs. 0 MW).
The line ratings and limiting elements identified in the following list (Table 1) are
based upon the latest Rev.3 of FAC-009 (Transmission Equipment Facility Ratings).
The recommended upgrades and revised line ratings are based upon investigations
performed by the XE /PSCo Transmission and Substation Engineering groups, with
the items listed here as limited to lines /substations requiring upgrades. Additional
details regarding the lines and limiting equipment identified in the preliminary and
follow-up power flow studies can be found in the Appendix (Contingency Results
Tables).
• NQ-2007-2-FSV300_RAL-Final2.doc Page 2 of 15
Last Rev 10-24-07 Ray LaPanse
Exhibit No. GMS-1
• Table 1:Summary listing of overloaded elements with required upgrades
Max Overload%
Overloaded Line I Element (Revised Rate, FSV 300"Heavy Scope of Work and Cost
Stress"HSHN case)
Cherokee—Lacombe 230 kV 123%(sub cont rate)/ Cherokee Sub—replace line
(Ckt. #5057) 106% (sub 4-hr emerg rate) term conductor($15k)
Transmission line—replace
Ft. Lupton-FSV 230 kV 108%(T-line 4 FPS) damaged conductor on
(Ckt. #5311) approx. 2.5 mile section of
this double-ckt. line ($322.5k).
Transmission line—replace
Ft. Lupton -FSV 230 kV 108%(T-line 4 FPS) damaged conductor on
(Ckt.#5329) approx. 2.5 mile section of
this double-ckt line($322.5k).
Hogback—Lookout 115 kV 126%(sub cont rate)/ Hogback Sub—replace line
(Ckt.#9794) 108%(sub 4-hr emerg rate) term conductor($15k)
Expedite planned/budget
approved installation of
Valmont 2301115kv,280 MVA second Valmont autoxfmr
Valmont
23 /11 k 120%(cont rate) from 2010 into May 2009.
Autot (Previously approved-
budgeted cost est. $4.7
million).
• •
• NQ-2007-2-FSV300_RAL-Final2.doc Page 3 of 15
Last Rev 10-24-07 Ray LaPanse
Exhibit No. GMS-1
• Figure 1: Existing PSCo 230 kV Transmission System in the FSV—Metro Region
(This is a simplified 230 kV system diagram and does not include all system details)
Ault
"TOT 7" Border
(The TOTS Border is further north of Ault)
Windsor -
Fordham Weld ___-----
Cedar Creek
(2009)
4 Peetz Logan
Longs Peak \ Ft. St. Vrain Pawnee
--
Keenesburg
Niwot Val ont Ft. TCTI '
uptor O RMEC
Spindle
Leggett -- Green Vly
Simms "K Henry Lk ,„.. Brighton
Plains �_ S
® _ BSEC Spruce
p
End -`: Rid e
eunion - Brick
Lookout Cherokee
• Silver Powhaton _ Quincy Center
Saddle
Denve
Term Leetsdale
Smoky Hill
Soda Lakes Arapahoe
®Greenwood
ilia ili
Waterton
Daniels Park
• NQ-2007-2-FSV300 RAL-Final2.doc Page 4 of 15
Last Rev 10-24-07 Ray LaPanse
Exhibit No. GMS-1
• Study Scope and Analysis
The Interconnection Special Study evaluated the transmission impacts associated
with the proposed interconnection of 300 MW of additional new generation at FSV
230 kV into the PSCo Transmission System. It consisted of steady-state power flow
analyses only. The power flow analysis provided a preliminary identification of any
thermal or voltage limit violations resulting for the interconnection, and for a NR
request, a preliminary identification of network upgrades required to deliver the
proposed generation to PSCo loads.
PSCo adheres to NERC /WECC Reliability Criteria, as well as internal Company
criteria for planning studies. During system intact conditions, criteria are to maintain
transmission system bus voltages between 0.95 and 1.05 per-unit of system nominal
/ normal conditions, and steady-state power flows within 1.0 per-unit of all elements'
thermal (continuous current or MVA) ratings. Operationally, PSCo tries to maintain a
transmission system voltage profile ranging from 1.02 per-unit or higher at
generation buses, to 1.0 per-unit or higher at transmission load buses. Following a
single contingency element outage, transmission system steady state bus voltages
must remain within 0.90 per-unit to 1.10 per-unit, and power flows within 1.0 per-unit
of the elements continuous thermal ratings.
For this project, potential affected parties include Western Area Power
Administration (WAPA), Tri-State Generation and Transmission (TSGT), and Platte
• River Power Authority (PRPA). However, due to the expedited schedule required for
this special study, none of these parties have been contacted or involved in the
study at this time.
