Exhibit 99.02
BEFORE THE
PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
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IN THE MATTER OF THE APPLICATION OF
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PUBLIC SERVICE COMPANY OF COLORADO
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Docket No. 04A-214E
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FOR APPROVAL OF ITS 2003 LEAST-COST
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RESOURCE PLAN
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IN THE MATTER OF THE APPLICATION OF
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PUBLIC SERVICE COMPANY OF COLORADO
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FOR AN ORDER APPROVING A
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Docket No. 04A-215E
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REGULATORY PLAN TO SUPPORT THE
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COMPANY’S 2003 LEAST-COST RESOURCE
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PLAN
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IN THE MATTER OF THE APPLICATION OF
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PUBLIC SERVICE COMPANY OF COLORADO
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FOR A CERTIFICATE OF PUBLIC
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Docket No. 04A-216E
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CONVENIENCE AND NECESSITY FOR THE
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COMANCHE UNIT 3 GENERATION FACILITY
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COMPREHENSIVE SETTLEMENT AGREEMENT
December 3, 2004
PARTIES TO THIS COMPREHENSIVE SETTLEMENT
Public Service Company of Colorado, the Staff of the Colorado Public
Utilities Commission (“Staff”), the Colorado Office of Consumer Counsel (“OCC”),
the Colorado Energy Consumers Group(1), the Colorado Governor’s Office of
Energy Management and Conservation, Western Resource Advocates, Colorado
Coalition for New Energy Technologies, Southwest Energy Efficiency
Project, Environment Colorado, Colorado
Renewable Energy Society, the City and County of Denver, and Tri-State
Generation & Transmission Association, Inc. (collectively, the “Parties”)
hereby enter into this Comprehensive Settlement Agreement(2).
INTRODUCTION
On April 30, 2004 Public Service Company of Colorado (“Public
Service” or the “Company”) filed with
the Commission the Verified Application of Public Service Company of Colorado
for Approval of its 2003 Least-Cost Resource Plan. With the application, the Company filed its
Least-Cost Resource Plan (“LCP”) in four volumes: Volume 1 – Plan Summary; Volume 2 – Renewable
Energy Request for Proposals; Volume 3 – All-Source Requests for Proposals; and
Volume 4 –Technical Appendix.
(1)
Although a part of the Colorado Energy
Consumers Group, AARP does not join in this Comprehensive Settlement Agreement
and takes no position with respect to whether it should be approved.
(2) The following
intervenors have not signed this Comprehensive Settlement Agreement: Colorado
Mining Association, Colorado Independent Energy Association; Calpine Corporation;
CF&I Steel, LP; City of Boulder; Climax Molybdenum Company; North American
Power Group, Ltd.; L S Power Associates, L.P.; Baca Green Energy; LLC, Prairie
Wind Energy, LLC; Pacificorp; Sun Power, Inc.; Arkansas River Power Authority;
Rocky Mountain Farmers Union; Aquila, Inc.; Yampa Valley Electric Association,
Incorporated; Holy Cross Energy; and the Regents of the University of Colorado
at Boulder. Some of these parties are
still reviewing the Comprehensive Settlement Agreement and may join the
settlement on or before the date of the evidentiary hearing scheduled for December 8,
2004.
1
The Company
also filed the Motion of Public Service Company of Colorado for Waiver of the
250 MW Limit in LCP Rule 3610 (b) to Permit the Construction of Comanche Unit
3.
On April 30, 2004, Public Service also filed the Verified
Application For an Order Granting to Public Service Company of Colorado a
Certificate of Public Convenience and Necessity, with supporting testimony, to
construct Comanche 3(3). Further, on April 30,
2004, the Company filed a Verified Application, with supporting testimony, for
an order approving a proposed regulatory plan to support the Company’s 2003
Least-Cost Resource Plan. The Company
filed motions to consolidate into one docket the three applications filed on April 30.
The Commission granted the Company’s motions to consolidate the three
applications, but severed consideration of the Renewable Energy Request for
Proposals from this consolidated docket and addressed the Company’s Renewable
Energy RFP in Commission Docket No. 04A-325E.
On August 13, 2004, Public Service filed Supplemental Direct
Testimony. On September 13, 2004,
the Intervenors filed Answer Testimony.
On October 18, 2004, Public Service filed Rebuttal Testimony and
other parties filed Cross-Answer Testimony.
(3) Comanche 3 shall be defined to mean a new
coal-fired steam electric generating unit with a summer net dependable capacity
of 750 MW, and a maximum gross heat input rate of approximately 7421 million
Btu per hour as set forth in the preconstruction air permit application, and to
be located at the existing Comanche Station near Pueblo, Colorado. Public Service shall operate Comanche 3 but
may co-own the unit with other entities.
“Comanche 1” shall mean an existing coal-fired steam generating unit
with a summer net dependable capacity of 325 MW. “Comanche 2” shall mean an existing
coal-fired steam generating unit with a summer net dependable capacity of 335
MW. “Comanche Station” shall mean Comanche 1, Comanche 2 and Comanche 3,
collectively.
2
Hearings were held from November 1 through November 17,
2004. At the hearing on November 18,
the Company requested suspension of hearings to afford time to negotiate
settlement of the contested issues in this consolidated docket. By Decision No. C04-1409 the Commission
agreed to continue the hearings until December 8, 2004.
SETTLEMENT WITH CONCERNED ENVIRONMENTAL
AND COMMUNITY PARTIES
Public Service conducted two separate sets of settlement
discussions. The first set of
discussions was among Public Service and national, regional, and local
environmental and community groups who had expressed concerns about the public
health and environmental impacts that will result from Comanche 3. These groups
are collectively referred to as the “Concerned Environmental and Community
Parties” or “CECP”. Some of the CECP
groups are intervening parties in this consolidated Commission docket; others
spoke at the Commission’s public statement hearings; others have not presented
their views directly to the Commission.
Public Service reached settlement with CECP. The “CECP Settlement” is attached to this
Comprehensive Settlement Agreement as Attachment A(4). In consideration for the
emission reductions and other provisions of the CECP Settlement, the Concerned
Environmental and Community Parties agreed not to initiate, fund or participate
in any formal administrative or legal action to oppose or knowingly impede the
permitting or approval of those activities necessary for the construction and
(4)
This Comprehensive Settlement Agreement
generally describes the obligations of CECP.
To the extent there are any inconsistencies between the general
descriptions of CECP obligations in this Comprehensive Settlement Agreement and
the CECP Settlement, the CECP Settlement shall control.
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operation of
Comanche 3 that are listed in Section 16 of the CECP Settlement. The CECP
Settlement should mitigate but may not eliminate the risk of delay in the air
permitting and construction of Comanche 3.
Delay in obtaining the air permit for Comanche 3 would erode the
economic benefits provided by Comanche 3 to Public Service’s customers.
Pursuant to Section 17(A) of the CECP Settlement, Public Service agreed to seek Commission
approval for the commitments in Sections 3, 4, 5, 6, 7, 8, 12, 14 and 15 of the
CECP Settlement, as part of the Commission order on the Company’s 2003 Least
Cost Plan. Section 17(A) states
that, if the Commission does not approve in full the Company undertaking the
commitments in these sections of the CECP Settlement, or if a Commission order significantly
impedes implementation of any of the commitments under the CECP Settlement, or
if the Commission Order approving such commitments is reversed on judicial
appeal in any significant respect, Public Service’s and CECP’s obligations
under the CECP Settlement are terminated.
Since Public Service and its customers derive significant benefits from
the CECP Settlement, termination of the CECP Settlement should be avoided. Public Service and the Parties to this
Comprehensive Settlement Agreement agree that it is in the public interest for
the Commission to approve Public Service undertaking the commitments set forth
in Sections 3, 4, 5, 6, 7, 8, 12, 14 and 15 of the CECP Settlement. These provisions are referenced in this
Comprehensive Settlement Agreement. Public Service and the Parties to this
Comprehensive Settlement Agreement further request that the Commission not
issue an order that would significantly impede the implementation of any of the
commitments set forth in the CECP Settlement. Notwithstanding the
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foregoing,
unless a Party to this Comprehensive Settlement Agreement is also a signatory
to the CECP Settlement, a Party to this Comprehensive Settlement Agreement is
not bound by the provisions in the CECP Settlement. The Parties to this
Comprehensive Settlement Agreement have attempted to make the Comprehensive
Settlement Agreement and the CECP Settlement consistent with each other in all
material respects, and it is the Parties’ intent and recommendation that the
two agreements should be interpreted as consistent with each other. However, Public Service is not asking for the
Commission to agree to the CECP Settlement in its entirety because it addresses
some issues that are beyond the scope of this proceeding. Public Service and the Parties to this
Comprehensive Settlement Agreement are requesting only that the Commission
approve this Comprehensive Settlement Agreement.
COMPREHENSIVE SETTLEMENT WITH PARTIES TO
CONSOLIDATED COMMISSION DOCKET
The second set of settlement discussions was held among Public Service
and some of the intervening parties in this consolidated docket. These
settlement negotiations have resulted in this Comprehensive Settlement
Agreement.
COMPREHENSIVE
SETTLEMENT
The Parties to this Comprehensive Settlement Agreement hereby agree to
the following resolution of the contested issues in this consolidated docket.
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CPCN
for Comanche 3
1.
The
Commission should grant the Company a Certificate of Public Convenience and
Necessity (“CPCN”) to construct Comanche 3 as a supercritical pulverized
coal-fired steam electric generating unit.
The description of Comanche 3 is set forth in the testimony and exhibits
filed by the Company with its Application for a CPCN. The CPCN granted by the Commission should
also grant the Company permission to install both the new emission controls to
the existing generating units Comanche 1 and Comanche 2 that are discussed in
the Company’s LCP and testimony and exhibits and the additional environmental
controls that are discussed below in this Comprehensive Settlement
Agreement. The construction authorized
by this CPCN for Comanche 3 and the additional environmental controls for
Comanche 1 and Comanche 2 shall be referred to collectively in this
Comprehensive Settlement Agreement as the “Comanche Project.”
2.
Public
Service has preexisting contractual commitments that require it to offer
ownership shares in Comanche 3 to Intermountain Rural Electric Association and
Holy Cross Energy. If both of these Colorado utilities agree to participate
with Public Service in Comanche 3, Public Service’s share of Comanche 3 would
be approximately 500 MW. In its CPCN Application, Public Service requested a
CPCN to construct a 750 MW Comanche 3 and to own 500 MW of Comanche 3. Negotiations between Public Service and
Intermountain Rural Electric Association, and between Public Service and Holy
Cross Energy, for participation in Comanche 3 have not yet been completed.
3.
Due
to the expected benefits from Comanche 3, the Parties agree that the Commission
should grant Public Service a CPCN that will allow Public Service to
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construct and
own 750 MW of Comanche 3. Given Public
Service’s pre-existing contractual commitments to Intermountain Rural Electric
Association and Holy Cross Energy, the Parties further agree that the
Commission should approve, as part of the CPCN, a transfer by Public Service to
Intermountain Rural Electric Association and to Holy Cross Energy of an
ownership share of up to approximately 250 MW, but these transfer approvals
shall be subject to the limitations set forth in Highly Confidential Attachment
B to this Comprehensive Settlement Agreement.
Should Public Service not be able to reach joint ownership terms and
conditions with either Intermountain Rural Electric Association or Holy Cross
Energy or both that comply with the limitations set forth in Highly
Confidential Attachment B, then Public Service must file a separate application
with the Commission under C.R.S. §40-5-105 if Public Service desires to
transfer an ownership interest in Comanche 3 to the utility who refused to
agree to ownership terms and conditions that comply with the limitations set
forth in Highly Confidential Attachment B.
Should Public Service desire to sell an ownership share in Comanche 3 to
any entity other than Intermountain Rural Electric Association or Holy Cross
Energy, Public Service must obtain Commission approval under C.R.S. §40-5-105.
4.
In
order to grant Public Service the CPCN set forth in this Comprehensive
Settlement Agreement, the Parties recommend that the Commission grant Public
Service’s motion for a waiver of the 250 MW limit in Rule 3610 (b) of the
Commission’s Least-Cost Resource Planning Rules.
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Additional
Environmental Controls
5.
The
Company shall install lime spray dryers on both Comanche 1 and Comanche 2 as
required by section 3 of the CECP Settlement. The cost of the lime spray dryer for Comanche
2 was already included within the cost estimates set forth in the Company’s
testimony and exhibits. The additional
lime spray dryer for Comanche 1 is estimated to cost approximately $48 million
($2003).
6.
Public
Service shall comply with the monitoring, testing and emission limits for
mercury set forth in section 7 of the CECP Settlement. The CECP Settlement establishes a process by
which the Company will test mercury emissions at Comanche Station no later than
180 days after the initial startup of Comanche 3 and will provide its test
results to the Colorado Department of Public Health and Environment (“CDPHE”)
and CECP. The CDPHE shall use the test
results provided by the Company to determine the maximum level of mercury
control for the Comanche Station that CDPHE considers to be cost-effective
based on a dollar per pound of mercury removed.
The mercury control limits determined by CDPHE to maximize
cost-effective reductions for Comanche Station will be incorporated into the
Title V operating permit. The mercury
control technology is likely to be sorbent injection, unless a better control
technology emerges. It is anticipated
that Public Service will need to install, as it constructs the Comanche
Project, mercury emission controls with an estimated capital cost of
approximately $3 million ($2003). Public Service anticipates that the mercury
emissions testing that it will perform for CDPHE will cost approximately
$500,000 ($2004). Finally, Public
Service anticipates that the mercury control level determined by CDPHE, as
described above, will require Public Service to spend initially from $2 million
to $5
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million per
year in the first year’s operation and maintenance costs associated with the
control technology, beginning no later than two years after the initial startup
of Comanche 3. This annual operation and
maintenance expense may increase with the escalation in the variable costs of
the control technology or due to the establishment of laws or regulations that
provide for more stringent mercury emissions limits than those determined by
CDPHE as a result of the process set forth in the CECP Settlement.
7.
All
emission control equipment installed on Comanche 1, Comanche 2 and Comanche 3
shall be designed to comply with the specific emission limits, installation and
compliance schedules, and other permit requirements set forth in sections 3, 4,
5, 6, 7 and 8 of the CECP Settlement.
8.
In
addition to the specific additional environmental controls set forth in this
Comprehensive Settlement Agreement, Public Service may be required by either
CDPHE or the United States Environmental Protection Agency to incur additional
expenditures in order to receive an air permit for Comanche 3.
9.
The
Parties agree that, except as provided later in this Comprehensive Settlement
Agreement with respect to the Construction Cost Cap, the investments in
environmental controls associated with the Comanche Project set forth in
paragraphs 5 through 8 above are deemed prudent and are recoverable in
rates. The Parties further agree that
operation and maintenance expenses associated with the environmental controls
set forth in paragraphs 5 through 8 above are recoverable in rates by Public
Service to the extent the operation and maintenance expenses are prudently
incurred.
10.
Section 9
of the CECP Settlement sets forth additional covenants that address
environmental mitigation in the Pueblo area. Public Service agrees that the
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environmental
mitigation covenants in section 9 of the CECP Settlement with respect to
shredded car bodies at the Rocky Mountain Steel plant in Pueblo and the diesel
school buses in the Pueblo area shall not be recoverable in rates.
11.
The
CECP Settlement also addresses in section 10 sustainable development
activities for the Pueblo region, and in section 13 the consideration of
innovative technologies. The Parties to
this Comprehensive Settlement Agreement who are not signatories to the CECP
Settlement are taking no position with respect to these covenants in the CECP
Settlement. Further, the Parties to this
Comprehensive Settlement Agreement request that the Commission take no action
at this time as to the rate treatment that should be afforded in future rate
proceedings to any costs incurred by the Company to comply with the sustainable
development activities and with the consideration of innovative technologies
required under the CECP Settlement.
Construction
Cost Cap
12.
In
exchange for the compromises reflected in this Comprehensive Settlement
Agreement, Public Service agrees that the construction costs for the Comanche
Project that may be placed into its rate base shall be subject to a cap. Public Service shall be limited to placing
into utility rate base the actual capital expenditures(5) for the Comanche
Project that are equal to or below the Construction Cost Cap determined in
accord with Highly Confidential Attachment C.
The Parties agree that actual capital expenditures incurred by Public
Service, up to and including the level set by this Construction Cost Cap,
represent reasonable and prudent
(5)
By “actual capital expenditures” the Parties
mean the capital expenditures that are recorded in the Company’s books and records
under the FERC Uniform System of Accounts.
Separate sub-accounts shall be established for the Comanche Project.
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expenditures by Public Service that shall not be subject to challenge
at the time that the Company seeks to place the Comanche Project into rate
base, except to the extent a Party could establish that an expenditure resulted
from fraud or deceit on the part of Public Service, its affiliates, or its
contractors.
13.
In
addition to actual construction cost up to the Construction Cost Cap, Public
Service shall be entitled to include in rate base, when a
commercially-operational Comanche 3 is reflected in the test year of a Phase 1
rate proceeding, the Company’s accumulated AFUDC(6) associated with the capital
expenditures for the Comanche Project that are at or below the Construction
Cost Cap.