Power Flow Study Models
The power flow studies were based on a PSCo-developed 2009 heavy summer
base case that originated from the study model developed in early 2007 as part of
PSCo's normal annual 5-year transmission capital budget project identification
process. These budget case models are developed from Western Electricity
Coordinating Council (WECC) approved models, modified as appropriate for PSCo
planned and approved projects and associated topology. Load levels reflect 2009
heavy summer peak system conditions. PSCo control area 70 generation was
dispatched in the case to simulate two different north-to-south stressed system
conditions, with the area 70 swing bus moved to Comanche#1, and generation
levels in the north generally increased to near maximum levels. In the initial "Heavy
Stressed" (Heavy Summer, Heavy North HSHN) case (see Tables 1 and 3 in the
Appendix), the TOT 3 path at the Colorado—Wyoming border, and the TOT 7 path
immediately north of FSV (see Figure 1) levels were increased to relatively high
levels of approximately 1450 MW for TOT 3 and approximately 550 MW for TOT 7.
In the follow-up "Moderately Stressed" (Heavy Summer HS) cases, the cases were
re-dispatched for TOT3 path flows for approximately 1250 MW, and TOT7 for
approximately 460 MW. The PSCo control area (CA 70) wind generation facilities
• NQ-2007-2-FSV300_RAL-Final2.doc Page 5 of 15
Last Rev 10-24-07 Ray LaPanse
Exhibit No. GMS-1
• were dispatched to 10% of net facility ratings, consistent with other similar planning
study models.
The new additional 300 MW of generation at FSV was modeled as two new 150 MW
combustion turbine generators (CTGs), similar to the existing FSV 130 MW (206
MVA, 0.85 p.f., Pmax 130 MW, Qmax 85 MVAR,) CTG units 2, 3, and 4. The
Customer mentioned that the new generators would be rated for 180 MW winter/
150 MW summer, therefore for this summer case the new generators were
conservatively modeled with a maximum capability of 150 MW(Pmax) /85 MVAR
(Qmax), or effectively 172 MVA at 0.87 p.f. These gross MVAR generation
capabilities would exceed the amounts necessary to achieve a net HV (230 kV )
Point of Interconnection (P.O.1.) +/- 0.95 p.f. Capability, which were calculated to be
approximately 150 MW/64 MVAR gross at the 18 kV gen bus for a resulting 150
MW/51 MVAR net (0.95 p.f.) on the 230 kV HV bus, with the 13 MVAR differential
equating to the MVAR losses in the GSU transformer. Each generator was modeled
with an associated 230 - 18 KV, 178 /222 MVA GSU transformer, with the same
impedances/electrical characteristics as the existing GSU #2.
The 2009 case model topology was further modified to remove the Squirrel Creek
500 MW generation facility, previously modeled tapping into the Daniels Park—
Comanche 345 kV line, and the associated 230 kV transmission infrastructure
additions (namely removing a second 230 kV Daniels Park— Midway 230 kV line).
The 345 kV transmission infrastructure additions associated with the new Comanche
#3 generation project, which are planned to be in service by summer of 2009, were
• maintained in the model. This model does not include the new Comanche#3 (750
MW) generation itself, as it will not be in service until after the summer of 2009. The
project generation was scheduled to the southern PSCo system by reducing
generation in that area. Other generation was re-scheduled during the evaluation
the Customer's request to the other entities' native load.
Power Flow Study Results and Conclusions
Two main power flow case model generation dispatch scenarios were evaluated: a
reference model without the additional new 300 MW FSV generation GTG5 & GTG6
addition ("FSV 0" case); and a model with the new 300 MW(summer) of generation
included at FSV ("FSV 300" case). The FSV 300 case was re-dispatched to lower
other PSCo control area generation by 300 MW, mainly in the southern part of the
PSCo system in order to maintain or maximize the north-to-south system stressing
(and TOT 7 path flows) in the cases. Several generation dispatch "stressed" cases
were created to evaluate the sensitivities of various levels of north-to-south system
flow levels; the aforementioned "heavy stressed" HSHN, and "moderately stressed"
HS cases. An additional case study was performed with the various levels of
generation at the nearby 600 MW RMEC generation facility
Automated contingency power flow studies were completed on all four case models
using PTI's MUST program routine, switching out single elements one at a time for
• all of the elements (lines and transformers) in control areas 70 (PSCo) and 73
NQ-2007-2-FSV300 RAL-Final2.doc Page 6 of 15
Last Rev 10-24-07 Ray LaPanse
Exhibit No. GMS-1
(WAPA RM). Upon switching each element out, the program re-solves with all
voltage taps and switched shunt devices locked, and control area interchange
adjustments disabled.