14.
By
agreeing to the recovery of Comanche 3 construction costs that are at or below
the Construction Cost Cap determined in accord with Highly Confidential
Attachment C, Parties to this Comprehensive Settlement Agreement do not waive
the right to challenge the recovery of replacement power costs that result from
material delays in the commercial operation date of Comanche 3 due to
imprudence.
15.
The
Company shall file progress reports with the Commission semi-annually,
beginning June 1, 2005 and ending with the first report after Comanche 3
reaches commercial operation, regarding the progress of construction and the
expected commercial operation date of Comanche 3. The progress reports shall
contain the status of each vendor contract (including updated information on
contracts under negotiation) and a narrative which summarizes bids received and
the selection process employed for each vendor contract. The progress reports shall also set forth the
force majeure clauses in each vendor contract and in any subcontract let by
Utility
(6) The accumulated AFUDC
must be set forth in the Company’s books and records in a Comanche Project
sub-account in accord with FERC Uniform System of Accounts.
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Engineering
Corporation or by Public Service. The progress reports shall provide the
account balances for all Comanche Project expenditures(7). The progress reports also shall include
budgeted versus actual status with respect to the milestone payment schedule,
differences in status between the projected and actual overall construction schedule and
the status of on-going permit applications.
Any material departure from the milestone payment schedule or the
construction schedule will be accompanied by a narrative explaining the
departure. Continuing property records shall be timely maintained and available
for inspection. Finally, the progress
reports shall list any material design or scope change orders. Public Service
reserves the right to file bid and financial information under seal and to seek
highly confidential protection for this information.
2003
Least-Cost Resource Plan and 2005 A
ll-Source Solicitation
16.
The
Parties agree that the Company should use a planning reserve margin of 16%(8)
for the 2003 LCP(9).
17.
For
purposes of the 2003 LCP, Public Service agrees not to apply a balance sheet
equalization factor or other imputed debt adjustment mechanism to the bids
received.
(7)
The Comanche Project expenditures shall be
set forth in the Company’s books and records in Comanche Project sub-accounts
in accord with FERC Uniform System of Accounts.
(8)
The 16% is applied to the Company’s “base”
demand forecast (i.e. normal weather).
(9) When the term “2003 LCP”
is used in covenants set forth in this Comprehensive Settlement Agreement, the
Parties intend that the term shall include the Company’s 2003 LCP as approved
by the Commission in this docket, all resource solicitations that are conducted
under the Company’s approved 2003 LCP, the implementation of any contingency
plan that may be required under the 2003 LCP, and any amendments to the 2003
LCP that the Company may file.
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18.
As
required by section 12 of the CECP Settlement and in consideration of the
potential incurrence of future costs due to greenhouse gas regulation (e.g.,
carbon dioxide taxes or allowance costs) during the 30 year Planning Period of
the 2003 LCP, the Parties agree that all evaluations of resources acquired
under the 2003 LCP should include
imputation of CO
2
costs of $9/ton beginning in 2010 and escalating
at 2.5% per year beginning in 2011 and continuing over the planning life of the
resource. The imputed cost of CO
2
shall be included in both the initial economic screening and in the dynamic
portfolio optimization steps of the bid evaluation processes. In evaluating
bids during the initial economic screening, Public Service shall reflect the
costs associated with the CO
2
proxy cost as a dollar per MWh
variable operating cost. In the dynamic portfolio optimization modeling, the CO
2
proxy cost shall be applied to all existing and new resources as a $/MWh
variable operating cost affecting resource dispatch. For any CO
2
emitting resource, the variable $/MWh CO
2
cost of a resource shall
be calculated using the formula set forth in Section 12(C) of the CECP
Settlement, which is hereby incorporated by reference.
19.
In
accord with section 15(E) of the CECP Settlement and in recognition of the
potential future value of renewable energy credits (“RECs”) provided to Public
Service, particularly after the passage of 2004 Colorado Ballot Initiative
Amendment 37, the Company shall include a REC value of $8.75/MWh for all
renewable resources bid into solicitations under the 2003 LCP, with the
exception of the Renewable Energy RFP issued August 17, 2004. To qualify
for the REC value, the renewable energy bid must meet the definition of “Eligible
Renewable Energy Resource” under Amendment 37, as that definition may be
updated by the Colorado Legislature by the time the bids are due
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in response to
the 2005 All-Source RFP or by the time the bids are due in response to any
other solicitation conducted under the 2003 LCP. The REC value shall be included in both the
initial economic screening and in the dynamic portfolio optimization steps of
the bid evaluation process. Public
Service shall apply the REC value to renewable resource bids for all operating
years of the renewable energy project from 2006 onward. The Renewable Energy Credit will not escalate
in value over the Planning Period used in the 2003 LCP.
20.
As
required by CECP Settlement sections 15(A) and 15(B), Public Service shall
accelerate and complete those components of the wind ancillary service cost
study required by the Commission in Docket No. 04A-325E that are necessary to
obtain projections of ancillary service costs for nameplate wind penetration
levels of 15% of Public Service’s system peak demand. For purposes of the study, the 15% wind
penetration level shall be based on Public Service’s 2007 peak demand forecast
or Public Service’s best available peak demand forecast for 2007 at the
commencement of the study. These
necessary components of the study shall be completed in time to evaluate wind
resource bids submitted in response to the 2005 All Source RFP. Public Service
shall accept wind bids in response to solicitations under the 2003 LCP up to a
15% penetration level, so long as the wind bids are part of Public Service’s
least cost resource portfolio. In the 2003 LCP, due to concerns over potential
operational impacts, the Company will not be required to select resources that
would result in a greater than 15% penetration level of intermittent resources
on the Public Service system. For this
purpose, the 15% wind penetration level shall be based on Public Service’s peak
demand forecast used to determine resource need and acquisition at the time of
the bid
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evaluations
and shall be calculated based on the year in which the wind resource would be
projected to come on-line. Nothing in this paragraph shall alter the $2.50/MWh
ancillary service costs to be ascribed to intermittent resources that are bid
in response to the Company’s Renewable Energy RFP issued on August 17,
2004; the ancillary service costs ascribed to the Renewable Energy RFP bids
shall be governed by the Commission’s orders in Docket No. 04A-325E.
21.
Public
Service shall use a capacity value of wind generation resources equal to 10% of
nameplate capacity for existing wind generation and in evaluating the wind bids
submitted in response to solicitations conducted under the 2003 LCP.
22.
Public
Service shall remove from the Model Power Purchase Agreement provided with the
2005 All-Source RFPs and other solicitations under the 2003 LCP an opportunity
for bidders to sell up to ten megawatts of Excess Capacity to Public Service
beyond the level of capacity specified in the bid.
23.
The
Parties agree that, when assessing supplier concentration and parent company
financial strength of bidders in the 2003 LCP, the evaluation will focus on an
assessment of the bidder’s ability to perform the obligations of the project
under a potential purchase power agreement.
Additional
Resource Planning Studies
24.
Public
Service, Staff and OCC shall jointly work to develop a study scope and study
methodology, and to identify appropriate study model(s), to perform a
probabilistic assessment of the appropriate reserve margin for the Public
Service system that includes consideration of the following:
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a.
Resources
acquired in the Renewable Energy RFP, the 2005 All-Source RFP, plus Comanche 3;
b.
Weather
related load variability; and
c.
Planned
and unplanned generation and transmission outages.
Public Service
shall use its best efforts to collect information from all electric systems
within the TOT-constrained area of Eastern Colorado and to obtain
commercially-available Loss of Load Probability (LOLP) models that have the
capability to properly represent both 1) the transmission limitations of the
TOT-constrained area and 2) the reliability support that the different electric
systems provide to each other. If Public
Service is able to obtain the data and software necessary to conduct this
study, Public Service shall study the full TOT-constrained area of Eastern
Colorado. If Public Service, Staff and OCC reach consensus on the study scope,
methodology, and appropriate computer models, then Public Service, Staff and
OCC shall rely on the study results to develop their individual recommendations
for the reserve margin in Pubic Service’s next resource plan. If Public Service, Staff and OCC are unable
to reach consensus on the study scope, methodology, or appropriate computer
models that would produce a meaningful study of the TOT-constrained area of
Eastern Colorado, within the limitations of available data and modeling
software, all Parties are free to advocate any position in the next Public
Service resource plan.
25.
In
accord with section 15(D) of the CECP Settlement, Public Service shall
perform an Effective Load Carrying Capability study on its system as a means
for determining the capacity value of wind generation resources. The study
shall consider the uncertainty or variability of hourly wind generation
patterns from year-to-year and
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the combined
effects of diverse wind farm locations. Public Service shall file the study
with the Commission and provide copies to the Parties by November 1,
2006. Public Service agrees to advocate
in future Commission proceedings that the reliability contribution or capacity
value of wind generation resources should be based upon a method that
incorporates consideration of reliability contribution in all hours of the year
and to propose recommendations for ascribing capacity value to existing and new
wind generation resources. Public
Service shall solicit participation of industry experts, Staff, OCC and other
interested parties with Public Service personnel on a technical review
committee with the intent of incorporating their specific interest and
knowledge base into the study. If Public
Service claims the information in such report is confidential, any member of
the technical review committee or any organization listed in Section 1 to
the CECP Settlement shall be allowed to review such information after signing a
reasonable confidentiality agreement that ensures that commercially sensitive
or trade secret information is protected. Members of the technical review
committee shall be afforded access to confidential information of entities other
than Public Service only upon the execution of non-disclosure agreements
acceptable to the owner of the Confidential Information. The Parties to this Comprehensive Settlement
Agreement, other than Public Service, reserve their rights to advocate for a
different method for determining wind capacity value.
26.
In
accord with section 15(C) of the CECP Settlement, if Public Service
selects cost-effective wind generation resources in response to the Renewable
Energy RFP and All-Source Solicitations of the 2003 LCP that increase nameplate
wind generation on its system above 720 MW, Public Service agrees to perform an
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additional
ancillary service cost study to obtain projections of ancillary service costs
at a 20% penetration level. This 20%
wind penetration study shall be used to inform resource solicitations
subsequent to the solicitations conducted under the 2003 LCP.
27.
Public
Service agrees to conduct and present with its CPCN application for the transmission
facilities required by Comanche 3 the following two studies. Public Service will evaluate the specific 230
kV alternative for the Comanche 3 transmission system outlined by Mr. Dominguez
in his Answer Testimony in this consolidated docket. Further, as requested by Staff witness Mr.
Dominguez, Public Service will evaluate methods to reduce transmission noise
levels to 50 db(A) for the 345 kV double
circuit Comanche-Midway-Daniels Park facility proposed in Volume 4 of the
Company’s LCP. By agreeing to conduct these studies, Public Service is not
agreeing that these alternatives will be the transmission facilities that
Public Service proposes to construct or for which Public Service requests a
CPCN. The Parties reserve their rights
to comment upon Mr. Dominguez’s alternatives to protect their respective
interests.
28.
Under
the Stipulation Between the Staff of the Colorado Public Utilities Commission
and Public Service Company of Colorado with Respect to Wind Studies, as
modified by the Commission in Docket No. 04A-325E by Decision No. C04-0994 (August 24,
2004), Public Service is obligated to perform power flow and stability
analyses, using 2007 power flow cases, of the portfolio of resources selected
by the Company in response to the Renewable Energy RFP. Public Service shall invite neighboring
transmission owners, through the auspices of the Colorado Coordinated Planning
Group, to participate in these studies.
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29.
In
order to increase public information about wind generation facility operations,
Public Service agrees to request permission from wind energy sellers to
publicly disclose historic production data on a 2-minute interval basis. To the degree that such permission is
obtained, Public Service agrees to make such information available upon
request. Such information will be
provided on a historic basis only.
Demand-Side
Management
30.
In
order to achieve energy efficiency to provide a hedge against volatile gas
prices and against uncertain future emission regulation, in order to reduce
total system costs, and in accord with section 14 of the CECP Settlement,
Public Service shall use its best efforts to acquire, on average, 40 MW of
demand reduction and 100 GWh of energy savings per year from cost-effective
Demand-Side Management (“DSM”) programs over the period beginning January 1,
2006 and ending December 31, 2013, so that by January 1, 2014 the
Company will have achieved a cumulative level of 320 MW of total demand
reduction and 800 GWh of annual energy savings.
Notwithstanding the foregoing, Public Service’s actual annual demand
reductions and energy savings during this period may vary from these annual
averages. The Company shall expend $196 million (2005 dollars) to meet such
demand reductions and energy savings unless these demand reductions and energy
savings are achieved with a lower level of expenditures. The DSM demand reductions and energy savings
required by this paragraph shall include the demand reductions and energy savings
achieved by Public Service through bidding under the 2003 LCP. The Company shall strive to develop and
implement a set of DSM programs that give all classes of customers an
opportunity to participate. As part of
this effort, the Company will attempt to develop for
19
residential
and commercial customers some programs that concentrate on reduction in peak
demand and some programs that concentrate on reduction of energy usage. All DSM
programs implemented under this Comprehensive Settlement Agreement, outside of
bidding under the 2003 LCP, shall be required to pass the Total Resource Cost
test. All DSM programs selected in the
2005 All-Source Evaluation will be part of the portfolio that minimizes the net
present value of rate impacts.
31.
The
Company shall perform a market study to determine, generally, levels of
efficiency available for various customer classes and the costs associated with
such measures, and whether such levels of DSM are cost-effective and available
in Colorado. Public Service agrees to involve other stakeholders in the design
of the market study and the review of the contractor summary results. The market study shall not exceed $2 million
in cost. Public Service shall complete the market study as expeditiously as
practicable, but no later than March 31, 2006.
32.
Public
Service further commits to conduct program-specific market and load research
and ongoing measurement and verification for each DSM measure as appropriate,
ranging from random audits to project-based reviews for the more customized
measures. Public Service will conduct an impact and process evaluation that
assesses the amount of energy and demand savings from each program and
evaluates the functional efficiency and customer satisfaction with each
program. Public Service will spend up to
an additional $2 million on these evaluation efforts. The $4 million spent on
the market study and the evaluation efforts shall be included in the $196
million cap and shall be recoverable through the Demand Side Management Cost
Adjustment (“DSMCA”) clause.
20
33.
Public
Service shall be entitled to continue to fully recover its expenses and
investment associated with existing DSM programs under the Company’s 1999
Integrated Resource Plan under the terms and conditions of the Company’s
current DSMCA, which include a five year amortization period for DSM
investment.
34.
For
the DSM programs contemplated by this Comprehensive Settlement Agreement,
Public Service shall be entitled to fully recover its expenses and investment
associated with these new programs under the terms and conditions of the
Company’s current DSMCA, except that the Company’s investment in DSM measures
shall be amortized over an 8 year period instead of a 5 year period. All DSM
investments associated with contracts signed after December 31, 2005 shall
be considered to be investments subject to the 8 year amortization period.
Further, the Company shall be entitled to make an out-of-period adjustment in
its 2006 rate case filing to capture the annualized effect of incremental
increases in internal labor, benefits and other employee-related costs
associated with implementing this expanded DSM program through 2006. The Company
shall include no more than 18 full-time-equivalent employees in this
out-of-period adjustment. These incremental labor and employee-related costs
shall be included in the $196 million cap discussed in prior paragraphs.
35.
Within
three months of completing the market study described in paragraph 31 above,
but no later than July 1, 2006, the Company shall file an application with
the Commission to open a docket to address the provision of DSM by Public
Service above and beyond the levels provided by existing programs and by this
21
Comprehensive
Settlement Agreement(10). The Company
acknowledges that in the DSM docket initiated pursuant to this paragraph, the
Commission may examine for future DSM programs beyond the levels set forth in
this Comprehensive Settlement Agreement, among other issues, 1) whether the
Company’s expenses should be recovered through a rider and 2) the appropriate
amortization period for recovery of DSM investment.
36.
Public
Service shall file with the Commission with its annual DSMCA filing a report on
the DSM expenditures, energy savings, and peak demand reduction achieved by the
programs for the past year. Public
Service shall also file with the Commission with its annual DSMCA filing the
results of the impact and process evaluations(11) that were conducted in the
past year.
37.
Public
Service shall establish and maintain a DSM working group that shall meet at
least twice a year. The DSM working group shall be open to all interested
persons and shall provide input to Public Service in DSM program design,
analysis and other issues relevant to helping the Company meet or exceed the
minimum energy savings and peak demand reduction levels. Public Service shall provide to the members
of the DSM working group copies of all DSM filings it makes with the
Commission.
(10)
The Company has agreed in section 14(D)
of the CECP Settlement to advocate in the subsequent Commission DSM
proceedings, among other things, for use of the Total Resource Cost test and
for financial incentives for Company acquisition of DSM. The Parties to this Comprehensive Settlement
Agreement who are not signatories to the CECP Settlement are not bound by these
terms of the CECP Settlement and fully reserve their rights to advocate for
their interests in the subsequent DSM docket.
(11)
Public Service shall conduct impact and
process evaluations at the conclusion of each program.