These automated contingency studies were performed for both the FSV 300, and
the FSV 0 models, and the results listing the overloaded elements (load flows in
excess of their continuous rating) were compared. As previously stated in the Stand
Alone Study Results section of this report, these studies indicated that the additional
300 MW of injection into the FSV 230 kV bus could cause new and/or additional load
flows in excess of present or planned element ratings on several 230 kV
transmission lines (line conductor, or associated substation termination equipment),
plus one 230-115 kV autotransformer (Valmont), under single-contingency (N-1)
conditions. As a result of the investigations performed by Transmission and
Substations Engineering, some of the limiting equipment ratings have been revised,
resulting in a reduction of the original nine overloaded lines identified in the
preliminary Study Report, to four overloaded lines/subs requiring some upgrades,
plus the overloaded Valmont autotransformer. The continuous current ratings for
these lines as limited by either the transmission line conductor (sag clearance
limitations) or the substation termination equipment (jumpers, switches, relaying /CT
limitations, breakers, etc.) have been, or are being investigated by Substation and
Transmission Engineering in order to determine the measures (scope, cost, and
schedule/time) necessary to bring the ratings up to or exceeding the MVA (e.g.
continuous current) conditions identified for these specific overloaded lines.
• Based upon the investigations completed so far, it is believed that the modifications
will likely be relatively minor in scope, and should be achievable by the summer of
2009. In some cases under the extreme stressed conditions modeled in this study, it
is assumed that the 4-hour emergency ratings for some of the limiting substation
termination equipment will be utilized, until the system operators are able to adjust
generation and/or line switching conditions in order to bring the transmission flows
within the continuous thermal ratings of the equipment. Note that the final scope for
some of the network upgrades has not yet finally determined, most notably potential
line upgrades for the two Ft. Lupton— FSV 230 kV lines, and the results of these
remaining investigations will be included in a supplement to this final study report.
As there are several 230 kV lines exiting FSV with shared transmission tower
configurations, additional double-contingency (N-2) outage cases were manually
run. These runs were completed on a total of four 230 kV double-circuit outage
scenarios, with the results summarized in Table 3 of the Appendix.
• NQ-2007-2-FSV300RAL-Final2.doc Page 7 of 15
Last Rev 10-24-07 Ray LaPanse
Exhibit No. GMS-1
•
Appendix
Power Flow Contingency Results Tables
•
NOTE -the elements identified in this study report as overloaded in these
contingency runs, are limited to the new or significantly increased overloads, and do
not address all of the elements that may have been indicated as overloaded in the
contingency runs. The other elements that may be overloaded, independent of the
new 300 MW generation injection at FSV, will be addressed through other separate
Transmission Planning project proposals.
• NO-2007-2-FSV300_RAL-Final2.doc Page 8 of 15
Last Rev 10-24-07 Ray LaPanse
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•
Table 4: Heavy North to South Stressed System Case(2009HSHN RL5,TOT3= 1453,
TOT7=609),Common Tower N-2 Double Contingency Outage Results: (in %of original
rates)
FSV 300 Case($2) FSV 0 Case(N-2)
(N-2)Ckts Out OL Element Element Leading Element Loading
(MVA l%of Rate) (MVA/%of Rate)
#5953 (FSV-Spindle); & #5057 Cher-Lacombe 512.8 MVA/115.5% 454.6 MVA/ 102.4%
#5307(FSV—Niwot)
#5311 FSV-Ft.Lupton#1 493.7/ 111.2 419.2/92.6
#5329 FSV-Ft.Lupton#2 493.7/ 111.2 419.2/92.6
#5183 JL Green-FtLupt 521.5/ 109.1 468.1 /99.7
#5527 Wash-JL Green 505.6/ 122.4 452.4/111.5
#5527 Glenn-Wash 413.9/100.2 362.3/89.4
#5327(FSV—Green Vly); & #5527 Wash-JL Green 435.3 MVA/ 105.4% 393.4 MVA/96.7%
#5279 (Keenesbq—Green Vly)
#5311 (FSV-Ft.Lupton#1); &* #5385 Valmont-Spindle 576.9 MVA/ 103.6% 531.2 MVA/92.6%
#5329 (FSV-Ft.Lupton#2);
#5307(FSV-Niwot); & #5057 Cher-Lacombe 555.1 MVA/ 125% 496.5 MVA/111.8%
#5385 (Spindle-Valmont)
• #5311 FSV-Ft.Lupton#1 577.8/130.1 494.6/111.4
#5329 FSV-Ft.Lupton#2 577.8/ 130.1 494.6/ 111.4
#5183 JL Green-FtLupt 574.4/ 120.2 528.6/ 110.6
#5527 Wash-JL Green 466.1 / 112.9 420.7/101.9
#5527 Glenn-Wash 558.4/ 135.2 512.6/124.1
NOTE—These additional N-2 double contingency power flow studies were run as an
additional sensitivity study only, and do not necessarily reflect any likely or probable
events.
• NQ-2007-2-FSV300_RAL-Final2.doc Page 15 of 15
Last Rev 10-24-07 Ray LaPanse
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