22
38.
The
Parties do not agree among themselves as to whether the Commission must grant
the Company a waiver from the Commission’s Least-Cost Resource Planning Rules
to accomplish the DSM commitments set forth in this Comprehensive Settlement
Agreement. The Parties are not asking
the Commission for a specific ruling on whether a waiver is required. However, to the extent that a waiver is
required, the Parties agree that the public interest would be served by the
Commission granting such a waiver.
Impact of Settlement on Public Service’s
2003 LCP
39.
Public
Service represents that it has modeled the economic impact of the provisions of
this Comprehensive Settlement Agreement on the Company’s screening analyses
presented in the Company’s filed 2003 Least-Cost Resource Plan, with a variety
of updated modeling assumptions including the use of the price for natural gas
used in the Renewable Energy RFP bid evaluation(12). Public Service’s report discussing the
assumptions used for each model run and the results of these model runs is
attached as Attachment D. Public Service
represents that the model runs show the impact of this Comprehensive Settlement
Agreement, referred to as the “Settlement Case” in comparison to both the case
proposed in the Company’s October 18, 2004 rebuttal testimony and to
updated generic screening analyses(13). In general, Public Service represents that
these runs demonstrate the following aspects of the Settlement Case:
(12)
The gas price used in the Renewable Energy
RFP bid evaluation is based upon on combination of four different long-term gas
price forecasts: CERA, PIRA, EIA, and
NYMEX.
(13)
A description of the updates made to the
Company’s screening analyses is set forth in Attachment D.
23
a.
Even
with the additional environmental controls, the inclusion of higher CO
2
proxy costs, and increased DSM
required by this Comprehensive Settlement Agreement, Comanche 3 is still chosen
as part of the Least- Cost Resource Plan.
b.
An
additional coal resource could be selected in the 2005 All-Source RFP
Evaluation as part of the Least-Cost Resource Plan.
c.
Additional
gas-fired resources could be selected in the 2005 All-Source RFP Evaluation as
part of the Least-Cost Resource Plan.
d.
Additional
wind resources priced without the benefit of the federal production tax credit
could be selected in the 2005 All-Source RFP Evaluation as part of the
Least-Cost Resource Plan.
e.
The
Comprehensive Settlement Agreement, including DSM, produces a net present value
reduction of revenue requirements of approximately $90 million compared to the
Company’s October 18, 2004 rebuttal case and between $500 million to $1.3
billion compared to the revised generic screening analyses. The Comprehensive Settlement Agreement,
including DSM, results in a slight increase in the net present value of average
rate impacts of approximately $0.05/MWh ($0.00005/kWh) compared to the Company’s
rebuttal case and a reduction in the net present value of average rate impacts
of between $.58/MWh and $2.14/MWh compared to the revised generic screening
analyses.
New
LCP Rules
40.
Concerns
were expressed by many Parties to this docket about various provisions in the
Commission’s Least-Cost Planning Rules.
The Parties agree that Public Service shall file a petition no later
than September 1, 2005 requesting the
24
Commission to
open a rulemaking docket to reexamine the LCP rules. Among other things, the
petition shall request that the rulemaking proceeding should examine the
following topics: 1) the competitive solicitation processes that should be used
to acquire various types of resources; 2) how a utility rate-based generation
facility can be fairly evaluated and compared against purchased power options;
3) the effects of purchased power contracts on utility balance sheets and
income statements and how those effects can reasonably be addressed; 4) how
cost impacts and cost recovery can be integrated into the resource planning and
acquisition cycle; 5) whether the net present value of revenue requirements
instead of net present value of rate impacts should be the test employed to
select the least cost resource portfolio; 6) how future environmental
regulatory risks should be taken into account; 7) the adequacy of the current
public participation process, and 8) the appropriate cost-effectiveness test
for DSM. Public Service shall not ask
the Commission to reopen Rules 3602 and 3605
dealing with the applicability of the Commission’s LCP Rules to
cooperative electric associations and cooperative generation and transmission
associations(14)
Regulatory
Plan
41.
The
Company acknowledges that the Intervenors’ willingness to resolve the cost
recovery issues as set forth below is based upon the particular factual
circumstances that have been presented in this consolidated docket. The Parties
agree that the following compromises and agreements with respect to the
Regulatory Plan shall have no precedential effect or significance, except as
may be necessary to enforce
(14)
Other Parties reserve their rights to seek to
expand the scope of the LCP Rulemaking.
25
this
Comprehensive Settlement Agreement or Commission Order approving this
agreement.
42.
The
Company agrees to withdraw its request for the Least Cost Plan Adjustment
Rider.
43.
Public
Service agrees that it shall not file an electric Phase 1 rate case prior to January 1,
2006.
44.
The
Parties recognize the Company’s need to begin increasing its equity ratio, as
calculated for financial reporting purposes, to 56% to offset the debt
equivalent value of existing purchased power agreements and to improve the
Company’s overall financial strength.
The Parties agree that, for purposes of the 2006 Phase 1 rate case, the
actual regulatory capital structure(15), including pro forma adjustments but
excluding short-term debt, as of the earlier of the date on which a settlement
of the 2006 Phase 1 rate case is executed or the first day of evidentiary
hearings, shall be deemed reasonable and shall be used to determine the Company’s
2006 Phase 1 rate case revenue requirement.
The Parties understand that, depending upon the level of short-term debt
on the Company’s balance sheet as of the date the regulatory capital structure
is determined, the equity ratio could exceed 56%. Public Service stipulates that, for purposes
of the 2006 Phase 1 rate case, its proposed regulatory capital structure shall
not exceed 60% equity. Public Service
reserves the right to seek higher levels of equity in its regulatory capital
structure in Phase I rate proceedings subsequent to the 2006 rate case. The Parties reserve their rights to take a
position that reflects their respective interests at such time.
(15)
In calculating its actual regulatory capital
structure, Public Service shall use its most recently available month-end
financial statement as the starting point.
26
45. The Parties agree
that in any one or more Phase 1 rate proceedings that the Company may file
between January 1, 2006 and the later of January 1, 2011 or five and
one-half years after the Company secures an administratively final air permit
for Comanche 3(16), provided that the Company’s actual capital structure used
for regulatory purposes equals or exceeds 56 percent equity, the Company shall
be entitled to the following treatment of Construction Work in Progress
associated with the construction of Comanche 3, the installation of
environmental controls on Comanche 1, 2, and 3, and related transmission
investment (“Comanche CWIP”):
a.
If
on the earlier of the date on which a settlement of the Phase 1 rate case is
executed or the first day of evidentiary hearings, the Company’s senior
unsecured debt rating from either Standard & Poor’s or Moody’s is below A-
or its Moody’s equivalent, the Company shall be permitted to include Comanche
CWIP in ratebase without an AFUDC offset, calculated as of the end of the
applicable test year(17); and
b.
If
on the earlier of the date on which a settlement of the Phase 1 rate case is
executed or the first day of evidentiary hearings, the Company’s senior
unsecured debt rating from either Standard & Poor’s or Moody’s is below
BBB+ or its Moody’s equivalent, the Company shall be permitted to make an
out-of-period adjustment to include Comanche CWIP in rate base without an AFUDC
offset, accrued during the
(16) If construction at Comanche 3 is halted due
to a legal challenge to the air permit filed after issuance or other force
majeure event, the five and one half year period referenced in this Paragraph
shall be extended day for day for so long as the construction is halted.
(17)
Based upon Public Service’s current
estimates, for illustrative purposes only, the annual revenue requirement
impact of including the Comanche CWIP balance as of year-end 2005 in rate base
without an AFDUC offset would be $ 4,747,150. This amount would be included in
the revenue requirement used to establish rates that would take effect on January 1,
2007, assuming Public Service files an electric rate case in Spring 2006.
27
period ending
twelve months following the end of the test year upon which the Phase 1 filing
is based(18). The Parties acknowledge
that the Company’s Phase 1 filing will include the Company’s best estimate of
the Comanche CWIP balance as of the end of the twelve month period following
the end of the applicable test year, which estimate may be revised from time to
time up until 30 days prior to the first day of scheduled evidentiary hearings
in the Phase 1 rate case(19).
c.
If
Public Service’s actual capital structure used for regulatory purposes does not
equal or exceed 56%, or if Public Service’s senior unsecured debt rating from
both Standard & Poor’s and Moody’s is at or above A- or its Moody’s
equivalent, then the Parties reserve their rights to take a position with
respect to Comanche CWIP that reflects their respective interests at such
time. If the Company’s senior unsecured
debt rating from both Standard & Poor’s and Moody’s is BBB+ or its Moody’s
equivalent, then the Parties reserve their rights to take a position with
respect to the Comanche CWIP pro forma adjustment discussed in Paragraph b that
reflects their respective interests at such time.
46.
Public
Service reserves the right to seek additional regulatory relief associated with
the construction of the Comanche Project or the impact of purchased power at
any time, except that the Company agrees that it shall not seek a rider
specific
(18)
Based upon Public Service’s current
estimates, for illustrative purposes only, the annual revenue requirement
impact of including the Comanche CWIP balance as of year-end 2006 in rate base
without an AFDUC offset would be $ 29,513,628.
This amount would be included in the revenue requirement used to
establish rates that would take effect on January 1, 2007, assuming Public
Service files an electric rate case in Spring 2006.
(19)
Any revised Comanche CWIP estimate shall be
filed with the Commission and served on all parties with accompanying work
papers with an attestation by an officer of the Company and the Company’s
contractors, including Utility Engineering Corporation.
28
to recovery of
the financing costs of Comanche 3 and the Company shall not file an electric
Phase 1 rate case prior to January 1, 2006. The Parties reserve their
rights to take a position that reflects their respective interests with regard
to such additional regulatory relief requests.
GENERAL
TERMS AND CONDITIONS
This Comprehensive Settlement Agreement reflects compromise and
settlement of all issues raised or that could have been raised in this
consolidated docket. The Parties agree
that Public Service’s last stated position regarding its proposed 2003 Least
Cost Resource Plan, whether presented by Public Service in the pre-filed Least
Cost Plan volumes, its pre-filed direct, pre-filed supplemental direct,
pre-filed rebuttal testimonies, or oral statements at the evidentiary hearing,
should be approved by the Commission, subject to the provisions of this
Comprehensive Settlement Agreement(20).
All Parties agree to support this Comprehensive Settlement
Agreement. The Parties agree to join a motion
that requests the Commission to approve this Comprehensive Settlement Agreement
and to agree to all provisions of this Comprehensive Settlement Agreement that
are binding upon the Parties of this agreement.
Unless otherwise specifically indicated, the provisions of this
Comprehensive Settlement Agreement shall apply only to the Company’s 2003 LCP. Unless otherwise specifically indicated, the
provisions of this Comprehensive Settlement Agreement do not apply to any other
Commission docket affecting Public Service or any other utility.
(20)
The Intervenors’ agreement in this regard
should not be assumed to imply that the Intervenors necessarily support these
positions or necessarily agree that such positions should be adopted in the
future.
29
This Comprehensive Settlement Agreement is a negotiated compromise of
issues and is broadly supported by Parties who include Public Service,
independent energy providers, retail customers, other utilities, and public
interest and environmental organizations. Nothing contained herein shall be
deemed to constitute an admission or an acceptance by any party of any fact,
principle, or position contained herein.
Notwithstanding the foregoing, the Parties, by signing this
Comprehensive Settlement Agreement and by joining the motion to approve this
Comprehensive Settlement Agreement, acknowledge that they pledge support for
Commission approval and subsequent implementation of these provisions.
This Comprehensive Settlement Agreement is to be treated as a complete
package, not as a collection of separate agreements on discrete issues or
proceedings. To accommodate the
interests of different parties on diverse issues, the Parties acknowledge that
changes, concessions, or compromises by a party or parties in one section of
this Comprehensive Settlement Agreement necessitated changes, concessions, or
compromises by other parties in other sections.
The Parties hereby agree that all pre-filed testimony and exhibits that
have not already been admitted into evidence in this docket shall be admitted
into evidence without cross-examination.
This Comprehensive Settlement Agreement shall not become effective
until the issuance of a final Commission Order approving the Comprehensive
Settlement Agreement, which Order does not contain any modification of the
terms and conditions of this Comprehensive Settlement Agreement that is
unacceptable to any of the Parties and which does not result in the termination
of the CECP Settlement. In the event the
30
Commission
modifies this Comprehensive Settlement Agreement in a manner unacceptable to
any Party, that Party shall have the right to withdraw from this agreement and
proceed to hearing on the issues that may be appropriately raised by that Party
in this docket. The withdrawing Party shall notify the Commission and the
Parties to this Comprehensive Settlement Agreement by e-mail within three
business days of the Commission-ordered modification that the Party is
withdrawing from the Comprehensive Settlement Agreement and that the Party is
ready to proceed to hearing; the e-mail notice shall designate the precise
issue or issues on which the Party desires to proceed to hearing (the “Hearing
Notice”).
The withdrawal of a Party shall not automatically terminate this
Comprehensive Settlement Agreement as to the withdrawing Party or any other
Party. However, within three business
days of the date of the Hearing Notice from the first withdrawing Party, all
Parties shall confer to arrive at a comprehensive list of issues that shall
proceed to hearing and a list of issues that remain settled as a result of the
first Party’s withdrawal from this Comprehensive Settlement Agreement. Within five business days of the date of the
Hearing Notice, the Parties shall file with the Commission a formal notice
containing the list of issues that shall proceed to hearing and the list of
issues that remain settled. The Parties
who proceed to hearing shall have and be entitled to exercise all rights with
respect to the issues that are heard that they would have had in the absence of
this Comprehensive Settlement Agreement.
Hearing shall be scheduled on all of the issues designated in the formal
notice filed with the Commission as soon as practicable.
31
Due to the importance of the CECP Settlement to the timely
implementation of the 2003 LCP, Public Service has agreed in the CECP
Settlement that if the Commission order in this docket would result in the
termination of the CECP Settlement, Public Service, and certain other Parties,
shall jointly apply for rehearing, reargument and reconsideration of the
Commission decision(21). If Public
Service applies for rehearing to comply with the CECP Settlement, the Parties
agree that rehearing of the Commission decision and the hearing process
contemplated in this Comprehensive Settlement Agreement by the withdrawal of a
party, shall simultaneously go forward on parallel tracks so that the issues in
this docket may be resolved at the earliest practicable time. The Parties agree that, if the Commission
order on the Comprehensive Settlement Agreement could result in the termination
of the CECP Settlement, Public Service immediately will request that the
Commission stay the finality of the order pending resolution of the rehearing
requests on this issue.
In the event that this Comprehensive Settlement Agreement is not
approved, or is approved with conditions that are unacceptable to any Party who
subsequently withdraws, the negotiations or discussions undertaken in
conjunction with the agreement shall not be admissible into evidence in this or
any other proceeding, except as may be necessary in any proceeding to enforce this
Comprehensive Settlement Agreement.
Approval by the Commission of this Comprehensive Settlement Agreement
shall constitute a determination that the agreement represents a just,
equitable and
(21) Pursuant to Section 17(A) of the CECP
Settlement, Public Service and the Parties that are signatories to the CECP
Settlement have agreed to jointly request ARRR and, if necessary, a second ARRR
of any Commission order that would result in the termination of the CECP
Settlement.
32
reasonable
resolution of all issues that were or could have been contested among the
Parties in this proceeding. The Parties
state that reaching agreement in this docket by means of a negotiated
settlement is in the public interest and that the results of the compromises
and settlements reflected by this Comprehensive Settlement Agreement are just,
reasonable and in the public interest.
All Parties to this Comprehensive Settlement Agreement have had the
opportunity to participate in the drafting of this agreement. There shall be no legal presumption that any
specific Party was the drafter of this agreement.
This agreement may be executed in counterparts, all of which when taken
together shall constitute the entire agreement with respect to the issues
addressed by this agreement.
Dated this 3rd day of December, 2004.
33
Attachment A
Settlement
Agreement
This Settlement Agreement is executed this 3rd day of December, 2004,
by and
between Public
Service Company of Colorado and the Concerned Environmental and Community
Parties, as defined below.
Recitals
A.
Public Service Company of Colorado has
proposed to construct a new 750 MW coal-fired unit at the Comanche Station
located near Pueblo, Colorado.
B.
Concerned Environmental and Community Parties
object to the environmental impacts associated with Comanche 3 and Public
Service Company of Colorado’s proposed 2003 Least-Cost Resource Plan filed with
the Colorado Public Utilities Commission (“CPUC”).
C.
This Settlement Agreement is intended to
address Concerned Environmental and Community Parties’ objections regarding the
pre-construction air permit for the new unit at Comanche 3 and the 2003 Least-Cost
Resource Plan.
Agreement
1.
Parties.
A.
Public Service Company of Colorado (“PSCo”)
is a Colorado public utility and a wholly owned subsidiary of Xcel Energy Inc.,
a public utility holding company. PSCo does business in Colorado as “Xcel
Energy.”
B.
Concerned Environmental and Community Parties
(“CECP”) consists of the following organizations and their Affiliated
Organizations:
a.
Western Resource Advocates;
b.
Sierra Club;
c.
Environmental Defense;
d.
Environment Colorado;
e.
Better Pueblo;
f.
Diocese of Pueblo;
g.
Southwest Energy Efficiency Project;
h.
Colorado Renewable Energy Society; and
i.
Smart Growth Advocates.
C.
The term “Affiliated Organizations” means any
organization under common management and control with any of the CECP parties
or any successor to any CECP party.
1
D.
The term “PSCo” means Public Service Company
of Colorado or any of its successors or assigns.
2.
Definitions.
A.
“Comanche 3” shall be defined to mean a new
coal-fired steam electric generating unit with a net summer dependable capacity
of 750 MW, and a maximum gross heat input rate of approximately 7421 million
Btu per hour as set forth in the preconstruction air permit application, and to
be located at the existing Comanche Station near Pueblo, Colorado. PSCo shall
amend the Clean Air Act Title V operating permit for Comanche Station to
reflect the rated heat input of Comanche 3 in the same manner as the rated heat
input is reflected for Comanche 1 & 2.
B.
“Comanche 1” and “Comanche 2” shall be
defined to mean the existing coal-fired steam electric generating units located
at the Comanche Station near Pueblo, Colorado. PSCo owns and operates Comanche
1 and Comanche 2.
C.
“2003 LCP” shall be defined to mean PSCo’s
2003 proposed Least-Cost Resource Plan and to include any contingency plans for
the 2003 Least-Cost Resource Plan pursuant to Rule 3614(b)(II) of the Colorado
Electric Least-Cost Resource Planning Rules or any amendments to the 2003
Least-Cost Resource Plan pursuant to Rule 3615 of the Colorado Electric
Least-Cost Resource Planning Rules.
D.
“All-Source Solicitation” shall be defined to
mean the All-Source solicitations under the 2003 LCP.
3.
Emission limits for sulfur dioxide emissions.
A.
PSCo shall amend its pre-construction permit
application for Comanche 3 to propose one or more emission limits for sulfur
dioxide (“SO
2
”) that are equivalent to Best Available
Control Technology (“BACT”) as defined in the Clean Air Act at 42 U.S.C. § 7479(3).
PSCo shall design, install and operate a lime spray dryer sulfur dioxide
removal system at Comanche 3 consistent with all SO
2
emission limits determined by the Colorado Department of Public Health
and Environment (“Department”) to be equivalent to BACT in accordance with the
federal Clean Air Act at 42 U.S.C. § 7479(3). In no event shall the mass
emission SO
2
limit determined by the Department to be
equivalent to BACT for Comanche 3 be less stringent than 0.1lb./mmbtu heat
input on a 30-day rolling average basis including emissions from shutdown and
malfunction events. PSCo shall not seek an exemption for emissions during
startup, shutdown or malfunction except for emissions during cold startups but
such exemption shall be for no more than two hours after coal is first fed to
the boiler.
2
B.
PSCo shall comply with the emission limits
set forth and contemplated by Section 3.A within 60 days after achieving
the maximum production rate at which Comanche 3 will be operated, but no later
than 180 days after initial startup.
C.
PSCo shall install lime spray dryer SO
2
removal systems at Comanche 1 and 2 and meet a mass emissions SO
2
limit of 0.12 lb/mmbtu heat input on each unit as determined on a
30-day rolling average basis including emissions from shutdown and malfunction
events. PSCo shall not seek an exemption for emissions during startup, shutdown
or malfunction except for emissions during cold startups but such exemption
shall be for no more than two hours after coal is first fed to the boiler. In addition,
PSCo agrees that the combined average SO
2
emissions from
both Comanche 1 and 2 taken together shall not exceed a 0.1 lb/mmbtu heat input
emission limit on an annual rolling average basis (rolling on a daily basis)
including emissions during startup, shutdown and malfunction events.
D.
Within 60 days of the effective date of this
Settlement Agreement, PSCo shall incorporate the emission limits set forth in
this Section for Comanche 1, 2, and 3 into the pre-construction permit
application filed for Comanche 3.
4.
Emission limits for oxides of nitrogen.
A.
PSCo shall amend its pre-construction permit
application for Comanche 3 to propose one or more emission limits for oxides of
nitrogen (“NO
x
”) that are equivalent to BACT as defined in the Clean
Air Act at 42 U.S.C. § 7479(3). PSCo shall design, install and operate a
selective catalytic reduction system for NO
x
removal at Comanche 3
consistent with all NO
x
emission limits determined by the Department
to be equivalent to BACT in accordance with the federal Clean Air Act at 42
U.S.C. § 7479(3). In no event shall the NO
x
emission limit
determined by the Department to be equivalent to BACT for Comanche 3 be less
stringent than 0.08 lb/mmbtu heat input on a 30-day rolling average basis,
including shutdown and malfunction events. PSCo shall not seek an exemption for
emissions during startup, shutdown or malfunction except for emissions during
cold startups but such exemption shall be for no more than two hours when
natural gas-fired igniters are in use, and for no more than four hours after
coal is first fed to the boiler.
B.
PSCo shall comply with the emission limits
set forth and contemplated by Section 4.A within 60 days after achieving
maximum production rate at which Comanche 3 will be operated, but no later than
180 days after initial startup.
C.
PSCo shall install advanced low-NO
x
emission control or reduction technologies on the existing Comanche 1 and 2
units and meet a NO
x
3
emission limit of 0.2 lb/mmbtu heat input at each unit as determined on
a 30-day rolling average basis, including shutdown and malfunction events. In
addition, PSCo agrees that the combined average NO
x
emissions from both Comanche 1 and 2 taken together shall not exceed a
0.15 lb/mmbtu heat input limit on an annual rolling average basis (rolling on a
daily basis), including shutdown and malfunction events. With respect to these
limits, PSCo shall not seek an exemption for emissions during start up,
shutdown or malfunction except for emissions during cold startups but such
exemption shall be for no more than two hours when natural gas-fired igniters
are in use, and for no more than four hours after coal is first fed to the
boiler.
D.
Within 60 days of the effective date of this
Settlement Agreement, PSCo shall
incorporate the emission limits set forth in this section for Comanche 1,
2 and 3 into the pre-construction permit application filed for Comanche 3.
5.
Limits for particulate matter.
A.
PSCo has submitted a pre-construction permit
application for Comanche 3 that proposes emission limits for particulate matter
(“PM”) that PSCo represents is BACT as defined in the Clean Air Act at 42
U.S.C. § 7479(3). PSCo shall design, install and operate a fabric filter
dust collection system for PM removal at Comanche 3 consistent with all PM
emission limits determined by the Department to be BACT in accordance with the
federal Clean Air Act at 42 U.S.C. §§ 7475(a)(4) and 7479(3). In no event
shall the PM limits determined by the Department to be BACT for Comanche 3 be
less stringent than those set forth below, and within 60 days of this
Settlement Agreement PSCo shall amend its pre-construction permit application
to incorporate such limits to the extent they are not currently in such application:
a.
Filterable PM
10
emissions shall be no greater than 0.0130 lb/mmbtu heat input;
b.
Total PM
10
emissions (including
condensibles) shall be subject to enforceable emission limitations as
determined by the Department;
c.
Opacity shall be no more than 10 percent on a
6-minute average, excluding excess emissions during periods of startup,
shutdown and malfunction if properly documented and reported consistent with 40
C.F.R. 60.7(c) and any other applicable requirements.
The emission limits set forth in this Section shall become
enforceable under this Settlement Agreement in accordance with the terms of the
final Comanche 3 preconstruction permit.
4
6.
Installation and compliance schedule.
PSCo shall design and install all SO
2
and NO
x
control equipment required to comply with the
emissions limitations for Comanche 1 and 2 described in, and contemplated by,
Sections 3 and 4 so that such control equipment is operational by December 31,
2008. PSCo shall meet the unit-specific emission limits for Comanche 1 and 2 no
later than 180 days after initial startup of the SO
2
and NO
x
control equipment for each unit, or by July 1,
2009, whichever is earlier. PSCo shall begin calculating compliance with the SO
2
and NO
x
combined annual rolling average emission limits
(rolling on a daily basis) for Comanche 1 and 2 no later than 180 days after
initial startup of the SO
2
and NO
x
control equipment for
the last unit. PSCo shall incorporate the installation and compliance schedule for
Comanche 1 and 2 set forth in this Section into the pre-construction
permit application filed for Comanche 3.
Compliance with the SO
2
, NO
x
, and opacity limits
set forth in, or contemplated by, this Settlement Agreement shall be determined
at the Comanche Station by continuous SO
2
, NO
x
, and opacity monitors, and any other monitors or
systems required by the Department or the U.S. Environmental Protection Agency
(“EPA”), and PSCo shall install and operate all such monitoring systems in
conformance with all applicable Department and EPA requirements and performance
specifications.
7.
Monitoring, testing and emission limits for
mercury.
A.
PSCo shall comply with any applicable mercury
emission limitations and requirements at Comanche 1, 2, and 3, including the
requirement for case-by-case maximum achievable control technology emission
limitations under the Clean Air Act at 42 U.S.C. § 7412(g)(2) for Comanche
3. PSCo shall also amend its permit application for Comanche 3 to request a
mercury emission limit at Comanche 3 that is at least as stringent as the 20x10
-
6
lb/MWh mercury
emission limit as proposed by EPA at 69 Fed. Reg. 4652 (January 30, 2004)
for new coal-fired steam electric generating units burning sub-bituminous coal.
B.
Within one year after the date that the
Comanche 3 pre-construction air permit is issued by the Department, PSCo shall
install, properly maintain and operate a continuous mercury emissions
monitoring system on Comanche 1 and 2 using Q-SEMS technology as described at
69 Fed. Reg. at 4694 (January 30, 2004), or such other technology as the
Parties may agree. PSCo shall monitor mercury emissions from Comanche 1 and 2
beginning 18 months after the issuance of the Comanche 3 air permit and shall
report the quality assured and quality controlled data to CECP and the
Department on a calendar quarterly basis thereafter.
5
C.
PSCo shall operate and maintain the mercury
monitoring technology in accordance with EPA requirements and the manufacturer’s
specifications. In the event of any mercury monitoring technology malfunction,
PSCo shall either repair or replace such monitoring technology. If the mercury
monitoring technology identified in Section 7.B is unable to meet
applicable performance requirements, despite PSCo’s efforts to repair and
replace such technology, PSCo agrees to install alternate mercury monitoring
technology unless technologically or economically infeasible or to conduct
annual stack testing if monitoring technology is technologically or
economically infeasible.
D.
Within 60 days after achieving the maximum
production rate at which Comanche 3 will be operated, but in no event later
than 180 days after initial startup of Comanche 3, PSCo shall install equipment
necessary to use sorbent injection technology to control mercury at Comanche 3.
On or before the SO
2
and NO
x
controls installation
deadline for Comanche 1 and 2 as provided in Section 6, PSCo shall install
equipment necessary to use sorbent injection technology to control mercury at
Comanche 1 and 2.
E.
Within 60 days after achieving the maximum
production rate at which Comanche 3 will be operated, but no later than 180
days after initial startup, PSCo shall test for a period of one year different
mercury emission control methods or technologies on Comanche 1 and 2. Such
methods or technologies shall be selected by PSCo in its sole discretion after
consultation with CECP and may include methods or technologies other than
sorbent injection. PSCo shall provide CECP with a report detailing the results
of the tests, the conclusions arising from the tests and the bases for such
conclusions. The report required under this paragraph shall be provided to CECP
within 18 months after the commencement of the testing required by this
paragraph. If PSCo claims information in the report contains trade secrets, any
organization listed in Section 1 shall nevertheless be allowed to review
such information after signing a reasonable confidentiality agreement that
ensures that such trade secrets are protected.
F.
No later than two years after the initial
startup of Comanche 3, PSCo shall comply with a plant-wide mercury emission
limit for the Comanche Station that maximizes cost-effective (as defined below)
mercury reductions on a plant-wide basis. To implement this paragraph, PSCo
shall propose a plant-wide emission limit to the Department in accordance with
this paragraph after consultation with CECP. Unless otherwise agreed by the
Parties, PSCo shall comply with an emission limit under this paragraph that
represents the maximum cost-effective reduction of mercury at Comanche Station,
achievable through the expenditure of no less than $2 million per year and no
more than $5 million per year in the first year’s operations and maintenance
costs directly associated with mercury controls, excluding mercury monitoring
costs and the operations and maintenance control costs
6
for SO
2
, NO
x
, PM or any other pollutant
regardless of whether such controls reduce mercury emissions but including the
mercury control costs necessary to comply with the applicable mercury emission
limitations set forth in Paragraph 7.A. If PSCo proposes to set an emission
limit that will cost less than $5 million per year in the first year operations
and maintenance costs to maximize the reduction of mercury, PSCo shall bear the
burden of demonstrating to the Department that a more stringent emission
limitation than that proposed by PSCo is not cost-effective based on a dollar
per pound of mercury removed.
PSCo shall seek from the Department a determination under this
paragraph that is reviewable by the Colorado Air Quality Control Commission in
a proceeding in which CECP may be a party. The Parties recognize that the Department
shall have the responsibility to set the emission limit in accordance with its
procedures. PSCo agrees that CECP shall have full rights and discretion under
law to participate in the Department’s proceeding and in any subsequent review
by the Colorado Air Quality Control Commission commenced in accordance with
this paragraph.
G.
Within 60 days after the effective date of
this Settlement Agreement, PSCo shall amend its preconstruction air permit
application for Comanche 3 to incorporate the requirements of Section 7.A
that are applicable to Comanche 3 and to incorporate the requirement to install
and operate the Q-SEMS technology under this Section.
8.
Other air permit issues.
A.
This Settlement Agreement is not a permit.
Furthermore, PSCo shall comply with all applicable present and future federal,
state and local laws, regulations and permitting requirements regardless of
whether they are set forth in this Settlement Agreement. To the extent any
conflict arises between any requirement in this Settlement Agreement and any
other applicable present or future requirement described above, the most
stringent requirement shall apply.
B.
Notwithstanding any other provision of this
Settlement Agreement, PSCo retains ownership of and all rights associated with
any and all credits or emission allowances allocated to it under any law, rule,
regulation, policy, or contract, whether such law, rule, regulation, policy or
contract is currently in effect or becomes effective in the future.
C.
In addition to other purposes, PSCo is
installing the emission controls on Comanche 1 and 2 pursuant to this
Settlement Agreement for the purpose of netting out of Prevention of
Significant Deterioration (“PSD”) review for SO
2
and NO
x
for Comanche 3; as such controls are necessary and appropriate to ensure timely
permitting of Comanche 3. PSCo agrees that such emission
7
reductions necessary for netting shall become federally enforcable in
the pre-construction permit and, pursuant to Section 16.F, the Clean Air
Act Title V operating permit. All other emission reductions required by this
Settlement Agreement shall become federally enforceable as otherwise provided
under the Agreement.
D.
In addition to the other emission limits, acid
gas emissions (including sulfuric acid mist, hydrogen fluoride and hydrogen
chloride) shall be subject to enforceable emissions limitations as determined
by the Department.
E.
Provided that PSCo’s pre-construction air
permit application, and the final permit, are consistent with Sections 3-8 of
this Settlement Agreement, CECP agrees that it shall not submit any adverse
formal comments or testimony on the permit application or proposed or final
permit to the Department or EPA during the pre-construction permit review
proceeding for Comanche 3 unless any provision in such permits is materially
inconsistent with, or materially diminishes the stringency of, any requirement
in this Settlement Agreement. Notwithstanding the above, if PSCo appeals any
Comanche 3 permit term, CECP shall be allowed to intervene and participate as a
party in the appeal proceeding regarding such term.
F.
The Parties agree that they shall provide the
Department with a copy of this Settlement Agreement as part of the
pre-construction air quality permit proceeding for Comanche 3.
G.
PSCo shall include in its pre-construction
air permit application for Comanche 3 and the air permit for Comanche 1 and 2 a
request for a condition that, at all times, including periods of startup,
shutdown, and malfunction, PSCo shall, to the extent practicable, maintain and
operate any emission control equipment required under this Settlement Agreement
in a manner consistent with good air pollution control practice for minimizing
emissions. Determination of whether acceptable operating and maintenance
procedures are being used will be based on information available to the
Department which may include, but is not limited to, monitoring results,
observations, review of operating and maintenance procedures, and inspection of
the source.
9.
Additional environmental mitigation.
To mitigate the potential impacts to the Pueblo area of emissions from
Comanche 3:
A.
Within 3 months after issuance of the
preconstruction air permit for Comanche 3, PSCo shall contribute $50,000 to the
Department for implementation of a program to reduce mercury contamination in
shredded car bodies provided to the Rocky Mountain Steel plant in Pueblo. PSCo
8
shall make an additional contribution of $50,000 to the Department for
the same program within one year after its initial contribution.
B.
Within 6 months after the issuance of the
Comanche 3 air permit, PSCo shall
contribute a total of $250,000 to Pueblo School Districts No. 60 and 70 to
reduce air pollution from existing diesel school buses in the Pueblo area,
provided that the school districts agree to accept the donation, maintain the
funds in a separate account, and expend the funds to achieve the maximum
reduction of air pollution from existing diesel school buses at the least cost.
School bus emissions may be reduced through any one or more of the following:
retrofitting existing buses with EPA verified pollution control devices such as
particulate filters and diesel oxidation catalysts, replacing existing buses
with new buses that are consistent with EPA’s Clean School Bus USA program, and
using ultra-low sulfur diesel fuel or other cleaner fuels.
10.
Sustainable development in the Pueblo region.
A.
PSCo and CECP shall jointly sponsor, in
cooperation with other appropriate stakeholders, a series of public forums
addressing sustainable development in the Pueblo area. The parties shall invite
other stakeholders from the Pueblo community (including, but not limited to,
the Pueblo Economic Development Corporation, Better Pueblo, industry,
government and citizens of Pueblo and surrounding areas) to participate in the
public forums.
B.
The sustainable development forums shall
consider and examine the following issues generally applicable to the Pueblo
community:
a.
Long-term economic development;
b.
Energy and technology issues;
c.
Environmental concerns;
d.
Environmental justice;
e.
Public safety;
f.
Water and water rights; and
g.
Other issues that the forums may identify.
C.
In conjunction with these forums, PSCo shall
participate in the Pueblo Sustainable Development Program.
9
D.
PSCo and CECP shall make best efforts to
begin these forums within three months and shall begin these forums no later
than four months after execution of this Settlement Agreement. Both parties are
jointly responsible for the logistics and arrangement of these meetings. PSCo
recognizes that CECP shall not have any financial responsibility under this
Section. The Parties shall make best efforts to include other stakeholders in
the process by the date of commencement of the forums.
E.
Among other things, the forums created
hereunder shall:
a.
consider the preparation of a study to
identify appropriate analytical tools to help the community evaluate the impact
of economic development proposals; and
b.
identify opportunities to seek funding from
third party charitable foundations or other sources for technical assistance on
sustainable development issues. PSCo shall provide reasonable assistance,
appropriate involvement and support in seeking such funding.
F.
PSCo’s obligations under this Section shall
cease upon termination of the Settlement Agreement unless otherwise agreed to
by the Parties.
11.
Emissions data.
A.
Beginning within one year after the date that
the Comanche 3 pre-construction air permit is issued by the Department, PSCo
shall make available on the Xcel Energy website electronic links to the
emissions reports and emissions data related to the Comanche plant that are
submitted to EPA and the Department. Such reports and data shall be made
available only after they have been subject to quality assurance and quality
control measures.
B.
PSCo shall use its best efforts to make the
emissions data described in this Section available on the Xcel Energy
website within 30 days after submission to EPA
C.
PSCo shall provide each organization listed
under Section 1 an opportunity to review and comment on the format of the
emissions data posted on its website under this Section.
12.
Carbon Dioxide Proxy Cost.
A.
PSCo shall include a carbon dioxide (“CO
2
”) proxy cost in its
analysis and evaluation of the cost of resource bids submitted in response to
the All-Source Solicitation. PSCo shall issue the Request for Proposals (“RFP”)
for the All-Source Solicitation consistent with this Section.
10
B.
The CO
2
proxy cost shall:
a.
be set at $9 per ton
1
of CO
2
;
b.
be first applied to resources beginning in
the year 2010 in the bid evaluation process; and
c.
escalate at a rate of 2.5% per year starting
in 2011 and continuing over the planning life of the resource.
C.
The CO
2
proxy cost shall be
included in both the initial economic screening and in the dynamic portfolio
optimization steps of the bid evaluation process. In evaluating bids during the
initial economic screening, PSCo shall reflect the costs associated with the CO
2
proxy cost as a $/MWh variable operating cost. In evaluating the bids dynamically,
PSCo shall model the costs associated with the CO
2
proxy cost as a
$/MWh variable operating cost affecting resource dispatch. In the dynamic
portfolio optimization modeling, the CO
2
proxy cost shall be applied
to both existing and new resources. For any CO
2
emitting resource,
the variable $/MWh CO
2
cost of a resource shall be calculated using
the following formula:
CO
2
cost
t
= [E
t
*HR
t
*C
t
]/(2*10
6
)
where:
E
t
= CO
2
emission rate
of the resource in lb/mmbtu heat input at
time t;
HR
t
= heat rate of the resource in btu/kWh at time t; and
C
t
= CO
2
proxy cost in $/ton at time t.
13.
Innovative technologies.
A.
PSCo and CECP shall work jointly on
innovative technologies, practices and measures to examine cost-effective
programs and strategies to reduce greenhouse gas emissions, including but not
limited to the innovative technology program described herein. The programs and
strategies may also include terrestrial or geological carbon sequestration and
small-scale and community-owned renewable energy projects.
B.
PSCo shall work with CECP to seek passage of
legislation in the 2005 legislative session of the Colorado General Assembly to
create the framework for an innovative technology program in the state of
Colorado. The innovative technology program shall promote the use of innovative
technologies on a demonstration scale to generate or conserve electricity for
Colorado electricity consumers. The program shall promote the use of
technologies designed to allow more efficient production or consumption of electricity
with fewer emissions of greenhouse gases on a plant or system-
11
wide basis. The program shall ensure that utilities implementing a
demonstration project under its terms shall have the right to full and timely
recovery of all costs associated with any subject demonstration project.
C.
If the Colorado General Assembly enacts
innovative technology program legislation consistent with Section 13.B in
the 2005 legislative session, PSCo shall, within 12 months after the date that
the Comanche 3 pre-construction air permit is issued by the Department, propose
an innovative technology demonstration project under the terms of that program.
Such innovative technology demonstration project shall be selected by PSCo in
its sole discretion after consultation with CECP. In proposing the project
under this paragraph, PSCo may consider technologies that include, but are not
limited to, compressed air storage/wind combination, renewably generated
hydrogen for fuel cells, or integrated gasification combined cycle power plants
fueled with western coal.
D.
The Parties shall consider siting the
innovative technology measures, practices or demonstration project in the
Pueblo area.
E.
The goal of the innovative technology demonstration
project under this Section shall be to reduce in a cost-effective manner
CO
2
emissions by a cumulative total of 1.67 million tons as measured
over the years 2006-2013. Progress toward the cumulative 1.67 million ton
reduction goal shall be measured through expansion or production cost model
projections associated with the innovative technology demonstration project.
PSCo shall make its best efforts to achieve this goal. The Parties recognize
that the performance of innovative technology demonstration projects is
uncertain, and cost or technology performance problems may prevent achievement
of the goal.
F.
Notwithstanding the foregoing, PSCo shall not
be required to achieve the CO
2
mitigation goal set forth above or
implement the innovative technology practices, measures or demonstration
project above unless it receives adequate assurance of timely cost recovery and
all required approvals for the practices, measures or projects.
G.
The Parties agree to work in good faith to
obtain additional funding for the innovative technology demonstration project
from the United States Department of Energy and obtain authority to implement
the project and recover its costs from the Colorado General Assembly and the
Public Utilities Commission, as appropriate.
14.
Energy Efficiency.
A.
PSCo shall use its best efforts to acquire,
on average, 40 MW of demand reduction and 100 GWh of energy savings per year
over the period
12
beginning January 1, 2006 and ending December 31, 2013, so
that by January 1, 2014, the company will have achieved 320 MW of total
demand reduction and 800 GWh of annual energy savings. Notwithstanding the
foregoing sentence, PSCo’s actual annual demand reductions and energy savings
during this period may vary from these averages. PSCo shall expend $196 million
(in 2005 dollars) to meet such demand reduction and energy savings unless these
demand reduction and energy savings are achieved with a lower level of
expenditure. The demand-side management (“DSM”) levels set forth in this Section shall
include the demand reduction and energy savings achieved by PSCo through the
All-Source Solicitation. All DSM programs implemented outside of the All-Source
solicitation shall be required to pass the Total Resource Cost test. PSCo shall
strive to implement a set of DSM programs that give all classes of customers an
opportunity to participate.
B.
PSCo shall conduct a market study to
determine, generally, levels of efficiency available for various customer
classes and the costs associated with such measures, and whether such levels of
DSM are cost-effective and prudent in Colorado. In addition, PSCo shall conduct
program-specific market and load research, and ongoing DSM program measurement
and evaluation. The cost of the market study and these other research and
evaluation activities is included in the total amount of DSM expenditures in Section 14.A
but shall not exceed $4 million. PSCo agrees to involve other stakeholders in
the design of the market study and the review of the contractor summary
results. PSCo shall complete the study as expeditiously as practicable, but no
later than March 31, 2006.
C.
PSCo shall be entitled to fully recover its
expenses and investments associated with the acquisition of the DSM programs
under Section 14.A and the cost of the market study and other activities
described in Section 14.B through PSCo’s Demand-Side Management Cost
Adjustment Clause or other mechanisms.
D.
Within three months of completing the market
study described in Section 14.B but no later than July 1, 2006, PSCo
shall request that the CPUC open a docket to consider issues related to DSM,
including the appropriate test used to judge the cost effectiveness of DSM
projects, the viability of additional DSM in Colorado’s economy, best DSM
practices and other issues related to increased investment in energy efficiency
measures by PSCo. In this docket, the Parties shall advocate a DSM policy that
(1) uses the Total Resource Cost test to determine the cost-effectiveness of
DSM programs; (2) provides for recovery of all costs of approved DSM programs,
including, but not limited to, administrative, internal and external labor, and
promotion costs; and (3) creates an incentive mechanism that promotes PSCo’s
investments in additional energy efficiency beyond the levels set forth in Section 14.A.
The incentive program described in this paragraph
13
may include compensation to PSCo for its loss of energy sales as a
result of the DSM program.
E.
PSCo shall report to the CPUC and other
parties on DSM expenditures, energy savings, and peak demand reductions
achieved by the programs each year.
F.
PSCo shall establish and maintain a DSM
working group that shall meet at least twice a year. The DSM working group
shall be open to all interested parties and shall provide input to PSCo in DSM
program design, analysis and other issues relevant to helping PSCo meet or
exceed the minimum energy savings and peak demand reduction levels.
15.
Renewable energy.
A.
PSCo shall accelerate and complete those
components of the wind ancillary service cost study
2
that are
necessary to obtain projections of ancillary service costs for nameplate wind
capacity penetration levels of 15% of PSCo’s system peak demand. These
necessary components of the study shall be completed in time to evaluate wind
resource bids submitted in the All-Source Solicitation. For purposes of the
study, the 15% wind penetration level shall be based on PSCo’s 2007 peak demand
forecast or the Company’s best available peak demand forecast for 2007 at the
commencement of the study. The study shall include consideration of the
operational flexibility of its Cabin Creek pumped-storage generation facility.
PSCo has solicited participation of stakeholders on a technical review
committee with the intent of incorporating their specific interest and
knowledge base into the study. The invitation was sent to industry experts,
intervenors, PUC staff and PSCo personnel. PSCo shall produce a report
detailing the results of the study. If PSCo claims information in the report is
confidential, any member of the technical review committee or any organization
listed in Section 1 shall nevertheless be allowed to review such
information after signing a reasonable confidentiality agreement that ensures
that commercially sensitive or trade secret information is protected.
B.
As previously ordered by the CPUC in the 2003
LCP Renewable Energy RFP docket, PSCo shall use an ancillary service cost of
$2.50/MWh (escalating at the same rate as gas prices) for wind bids up to 500
MW that are acquired in the renewable energy RFP. PSCo shall use the results of
the study in Section 15.A to evaluate all wind bids in the All-Source
Solicitation.
C.
PSCo shall accept wind bids up to a 15%
penetration level, so long as the wind bids are part of PSCo’s Least Cost
Resource Portfolio. For this purpose, the 15% wind penetration level shall be
based on PSCo’s peak demand forecast used to determine resource need and acquisition
at the
14
time of the bid evaluations and shall be calculated based on the year
in which the wind resource would be projected to come on-line. If PSCo selects
wind generation resources in response to the Renewable Energy RFP and
All-Source Solicitation that increase nameplate wind generation on its system
above 720 MW, PSCo agrees to undertake an additional wind ancillary service
cost study to obtain projections of ancillary service costs at a 20% penetration
level. This additional 20% wind penetration study shall be used to inform
subsequent resource solicitations. PSCo shall not be required to “hold” bids
for further evaluation pending the outcome of the 20% wind penetration study,
but nothing in this Settlement Agreement prevents PSCo from doing so.
D.
PSCo shall use a capacity value of wind
generation resources equal to 10% of nameplate capacity in evaluating bids submitted
in response to the All-Source Solicitation. PSCo shall perform a study of effective
load carrying capability on its system as a means of determining the capacity
value of wind generation resources. The study shall include consideration of
the uncertainty or variability of hourly wind generation patterns from year to
year and the combined effects of diverse wind farm locations. PSCo agrees to
(1) file, by November 1, 2006, the study results with the CPUC; (2)
advocate that the reliability contribution or capacity value of wind generation
resources should be based on a method that incorporates consideration of
reliability contribution in all hours in the year; and (3) include
recommendations for ascribing capacity value to existing and new wind
generation resources. PSCo shall solicit participation of industry experts,
intervenors, CPUC Staff and PSCo personnel on a technical review committee with
the intent of incorporating their specific interest and knowledge base into the
study. PSCo shall produce a report detailing the results of the study. If PSCo
claims the information in such report is confidential, any member of the
technical review committee or any organization listed in Section 1 shall
nevertheless be allowed to review such information after signing a reasonable
confidentiality agreement that ensures that commercially sensitive or trade
secret information is protected.
E.
PSCo shall include a renewable energy credit
(“REC”) value of $8.75/MWh in its analysis and evaluation of the cost of
renewable resource bids submitted in response to the All-Source Solicitation.
To qualify for the REC value in the bid evaluation, a renewable energy bid must
meet the definition of “Eligible Renewable Energy Resource” under the 2004
Colorado Ballot Initiative Amendment 37 as may be updated by the Colorado
Legislature by the time that bids are due in the All-Source Solicitation. The
REC value shall be included in both the initial economic screening and in the
dynamic portfolio optimization steps of the bid evaluation process. PSCo shall
apply the REC value to renewable resource bids in the All-Source Solicitation,
for all operating years of the renewable energy project beginning in 2006. CECP
acknowledges that nothing in this provision shall prohibit PSCo from
15
negotiating with individual bidders exceptions to the Model
Nondispatchable Power Purchase Agreement allowing such bidders to retain some
or all the RECs associated with a renewable energy bid, but such bids shall not
include the $8.75 REC value in the bid evaluations in the All-Source
Solicitation for any RECs so retained.
16.
Commitments of the Parties.
A.
As long as PSCo remains in material
compliance with this Settlement Agreement, the CECP organizations agree not to
make any adverse formal comments before the Department or EPA or to bring a
lawsuit asserting that any projects or construction undertaken at Comanche
Station prior to the effective date of this Settlement Agreement in any way
violated the requirements of section 165(a) of the federal Clean Air Act,
42 U.S.C. § 7475(a), or the
related requirements of the federally enforceable applicable implementation
plan. The CECP organizations also agree not to initiate, fund or participate in
any such comments or lawsuit by any other entity. If for any reason PSCo does
not materially comply with this Settlement Agreement, or otherwise does not
satisfy its obligations, or if the Department does not issue a proposed or
final Clean Air Act pre-construction permit and/or Clean Air Act Title V
operating permit that is consistent with the terms of this Settlement Agreement
in all material respects, the CECP organizations are released from their
agreement not to comment or sue described above in this paragraph. PSCo agrees
that in any ensuing proceeding PSCo shall not use or count the period of time
in which CECP’s agreement not to challenge or sue was in effect as support for
any otherwise available defense of statute of limitations, laches, delay or
other defense based on failure to timely comment on or prosecute any such
violations of the federal Clean Air Act or the federally enforceable applicable
implementation plan.
B.
The Parties agree that this Settlement
Agreement is a fair and reasonable resolution of the issues related to the
construction and operation of Comanche 3 as addressed in this Settlement
Agreement. Subject to Section 8.A, the reservation of rights in Section 17.J,
and the dispute resolution and repudiation provisions in Sections 17.F, and
17.G, the CECP organizations agree they shall not initiate, fund or participate
in any formal administrative or legal action to oppose or knowingly impede any
of the following administrative or regulatory approvals necessary for PSCo to
construct or operate Comanche 3 in accordance with this Settlement Agreement:
a.
The issuance of a certificate of public
convenience and necessity (“CPCN”) for Comanche 3 in the 2003 LCP proceeding;
16
b.
The granting of PSCo’s application to waive
Rule 3610(b) of the CPUC Least Cost Planning Rules for Comanche 3 in the 2003
LCP proceeding; and
c.
The issuance of the pre-construction air
permit by the Department or the authorized permitting authority required for
the construction of Comanche 3 and the Clean Air Act Title V operating permit
for the Comanche Station necessary to implement this Settlement Agreement.
Notwithstanding the above, the CECP organizations reserve their right to
comment on and challenge any provision in such permits that is materially
inconsistent with, or materially diminishes the stringency of any requirement
in, this Settlement Agreement.
C.
CECP agrees that if any of the CECP
organizations initiate, fund or participate in any administrative or legal
action to oppose or knowingly impede the permitting or approval of any
activities necessary to complete the construction and initial startup of
Comanche 3, including associated facilities such as the CPCN and right-of-way
for the transmission, PSCo may take action to terminate this Settlement
Agreement in accordance with the pre-enforcement and repudiation procedures in Section 17.
Before taking any such action, any CECP organization may notify PSCo of any
grievance it has with respect to any proposed permit or approval and PSCo shall
meet with the CECP organization and use its best efforts to resolve timely such
grievance. Upon termination under this paragraph, PSCo shall be relieved of any
obligations under this Settlement Agreement, including any obligation to
install emission controls under Sections 3-7, except as provided below. CECP’s
obligations under Sections 16.A and B shall survive termination under this
paragraph. If PSCo’s rights under this paragraph have been triggered after the
pre-construction air permit for Comanche 3 is final and effective, PSCo’s
obligation to achieve and maintain compliance with the NO
x
and SO
2
emission limits in this Settlement Agreement applicable to Comanche 1 and 2
shall survive termination.
D.
In addition to the foregoing, the
organizations listed under Section 1 that are Parties to the 2003 LCP/CPCN
proceeding before the PUC agree not to oppose the regulatory plan submitted by
PSCo in conjunction with the 2003 LCP/CPCN proceeding as such plan may be
modified by PSCo so long as such regulatory plan is not inconsistent with and
does not interfere with the requirements of this Settlement Agreement, and to
support PSCo’s recovery of the costs of all environmental components of this
Settlement Agreement, including, but not limited to, the costs of any emission
control equipment for the Comanche Station required hereunder. The
organizations listed under Section 1 that are Parties to the 2003 LCP/CPCN
shall not be bound to intervene in any future proceedings before the CPUC. The
provisions of this paragraph do not apply to any CECP organization that is not
a party to the PUC’s 2003 LCP/CPCN proceeding.
17
E.
Through a process established by mutual
agreement of the parties, PSCo shall consult with CECP at least quarterly after
execution of the Settlement Agreement to discuss the material issues associated
with the implementation of the Settlement Agreement and other issues identified
by mutual agreement. PSCo shall use best efforts to provide information as set forth
in this paragraph, and its failure to provide information pursuant to this paragraph
shall not be considered a breach of this Settlement Agreement. PSCo’s
obligation under this paragraph shall cease upon termination of the Settlement
Agreement unless otherwise agreed by the Parties.
F.
No later than 60 days after the last date for
achieving the emission limits in this Settlement Agreement for Comanche
Station, except for the mercury emission limit, PSCo shall file with the
Department a proposed amendment to the Comanche Station Clean Air Act Title V
operating permit to incorporate into the Title V permit such emission limits
and all related applicable requirements set forth in this Settlement Agreement.
If, however, the Comanche Station Title V permit will expire within 24 months
of the last date described above, PSCo may advance or delay filing the
application to amend the Title V permit until PSCo files its application to
renew the Title V permit. PSCo agrees to include in any Title V permit for
Comanche Station requirements no less stringent than those set forth in, or
contemplated by, Sections 3-9 of this Settlement Agreement, which obligation
shall survive termination of this Settlement Agreement under Section 20.
17.
Enforceability and Reservation of Rights.
A.
PSCo shall seek CPUC approval for the
commitments in sections 3, 4, 5, 6, 7, 8, 12, 14, and 15 of this Settlement
Agreement as part of the Commission order on the 2003 LCP. If CPUC action on
such commitments is not approved and ordered in full, if a CPUC order
significantly impedes implementation of any commitments under this Settlement
Agreement, or if the CPUC order approving such commitments is reversed on
judicial appeal in any significant respect, the Parties’ obligations under this
Settlement Agreement are terminated. If the Commission order on the 2003 LCP
does not approve such commitments or if the Commission order on the 2003 LCP
significantly impedes implementation of any commitments under this Settlement
Agreement, PSCo and any party to the 2003 LCP proceeding listed under Section 1
that wish to seek rehearing, reargument or reconsideration agree to jointly
request rehearing, reargument or reconsideration of the Commission order and,
if necessary, request second rehearing, reargument or reconsideration. If PSCo
reaches agreement with other parties to the 2003 LCP proceeding that
significantly impedes implementation of any commitment under this Settlement
Agreement, the Parties’ obligations under this Settlement Agreement are
terminated. PSCo agrees that if this Settlement Agreement is terminated under
the provisions
18
of this paragraph, PSCo shall not use or count the period of time in
which CECP’s agreement not to challenge or sue under Section 16.A was in
effect as support for any otherwise available defense of statute of
limitations, laches, delay or other defense based on failure to timely
prosecute any such violations of the federal Clean Air Act or the federally
enforceable applicable implementation plan.
B.
Each organization listed under Section 1
shall have the full rights under the law afforded persons or corporations to
enforce CPUC orders including the rights and powers under C.R.S. 40-7-101, et
seq.
C.
If PSCo fails to make amendments to its
preconstruction air quality permit application for Comanche 3 or to propose
emission limitations for Comanche 1 and 2 as required by this Settlement
Agreement, or if either the Department’s final federally enforceable Clean Air
Act preconstruction permit or the Clean Air Act Title V operating permit for
the Comanche Station is not materially consistent with the terms of this
Settlement Agreement, or upon expiration of the pre-construction air permit for
Comanche 3 before construction commenced, all of the Parties’ obligations under
this Settlement Agreement are terminated including but not limited to CECP’s
agreement not to comment, challenge or sue for alleged violations of the Clean
Air Act under Section 16.A. In the event of termination under this paragraph,
PSCo shall not oppose CECP’s rights to challenge any pre-construction air
quality or Clean Air Act Title V operating permit related to Comanche 3 or the Comanche
Station solely as a result of CECP’s failure to participate in the pre-construction
air permitting administrative process.
D.
CECP’s Remedies for Breach. In consideration
of PSCo’s commitments under this Settlement Agreement, CECP and its Affiliated
Organizations have agreed to forebear the exercise of specific procedural and
substantive rights as set forth in Section 16 of the Settlement Agreement.
In the event PSCo fails to perform any material obligation or commitment under Sections
3-11 of this Settlement Agreement, each organization listed under Section 1
or any Affiliated Organization shall, after exhausting the pre-enforcement
procedures of Section 17.F, have the full discretion and rights to seek
judicial or administrative relief to compel performance of such obligations
pursuant to the terms hereof. PSCo
hereby stipulates to subject matter jurisdiction under Colorado law, and to any
such organization’s standing to enforce specific performance of Sections 3-11
of this Settlement Agreement. In the
event PSCo fails to perform any material commitments under Sections 3-11 of the
Settlement Agreement, each of the organizations listed under Section 1
shall also have the option of exercising any rights that CECP has agreed to
forego if this Settlement Agreement is fully performed.
E.
PSCo’s Remedies for Breach. In the event
there is an alleged breach of Section 16 of the Settlement Agreement,
PSCo, after exhausting the pre-
19
enforcement and repudiation procedures of Section 17.F and 17.G,
may bring suit against the particular organization listed under Section 1
that is alleged to be in violation. To the extent any alleged breach results in
PSCo incurring additional costs or delay in the permitting or construction
anticipated under this Settlement Agreement, PSCo may seek injunctive relief against
the allegedly breaching organization. As provided in Section 17.I, each
organization listed under Section 1 is a distinct and separate entity and
the actions of one organization listed under Section 1 shall not be
imputed to another. If injunctive relief for breach of this Settlement
Agreement is granted against any of the organizations listed under Section 1
or a reviewing court declares any organization listed under Section 1 is
in breach of this Settlement Agreement, PSCo shall not be obligated to undertake
any action required under this Settlement Agreement including but not limited
to the installation of emission control equipment on Comanche 1 and 2, provided
that PSCo has complied with the material requirements under this Settlement
Agreement prior to the alleged breach by the CECP organization.
F.
Pre-enforcement Procedures. Before pursuing
judicial relief to compel performance of obligations set forth in this
Settlement Agreement, or before exercising any right to terminate this
Settlement Agreement, CECP and PSCo shall first invoke the following notice and
alternate dispute resolution procedures:
a.
Notice. The affected Party shall provide
written notice of alleged material breach to all parties to this Settlement
Agreement. Such notice shall include a reasonable description of the facts and circumstances
surrounding the alleged material breach, the term(s) of the Settlement
Agreement at issue, and the measure(s) sought to correct any breach.
b.
Informal Dispute Resolution. Within five
business days of receipt of notice of alleged breach, the Parties shall meet
and confer in person or by conference call at a mutually convenient time and
place in an effort to resolve the alleged breach. Discussions to resolve the dispute
among the parties shall continue for no less than 15 business days from the
time notice of alleged breach is received and the affected party shall not
institute or pursue an action in either state or federal court during this
period. The bar against instituting or pursuing judicial enforcement of the
obligations in this Settlement Agreement may be extended by mutual agreement of
the Parties beyond the minimum period required for notice and informal dispute resolution.
c.
Notice of Intent to Sue. Should the Parties
be unable to resolve their disagreements within 15 business days from the time
notice of
20
alleged breach is received or the mutually agreed enlarged time for
informal dispute resolution, the affected Party shall have the right, upon
providing five business days notice of intention to seek judicial relief to all
Parties, to seek judicial enforcement of the terms of this Settlement
Agreement.
d.
The requirements in this Section shall
survive after termination of this Settlement Agreement to the extent any party
seeks to enforce any obligation that survives after termination.
G.
Repudiation by CECP. If any organization
listed under Section 1 or any Affiliated
Organization allegedly acts in breach of the commitments made in this
Settlement Agreement, the organization listed under Section 1 or
Affiliated Organization whose name has been invoked may repudiate such action
either by letter (or other means mutually acceptable to the organization or
Affiliated Organization and PSCo) within 15 business days of being informed of
the alleged breach by PSCo pursuant to Section 17.E. Such letter or other
mutually acceptable means shall constitute full and complete performance of the
duties of any such organization or Affiliated Organization arising from the
Settlement Agreement, and PSCo shall have no right to terminate or otherwise
avoid its obligations under this Settlement Agreement. This provision shall
survive termination of this Settlement Agreement.
H.
The Parties agree that in no instance shall
any Party or individual be responsible
or liable for monetary damages, attorneys fees and/or costs incurred as a
result of any alleged breach or breach of this Settlement Agreement. The
parties acknowledge and agree that damages are not available as a remedy in the
event the obligations of this Settlement Agreement are breached. The parties
agree that damages would not be an adequate remedy for noncompliance with this
Settlement Agreement, and that no adequate remedy at law exists for noncompliance
with the terms of this Settlement Agreement. Accordingly, the parties expressly
acknowledge that an award of equitable relief would be an appropriate remedy
for a breach of the obligations under this Settlement Agreement, provided the
reviewing court has followed standard procedures in issuing injunctive relief.
I.
This Settlement Agreement does not create any
legal relationship between or among the organizations listed in Section 1.
Western Resource Advocates, Sierra Club, Environmental Defense, Environment
Colorado, Better Pueblo, Diocese of Pueblo, Southwest Energy Efficiency
Project, Colorado Renewable Energy Society, and Smart Growth Advocates are each
separate and distinct organizations, and the actions of one organization shall
not be imputed to another. The use of the term “Concerned Environmental and
Community Parties” or “CECP” in this Settlement Agreement is intended merely
for convenience and does not in
21
any manner imply that one organization shall be held accountable or
liable for the actions of another. Thus, each party is responsible only for its
own actions and this Settlement Agreement is not intended to and does not in
any manner create rights, duties, liabilities or legal consequences for the
individual and separate entities Western Resource Advocates, Sierra Club,
Environmental Defense, Environment Colorado, Better Pueblo, Diocese of Pueblo,
Southwest Energy Efficiency Project, Colorado Renewable Energy Society, and
Smart Growth Advocates arising out of the actions of any CECP or non-CECP
organization, whether or not that organization is a party to this Settlement
Agreement. No joint venture, agency, partnership or other fiduciary
relationship shall be deemed to exist or arise between or among the parties or
CECP groups as a result of this Settlement Agreement.
J.
Further Reservation of Rights
a.
Without in any way limiting CECP’s
commitments under Sections 16.A
and 16.B, CECP reserves all rights not expressly waived in this Settlement
Agreement, including but not limited to all rights:
•
to
seek administrative or judicial relief to address any violation of law by any
private or governmental entity or any person;
•
to
challenge or enforce any federal, state or local statutory or regulatory or
permit requirements, including any pre-construction permit application not
required or necessary to complete the construction of Comanche 3 and associated
facilities;
•
to enforce any federal, state or local statutory or regulatory or permit
requirements related to the operation of the Comanche Station after the
effective date of and not otherwise addressed by this Settlement Agreement;
•
to
advocate any position in any future CPUC proceeding or forum and to promote
clean energy and clean air throughout Colorado in any administrative,
legislative or public forum;
•
to
challenge in every respect and in any proceeding or forum any proposal related
to any new or expanded coal-fired power plant (except for Comanche 3 as set
forth in this Settlement Agreement) including any proposals for any new power
generation and associated facilities under the All-Source Solicitation and to
obtain through all available means any information about such proposals for new
power generation and associated facilities; and
22
•
to
comment publicly (positively or negatively) on any and all matters related to
PSCo or any of its agents, subsidiaries, assigns or affiliated companies.
b.
This Settlement Agreement constitutes a
compromise and settlement of several contested issues. The commitments of PSCo
hereunder are contingent upon the issuance of a CPCN for Comanche 3, the
pre-construction air quality permit, the Clean Air Act Title V operating permit
for Comanche 3, any other permits and approvals required for associated
transmission and other facilities, any permits and approvals required to
install pollution control equipment for Comanche 1 and 2 and assurance of
adequate cost recovery. If PSCo withdraws the pre-construction air quality
permit application for Comanche 3 for any reason (including third-party
objections to the permit), or if PSCo does not diligently pursue a
pre-construction air permit for Comanche 3 and such lack of diligence results
in a delay in the issuance of the permit of more than 36 months from the
effective date of this Settlement Agreement, or if the requisite approvals for
the construction of Comanche 3 are not obtained, CECP’s obligations under this
Settlement Agreement including CECP’s agreement under Section 16.A not to
challenge or sue alleged Clean Air Act violations shall be terminated and PSCo
shall have no obligation to undertake any of the improvements or actions set
forth in this Settlement Agreement except that PSCo shall not be relieved of
any obligation to comply with any order of the CPUC or any applicable legal
requirements. PSCo’s withdrawal of its pre-construction review permit
application for Comanche 3 and/or a decision not to construct Comanche 3 shall
not be considered a breach of this Settlement Agreement. PSCo agrees and
acknowledges that in the event of termination under this paragraph PSCo shall
not use or count the period of time in which CECP’s agreement not to challenge
or sue was in effect as support for any otherwise available defense of statute
of limitations, laches, delay or other defense based on failure to timely
prosecute any violations of the federal Clean Air Act or the federally
enforceable applicable implementation plan at the Comanche Station.
Further, except as necessary to enforce any terms of this Settlement
Agreement, PSCo’s or CECP’s willingness to compromise its positions on many of
the issues addressed in this Settlement Agreement, including but not limited to
the CO
2
proxy
cost, shall not be used by any Party against PSCo or any of the organizations
listed under Section 1 at proceedings at the CPUC or in any other forum
and the Settlement Agreement shall not be construed as an admission against
interest and shall be precluded as evidence pursuant to Rule 408 of the Federal
Rules of Evidence.
23
18.
Force Majeure
Neither Party shall be deemed to have breached this agreement or
trigger a right to terminate this Settlement Agreement for any delay or default
in performing hereunder if such delay or default is caused by conditions beyond
its control including, but not limited to Acts of God, Government restrictions,
wars, insurrections and/or any other cause beyond the reasonable control of the
Party whose performance is affected.
19.
Notice
Unless otherwise provided herein, whenever notifications, submissions,
or communications are required by this Settlement Agreement, they shall be made
in writing and addressed as follows:
As to PSCo:
Mary Fisher
Xcel Energy
1099 18th Street Suite 3000
Denver, CO 80202
Ph: (303) 308-2822
mary.j.fisher@xcelenergy.com
Olon Plunk
V.P., Environmental
Xcel Energy
4653 TABLE MOUNTAIN DR
COORS TECHNOLOGY CENTER
Golden, CO 80403
Ph: (720) 497-2015
Fax: (720) 497-2117
olon.plunk@excelenergy.com
As to Sierra Club:
Sierra Club Coordinating Attorney
Sierra Club Environmental Law Program
85 Second Street, 2d Floor
San Francisco, CA 94105
Phone: (415) 977-5680
Fax: (415) 977-5793
aaron.isherwood@sierraclub.org
24
Susan LeFever, Chapter Director
Sierra Club Rocky Mountain Chapter
1536 Wynkoop Street, #4C
Denver, CO 80202
Ph: 303-861-8819
Fax: 303-861-2436
susan.lefever@rmc.sierraclub.org
As to
Better Pueblo:
Ross Vincent, Chair
1829 S. Pueblo Blvd., #300
Pueblo, CO 81005-2105
Ph: 719-561-3117
Fax: 415-946-3442
chair@betterpueblo.org
As to Diocese of Pueblo:
Larry Howe-Kerr
Director, Office for Social Justice
1001 N. Grand Ave.
Pueblo, CO 81003
Ph: 800-354-2729, ext 112 (in CO)
Ph: 719-544-9861, ext 112
Fax: 719-544-5202
larryhk@aculink.net
As to
Smart Growth Advocates:
Vickie P Massam, President
3511 Lucia Court
Pueblo, CO 81005-3914
719-565-0597
vmassam@comcast.net
As to
Southwest Energy Efficiency Project (SWEEP):
Howard Geller
Executive Director
2260 Baseline Rd. Suite 212
Boulder, CO 80304
Ph: 303-447-0078 x1
hgeller@swenergy.org
As to
Environment Colorado:
25
Matt Baker
Executive Director
1536 Wynkoop Street, Suite 100
Denver, CO 80202
Ph: (303) 573-3871
mbaker@environmentcolorado.org
As to Colorado Renewable Energy Society:
Ronal W. Larson
21547 Mountsfield Drive
Golden, CO 80401
Ph: 303-526-9629
Fax: 303-526-0704
ronallarson@qwest.net
As to
Environmental Defense:
Air
Attorney
2334 North Broadway
Boulder, CO 80304
Ph: 303-440-401
vpatton@environmentaldefense.org
As to
Western Resource Advocates:
Energy
Program Director
2260 Baseline Road, Suite 200
Boulder, CO 80302
Ph: 303-444-1188 x232
Fax: 303-786-8054
jnielsen@westernresources.org
All
notifications, communications or submissions made pursuant
to this Settlement Agreement shall be sent in electronic (pdf) format unless
the size or other characteristics of the materials requires the submission of a
hard copy. If hard copies are submitted, they shall be submitted by: (a)
overnight mail or delivery service; or (b) certified or registered mail, return
receipt requested. All notifications, communications and transmissions (a) sent
by overnight, certified or registered mail shall be deemed submitted on the
date they are postmarked, or (b) sent by overnight delivery service shall be
deemed submitted on the date they are delivered to the delivery service. All
notifications, communications, and submissions made by electronic means shall
be deemed submitted on the date that the transmitting Party receives written
acknowledgment of receipt of such transmission. Any Party may change either the
notice recipient or the address for
26
providing notices to it by serving the other Parties with a notice
setting forth such new notice recipient or address. Nothing herein is intended
to limit informal communication between the Parties as contemplated by this
Settlement Agreement.
20.
Termination.
Unless terminated by mutual written agreement of the parties, PSCo
shall notify CECP in writing at such time that it has complied with all of the
requirements in this Settlement Agreement, and has obtained all Clean Air Act
Title V operating permits and all federally enforceable emission limits that
reflect all applicable requirements for the Comanche Station (including the
plant wide emission limitation for mercury under section 7). This
Settlement Agreement shall terminate and no longer be binding upon any party
unless within 30 days of PSCo’s notification, CECP subjects this issue to the
dispute resolution procedures set forth in Section 17.F. PSCo shall
provide any materially relevant information requested by CECP to assist CECP in
evaluating PSCo’s compliance determination described above.
Termination of this Settlement Agreement under this Section shall
not relieve PSCo of any obligation to comply with any order of the CPUC or any
applicable statutory, regulatory or permit requirements, including the emission
limitations provided for by this Settlement Agreement for the Comanche Station;
provided, however, that CECP’s covenant not to sue in Section 16.A, and
PSCo’s obligation to ensure that all future permits for Comanche Station
contain provisions that are at least as stringent as those in this Settlement
Agreement, shall survive termination.
21.
Amendment.
This Settlement Agreement only may be amended in writing by mutual
agreement of the Parties.
22.
Choice of Law.
This Settlement Agreement shall be construed and governed by the laws
of the state of Colorado, without regard to the principles of conflicts of law.
23.
Effective Date
This Settlement Agreement becomes effective on the date of the
signature of the last party.
24.
Additional Provisions.
25.
Each of the signatories to this Settlement
Agreement affirm that he or she is authorized to enter into the terms and
conditions of this Settlement Agreement. Each party hereto may validly execute
this document by facsimile signature or in
27
counterparts each of which shall constitute an original and all of
which shall constitute one and the same Agreement.
Endnotes
1.
The term “ton” means 2000 English pounds.
2.
The wind ancillary service cost study was
previously ordered by the CPUC in the 2003 LCP Renewable Energy RFP docket
(Docket No. 04A-325E) and is required to be completed by April 1,
2006. The parties recognize that some
of the study components not required under Section 13.A, but required by
the CPUC’s Renewable Energy RFP order, cannot be completed in time to inform
the All-Source Solicitation. Those components shall be included in the April 1,
2006 study results.
28
|
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AGREED & APPROVED
BY:
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Better Pueblo
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/s/ Ross Vincent
|
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Ross Vincent, Chair
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29
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Bishop of Pueblo
Diocese of Pueblo
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/s/ Arthur N. Tafoya
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+Most Rev. Arthur N.
Tafoya
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30
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Smart Growth Advocates
|
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|
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|
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/s/ Vickie P Massam
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Vickie P Massam,
President
|
41
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Southwest Energy
Efficiency Project
|
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/s/ Howard Geller
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Howard Geller,
Executive Director
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42
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Environment Colorado
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/s/ Matt Baker
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Matt Baker, Executive
Director
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43
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Sierra Club Rocky
Mountain Chapter
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/s/ Susan LeFever
|
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Susan LeFever, Chapter
Director
|
44
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Colorado Renewable
Energy Society
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/s/ David Bowden
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David Bowden, President
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45
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Environmental Defense
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/s/ Vickie Patton
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Vickie Patton, Senior
Attorney
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46
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Western Resource
Advocates
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/s/ James B Martin
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Jim Martin, Executive
Director
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47
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PSCo
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/s/ Richard C. Kelly
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Richard C. Kelly,
President & COO
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48
PSCo 2003 LCP
Comprehensive Settlement
Attachment D
Computer Modeling Analysis of Proposed LCP Settlement
CPUC Docket
No. 04A-214E, 04A-215E, 04A-216E
Jim Hill - Manager
Resource Planning
December 3, 2004
Summary
The Strategist computer
model was used to examine the cost and average rate impacts of the proposed LCP
Settlement under a set of updated modeling assumptions. These included the
price forecast for natural gas, PSCo’s cost of capital, reserve margins, and
the Company’s sales forecast. The cost
of the Settlement least-cost expansion plan was compared with the cost of other
least-cost expansion plans that were developed assuming 1) the Company’s
position as outlined in its October 18, 2004 rebuttal testimony and 2)
Comanche 3 is not constructed.
The results of these
model runs indicate that the proposed LCP Settlement is approximately $90
million (2003 PV) lower cost than a least-cost plan based on the Company’s
rebuttal testimony, and approximately $500 million to $1.3 billion lower cost
than a least-cost plan based on revised generic screening runs.
Major Modeling Assumptions
•
Natural Gas Prices
Natural gas commodity
prices used in this analysis are the same as those used in the Renewable Energy
RFP bid evaluation in which a combination of four different long-term gas price
forecasts were used to establish a single long-term gas commodity price
forecast (CERA, PIRA, EIA, and NYMEX). Additional costs were added to the gas
commodity price to account for transportation and Price Volatility Mitigation
(PVM). Below is an illustration of the
burner tip gas price used in these analyses compared to the range of gas prices
used in the LCP screening analysis of Volume 1.
1
•
Cost of Capital
Capital revenue
requirements for the Comanche 3 facility, Comanche 1 & 2 emission controls,
and for all generic resources were modeled as if they were utility rate-based
generation facilities. All revenue
requirement calculations were performed using the following information from
the 2002 PSCo rate case settlement.
|
|
|
Before Tax Weighted Cost of Capital
|
|
After Tax Weighted Cost of Capital
|
|
|
|
|
Weight
|
|
Rate
|
|
Wtd Cost
|
|
Weight
|
|
Rate*
|
|
Wtd Cost
|
|
|
Debt
|
|
48.60
|
%
|
7.31
|
%
|
3.55
|
%
|
48.60
|
%
|
4.53
|
%
|
2.20
|
%
|
|
Equity
|
|
51.40
|
%
|
10.75
|
%
|
5.53
|
%
|
51.40
|
%
|
10.75
|
%
|
5.53
|
%
|
|
|
|
Return on Rate
Base
|
|
9.08
|
%
|
Discount Rate
|
|
7.73
|
%
|
|
|
|
|
|
|
|
* Settlement debt rate
times .6199
|
|
•
Reserve Margin
All analyses used a
minimum reserve margin of 16% of firm load obligation. For all years of the
analysis, the maximum allowable reserve margin was set at 25% with the
exception of years 2010-2013. For these
years, the maximum allowable reserve margin was set at 35% to allow
consideration of the large generic coal units.
2
•
Comanche 3 Modeling (including Emission Controls on Comanche
1&2)
The base Comanche 3
facility (i.e., the new 750 MW unit) was modeled consistent with the
information contained in LCP Volume 1, Table 1.11-2, column labeled “Comanche 3
Hybrid Cooling”. Whenever the base
Comanche 3 facility was considered in these modeling analyses, it was
accompanied by a set of additional emission controls on existing Comanche units
1&2 (i.e., capital costs, FOM, VOM,
emission rate).
Two sets of Comanche
1&2 emission controls were considered.
Rebuttal
Scenario
. This scenario represents the Company’s October 18,
2004 rebuttal testimony. Emission controls consist of a new Lime Spray Dryer
(LSD) on Comanche 2 for SO2 control and NOx controls on both Comanche units
1&2. A breakdown of how these
controls were modeled is as follows:
•
LSD
•
Capital Cost $47.6 million (2003 $)
•
Annual FOM $1.4 million
•
VOM $0.44/MWh
•
SO2 reduction of 85% (i.e. from 0.59
lbs/mmbtu to 0.09 lbs/mmbtu)
•
NOx
•
Capital Cost $30 million (2003 $)
•
Annual FOM $0 million
•
VOM $0/MWh
•
NOx reduction of 33% (i.e. from 0.3
lbs/mmbtu to 0.1 lbs/mmbtu)
Settlement
Scenario
. This scenario includes
all
the emission
controls and costs of the Rebuttal Scenario plus a new Lime Spray Dryer (LSD)
on Comanche 1 and mercury (Hg) controls on both Comanche 1 and 2. A breakdown
of how these controls were modeled is as
follows:
•
LSD
•
Capital Cost $47.6 million (2003 $)
•
Annual FOM $1.4 million
•
VOM $0.45/MWh
•
SO2 reduction 85% (i.e. from 0.59
lbs/mmbtu to 0.09 lbs/mmbtu)
•
Hg
•
Capital Cost $3 million (2003 $)
•
Annual FOM $2 million
•
VOM $0/MWh
•
Hg reduction 60% (i.e. from 0.000005 lbs/mmbtu to 0.000002 lbs/mmbtu)
•
Generic Resources
Generic supply-side
generation resources were modeled identical to that described in LCP Volume 1,
Table 1.10-xx with the following exceptions:
Wind
=> To reflect the Company’s Renewable
Energy RFP, 480 MW of wind (i.e., six of the
80 MW generic wind facilities priced at $30/MWh flat) were
3
added to the existing
PSCo system upon which all additional least-cost resource plans were built. An
additional 320 MW of wind resources above and beyond the 480 MW were made
available to the Strategist model for all runs.
Adding this level of wind (480 + 320) to the existing 222 MW of wind
currently on the PSCo system represents a penetration of approximately 15%. No
additional wind beyond the 15% penetration was allowed in any run. All wind was
ascribed a 10% capacity credit.
It was assumed that the
additional 320 MW of available wind would not be eligible for the Production
Tax Credit (PTC) and would result in higher ancillary service costs than the
$2.50/MWh assumed for wind penetration levels to 10%. The additional 320 MW of wind was priced as
follows;
Revised
Generic Screening and Rebuttal Scenario:
•
Assumed
PTC price = $27.50/MWh flat
•
Assumed
PTC = $18.00 MWh
•
Non-PTC
price = $27.50 + ($18/1-tax rate) =
$27.50+ $18/.65 = $55.20/MWh
•
Assumed
Ancillary Cost = $7.00 MWh (for penetration from 10% to 15%)
•
Assumed
REC value = $2.13/MWh
•
Total
Price for additional wind = $55.20/MWh
+ $7.00/MWh - $2.13/MWh
= $60.06/MWh
Settlement
Scenario:
•
Assumed
PTC price = $27.50/MWh flat
•
Assumed
PTC = $18.00 MWh
•
Non-PTC
price = $27.50 + ($18/1-tax rate) =
$27.50+ $18/.65 = $55.20/MWh
•
Assumed
Ancillary Cost = $7.00 MWh (for penetration from 10% to 15%)
•
Assumed
REC value = $8.75/MWh
•
Total
Price for additional wind = $55.20/MWh
+ $7.00/MWh - $8.75/MWh
= $53.44/MWh
Conventional
Gas CT
=> Allowed as an option for the Strategist model
starting in year 2008. Last year available 2015 (when advanced CT assumed to
replace it).
Conventional
Gas CC
=> Allowed as an option for the Strategist model
starting in year 2008. Last year available 2015.
Advanced
Gas CT
=> Allowed as an option for the Strategist model
starting in year 2016. Last year available 2034.
Advanced
Gas CC
=> Allowed as an option for the Strategist model
starting in year 2008. Last year available 2034.
4
Integrated
Gasification Combined Cycle (IGCC)
=> Allowed as an option
for the Strategist model starting in year 2009. Last year available 2034.
Coal
=> Two sizes of generic coal facility
were examined in these analyses, a 750 MW unit and a 500 MW unit. A single 750
MW unit was allowed and up to two 500 MW units were allowed. The first year
available for the 750 MW unit was 2011 for the “early generic coal” and 2012
for the “base generic coal” scenarios.
The first year available for the 500 MW unit was 2012. The last year available for both the 750 MW
and 500 MW units was 2013. One
superfluous 500 MW unit was also allowed in these analyses (i.e., allowed to be
considered in years when there was not a need for additional capacity to meet
minimum reserves).
•
Emission Costs
Emissions of SO2, NOx,
and Hg were modeled with the same Clear Skies Initiative (CSI) assumptions as
those discussed in LCP Volume 1, section 1.10. These are as follows:
•
SO2
= $1,000/ton
•
NOx
= $1,000/ton
•
Hg
= $25 million/ton
Emissions of CO2 were
modeled at two different levels: $6.00 per ton for both the Revised Screening
scenarios and the Rebuttal Scenarios, and $9.00 per ton for the Settlement
scenario. Both the $6.00 and $9.00 levels escalated annually at a rate of
2.5%. In all scenarios, the first year the
CO2 cost was applied was 2010.
•
Demand and Energy Forecast
The July 2004 demand
and energy forecast was used to represent the “Base” level of peak demand and
annual energy for all scenarios examined.
This forecast was provided in the Company’s 2004 LCP Annual Progress
Report filed with the Commission on October 31, 2004. The July 2004 peak demand forecast is
approximately 1% higher (i.e., 67 MW) by year 2013 than the peak demand
forecast contained in the Company’s April 2004 LCP. The July 2004 energy sales forecast is
approximately 0.4% lower (i.e., 160 GWh) by year 2013 than the sales forecast
contained in the Company’s April 2004 LCP.
When modeling different
levels of DSM in these analyses, the peak demand reductions and energy
reductions were applied to the July 2004 demand and energy forecast.
5
•
DSM Peak and Energy
Reductions
Three levels of
additional DSM were examined.
1.)
No additional DSM =>
The level of DSM embedded in the July 2004 forecast was all that was
considered.
2.)
Rebuttal Scenario DSM
=> In this scenario, by year 2010 the
base peak demand forecast was reduced by
153 MW and annual energy sales were reduced by 365 GWh. These DSM peak and energy savings were
assumed to have a fifteen-year life.
3.)
Settlement Scenario DSM
=> In this scenario, by year 2013 the
base peak demand forecast was reduced by
320 MW and annual energy sales were reduced by 800 GWh. These DSM peak and
energy savings were assumed to have a fifteen-year life.
|
Year
|
|
Rebuttal DSM
Scenario
Peak
Reductions
MW
|
|
Rebuttal DSM
Scenario
Annual Energy
Reductions
GWh
|
|
Settlement DSM
Scenario
Peak
Reductions
MW
|
|
Settlement DSM
Scenario
Annual Energy
Reductions
GWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
25.8
|
|
50.2
|
|
40
|
|
100
|
|
|
2007
|
|
54.1
|
|
111.1
|
|
80
|
|
200
|
|
|
2008
|
|
85.3
|
|
186.2
|
|
120
|
|
300
|
|
|
2009
|
|
119.5
|
|
275.6
|
|
160
|
|
400
|
|
|
2010
|
|
153.7
|
|
365.0
|
|
200
|
|
500
|
|
|
2011
|
|
153.7
|
|
365.0
|
|
240
|
|
600
|
|
|
2012
|
|
153.7
|
|
365.0
|
|
280
|
|
700
|
|
|
2013
|
|
153.7
|
|
365.0
|
|
320
|
|
800
|
|
|
2014
|
|
153.7
|
|
365.0
|
|
320
|
|
800
|
|
|
2015
|
|
153.7
|
|
365.0
|
|
320
|
|
800
|
|
|
2016
|
|
153.7
|
|
365.0
|
|
320
|
|
800
|
|
|
2017
|
|
153.7
|
|
365.0
|
|
320
|
|
800
|
|
|
2018
|
|
153.7
|
|
365.0
|
|
320
|
|
800
|
|
|
2019
|
|
153.7
|
|
365.0
|
|
320
|
|
800
|
|
|
2020
|
|
153.7
|
|
365.0
|
|
320
|
|
800
|
|
|
2021
|
|
127.9
|
|
314.8
|
|
280
|
|
700
|
|
|
2022
|
|
99.6
|
|
253.9
|
|
240
|
|
600
|
|
|
2023
|
|
68.4
|
|
178.8
|
|
200
|
|
500
|
|
|
2024
|
|
34.2
|
|
89.4
|
|
160
|
|
400
|
|
|
2025
|
|
0
|
|
0
|
|
120
|
|
300
|
|
|
2026
|
|
0
|
|
0
|
|
80
|
|
200
|
|
|
2027
|
|
0
|
|
0
|
|
40
|
|
100
|
|
|
2028
|
|
0
|
|
0
|
|
0
|
|
0
|
|
|
2029
|
|
0
|
|
0
|
|
0
|
|
0
|
|
|
2030
|
|
0
|
|
0
|
|
0
|
|
0
|
|
|
2031
|
|
0
|
|
0
|
|
0
|
|
0
|
|
|
2032
|
|
0
|
|
0
|
|
0
|
|
0
|
|
|
2033
|
|
0
|
|
0
|
|
0
|
|
0
|
|
|
2034
|
|
0
|
|
0
|
|
0
|
|
0
|
|
6
•
DSM Costs
The expenditures and
associated revenue requirements for the Rebuttal and Settlement levels of DSM
discussed above are as follows:
|
Year
|
|
Rebuttal DSM
Scenario
Expenditures
2004 Dollars
|
|
Rebuttal DSM
Scenario
Expenditures
Nominal Dollars
|
|
Settlement DSM
Scenario
Expenditures
2005 Dollars
|
|
Settlement DSM
Scenario
Expenditures
Nominal Dollars
|
|
|
|
|
$Millions
|
|
$Millions
|
|
$Millions
|
|
$Millions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
$
|
16.00
|
|
$
|
16.76
|
|
$
|
17.31
|
|
$
|
17.72
|
|
|
2007
|
|
$
|
17.40
|
|
$
|
18.66
|
|
$
|
19.37
|
|
$
|
20.29
|
|
|
2008
|
|
$
|
19.00
|
|
$
|
20.86
|
|
$
|
22.97
|
|
$
|
24.63
|
|
|
2009
|
|
$
|
20.40
|
|
$
|
22.92
|
|
$
|
24.98
|
|
$
|
27.42
|
|
|
2010
|
|
$
|
22.20
|
|
$
|
25.53
|
|
$
|
25.97
|
|
$
|
29.18
|
|
|
2011
|
|
|
|
|
|
$
|
27.71
|
|
$
|
31.88
|
|
|
2012
|
|
|
|
|
|
$
|
28.84
|
|
$
|
33.95
|
|
|
2013
|
|
|
|
|
|
$
|
28.85
|
|
$
|
34.77
|
|
|
Total
|
|
$
|
95.00
|
|
$
|
104.74
|
|
$
|
196.00
|
|
$
|
219.85
|
|
Revenue requirements
calculations assumed 85% of the above expenditures were capital related and 15%
administrative. Capital expenditures for the Rebuttal DSM Scenario were
amortized over
five
years, while
capital expenditures for the Settlement DSM Scenario were amortized over
eight
years. Revenue requirements for both
scenarios were calculated assuming a 1-year lag between expenditure year and
project in-service year, straight-line
depreciation, zero AFUDC and an allowed rate of return of 9.08%. The resulting revenue requirements for both
DSM scenarios are as follows:
|
Year
|
|
Rebuttal
DSM
Scenario
Capital
Revenue
Requirements
($000) Nominal
|
|
Rebuttal
DSM
Scenario
Administrative
Costs
($000) Nominal
|
|
Total
Rebuttal DSM
Scenario
Revenue
Requirements
($000) Nominal
|
|
Year
|
|
Settlement
DSM
Scenario
Capital
Revenue
Requirements
($000) Nominal
|
|
Settlement
DSM
Scenario
Administrative
Costs
($000) Nominal
|
|
Total
Settlement DSM
Scenario
Revenue
Requirements
($000) Nominal
|
|
|
2003
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2003
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
|
2004
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2004
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
|
2005
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2005
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
|
2006
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2006
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
|
2007
|
|
$
|
4,014
|
|
$
|
2,515
|
|
$
|
6,529
|
|
2007
|
|
$
|
3,165
|
|
$
|
2,658
|
|
$
|
5,823
|
|
|
2008
|
|
$
|
8,224
|
|
$
|
2,799
|
|
$
|
11,023
|
|
2008
|
|
$
|
6,618
|
|
$
|
3,044
|
|
$
|
9,662
|
|
|
2009
|
|
$
|
12,673
|
|
$
|
3,129
|
|
$
|
15,802
|
|
2009
|
|
$
|
10,652
|
|
$
|
3,695
|
|
$
|
14,347
|
|
|
2010
|
|
$
|
17,293
|
|
$
|
3,439
|
|
$
|
20,732
|
|
2010
|
|
$
|
14,945
|
|
$
|
4,113
|
|
$
|
19,058
|
|
|
2011
|
|
$
|
22,184
|
|
$
|
3,830
|
|
$
|
26,014
|
|
2011
|
|
$
|
19,287
|
|
$
|
4,377
|
|
$
|
23,664
|
|
|
2012
|
|
$
|
17,848
|
|
$
|
0
|
|
$
|
17,848
|
|
2012
|
|
$
|
23,831
|
|
$
|
4,782
|
|
$
|
28,613
|
|
|
2013
|
|
$
|
13,461
|
|
$
|
0
|
|
$
|
13,461
|
|
2013
|
|
$
|
28,437
|
|
$
|
5,093
|
|
$
|
33,530
|
|
|
2014
|
|
$
|
9,006
|
|
$
|
0
|
|
$
|
9,006
|
|
2014
|
|
$
|
32,862
|
|
$
|
5,216
|
|
$
|
38,078
|
|
|
2015
|
|
$
|
4,538
|
|
$
|
0
|
|
$
|
4,538
|
|
2015
|
|
$
|
28,944
|
|
$
|
0
|
|
$
|
28,944
|
|
|
2016
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2016
|
|
$
|
24,934
|
|
$
|
0
|
|
$
|
24,934
|
|
|
2017
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2017
|
|
$
|
20,683
|
|
$
|
0
|
|
$
|
20,683
|
|
|
2018
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2018
|
|
$
|
16,384
|
|
$
|
0
|
|
$
|
16,384
|
|
|
2019
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2019
|
|
$
|
12,173
|
|
$
|
0
|
|
$
|
12,173
|
|
|
2020
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2020
|
|
$
|
7,969
|
|
$
|
0
|
|
$
|
7,969
|
|
|
2021
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2021
|
|
$
|
3,857
|
|
$
|
0
|
|
$
|
3,867
|
|
|
2022
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
2022
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
|
Total Rev Req
($000)
|
|
$
|
109,241
|
|
$
|
15,711
|
|
$
|
124,952
|
|
Total Rev Req
($000)
|
|
$
|
254,746
|
|
$
|
32,978
|
|
$
|
287,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Rev Req 2003 PV ($000)
|
|
$
|
60,603
|
|
$
|
9,950
|
|
$
|
70,554
|
|
Total
Rev Req 2003 PV ($000)
|
|
$
|
114,344
|
|
$
|
18,455
|
|
$
|
132,799
|
|
7
•
IPP Contracts Not Extended
Least-Cost expansion
plans were created with the assumption that
no
IPP contracts were
extended but rather the contracts were assumed to terminate per their current
contract term. Generic resources were
selected by the Strategist model to replace the capacity lost due to these
contract terminations.
•
IPP Contracts Extended
Least-Cost expansion
plans were also created with the assumption that fifteen existing IPP contracts
totaling 2,226 MW were extended. 1,500
MW of these contract extensions occur within the 10-year resource acquisition
period of 2003 to 2013. The remaining
726 MW of contract extension occur beyond 2013.
|
Contract
|
|
Summer
MW
|
|
Termination
Year
|
|
|
Thermo
Restructuring
|
|
150
|
|
2009
|
|
|
Brush
2 QF
|
|
68
|
|
2009
|
|
|
Monfort
Greeley QF
|
|
32
|
|
2011
|
|
|
Brush
1
|
|
50
|
|
2006
|
|
|
Brush
3
|
|
25
|
|
2006
|
|
|
Fountain
Valley
|
|
232
|
|
2013
|
|
|
Black
Hills Valmont 7&8
|
|
80
|
|
2013
|
|
|
Black
Hills Arap 56
|
|
116
|
|
2013
|
|
|
Brush
4D
|
|
115
|
|
2012
|
|
|
ManChief
|
|
262
|
|
2012
|
|
|
Plains
End
|
|
111
|
|
2012
|
|
|
Blue
Spruce
|
|
259
|
|
2013
|
|
|
subtotal
|
|
1500
|
|
|
|
|
|
|
|
|
|
|
|
UNC
Greeley QF
|
|
69
|
|
2014
|
|
|
Rocky
Mnt Energy (Calpine)
|
|
495
|
|
2014
|
|
|
Lamar
Wind (1)
|
|
162
|
|
2019
|
|
|
subtotal
|
|
726
|
|
|
|
8
Scenarios Modeled
The Strategist planning
model was used to develop least-cost expansion plans for the PSCo system over
the 2003-2034 time period for three main scenarios:
1.)
Revised Screening
Scenario
- All generic resource technologies are considered for addition to
the existing PSCo system (i.e., no Comanche 3).
480 MW of wind @ $30/MWh included as part of existing PSCo system
starting in 2006. Additional 320 MW of wind available for consideration
starting in 2007 at a non-PTC price of $60.06/MWh.
2.)
Rebuttal Scenario
- Comanche 3 considered along with all
generic resources except the generic 750 MW coal unit. DSM peak and energy savings per Rebuttal
Scenario (i.e., 153.7 MW and 365 GWh) with associated PVRR of $70.5 million.
480 MW of wind @ $30/MWh included as part of existing PSCo system starting in
2006. Additional 320 MW of wind available for consideration starting in 2007 at
a non-PTC price of $60.06/MWh.
3.)
Settlement Scenario
- Comanche 3 considered along with all generic resources except the generic 750
MW coal unit. Additional DSM peak and
energy savings per Settlement Scenario (i.e., 320 MW and 800 GWh) with
associated PVRR of $132.8 million. 480
MW of wind @ $30/MWh included as part of existing PSCo system starting in 2006.
Additional 320 MW of wind available for consideration starting in 2007 at a
non-PTC price of $53.44/MWh.
Least-cost expansion
plans for each of these three main scenarios were developed as follows:
The
Revised Screening
Scenario
was examined with both an IPP contract extension scenario and a
no-extension scenario under the following six sets of assumptions.
1.) No Additional Pulv
Coal -
No Additional DSM
2.) Early Generic Pulv
Coal (2011) - No Additional DSM
3.) Base Generic Pulv
Coal (2012)- No Additional DSM
4.) No Additional Pulv
Coal -
Rebuttal Scenario DSM
5.) Early Generic Coal
(2011) - Rebuttal Scenario DSM
6.) Base Generic Coal
(2012) - Rebuttal Scenario DSM
The
Rebuttal Scenario
was examined with both an IPP contract extension scenario and a no-extension
scenario under the following two sets of assumptions.
1.) Comanche 3 in 2010 –
Rebuttal Scenario DSM
2.) Comanche 3 in 2012 –
Rebuttal Scenario DSM
The
Settlement
Scenario
was examined for both an IPP contract extension scenario and a
no-contract extension scenario under the following assumptions.
1.) Comanche 3 in 2010 –
Settlement Scenario DSM
9
Scenario Modeling Results
•
IPP Contracts Not Extended
Assumption
Plan
Present Value (PV) Costs and Average Rate Impacts
The Settlement Scenario
Least-Cost Expansion plan was approximately $92 million (2003 PV) lower cost
than the Rebuttal Scenario and $228 million (2003 PV) lower cost than the
Rebuttal Scenario with a two-year delay in the Comanche 3 facility in-service
date. The Settlement Scenario was lower
cost than the six revised screening runs by $386 million to $1.343 billion
(2003 PV). The Settlement Scenario
resulted in an increase in average rates of
$0.04 /MWh compared to Rebuttal Scenario 1 (i.e., Com 3 in 2010). Compared to all other scenarios, the
Settlement Scenario resulted in a decrease in average rates ranging from
$0.22/MWh to $2.14/Mwh.
|
Run Description
|
|
Strategist
PV $000
|
|
DSM
Rev Req
PV $000
|
|
$9 to $6
CO2 Cost
Adjustment
PV $000
|
|
REC
Adjustment
PV $000
|
|
Total
Plan Cost
PV $000
|
|
Cost
Delta
From Settlement
PV $000
|
|
Average
PV Rate
$/MWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revised Screen 1
= No More Coal - No DSM - Contracts Not Extended
|
|
$
|
26,117,310
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
26,117,310
|
|
$
|
1,343,737
|
|
$
|
49.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revised Screen 2
= Early Generic Coal - No DSM - Contracts Not
Extended
|
|
$
|
25,300,200
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
25,300,200
|
|
$
|
526,627
|
|
$
|
48.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revised Screen 3
= Base Generic Coal - No DSM - Contracts Not Extended
|
|
$
|
25,342,848
|
|
$
|
0
|
|
$
|
0
|
|
$
|
0
|
|
$
|
25,342,848
|
|
$
|
569,275
|
|
$
|
48.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revised Screen 4
= No More Coal - Rebuttal DSM - Contracts Not
Extended
|
|
$
|
25,895,524
|
|
$
|
70,554
|
|
$
|
0
|
|
$
|
0
|
|
$
|
25,966,078
|
|
$
|
1,192,505
|
|
$
|
49.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revised Screen 5
= Early Generic Coal - Rebuttal DSM - Contracts Not
Extended
|
|
$
|
25,089,454
|
|
$
|
70,554
|
|
$
|
0
|
|
$
|
0
|
|
$
|
25,160,008
|
|
$
|
386,435
|
|
$
|
48.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revised Screen 6
= Base Generic Coal - Rebuttal DSM - Contracts Not
Extended
|
|
$
|
25,123,488
|
|
$
|
70,554
|
|
$
|
0
|
|
$
|
0
|
|
$
|
25,194,042
|
|
$
|
420,469
|
|
$
|
48.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rebuttal Scenario 1
= Com 3 2010 - Rebuttal DSM - Contracts
Not Extended
|
|
$
|
24,794,992
|
|
$
|
70,554
|
|
$
|
0
|
|
$
|
0
|
|
$
|
24,865,546
|
|
$
|
91,973
|
|
$
|
47.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rebuttal Scenario 2
= Com 3 2012 - Rebuttal DSM - Contracts
Not Extended
|
|
$
|
24,931,480
|
|
$
|
70,554
|
|
$
|
0
|
|
$
|
0
|
|
$
|
25,002,034
|
|
$
|
228,461
|
|
$
|
47.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement Scenario
= Com 3 2010 - Settlement DSM - Contracts
Not Extended
|
|
$
|
25,004,572
|
|
$
|
132,799
|
|
$
|
(377,471
|
)
|
$
|
13,672
|
|
$
|
24,773,573
|
|
$
|
0
|
|
$
|
47.70
|
|
CO2
adjustment
The “$9 to $6 CO2 Cost
Adjustment” noted in the above table removes the added cost associated with CO2
between the Settlement Scenario and all others.
CO2 was priced at $9/ton in the Settlement run and $6/ton in all other
runs. The effect of the $9/ton CO2
assumption is embedded within both the least-cost resource mix developed by the
Strategist planning model and the “Strategist PV $000” values
10
for the Settlement
Scenario (i.e., the $25,004,572). In
order to compare the Settlement plan costs which include CO2 @ $9/ton with the
other plans that include CO2 @ $6/ton, it is necessary to put all the plan
costs on comparable terms. This was
accomplished by taking the Settlement plan and recalculating its CO2 costs to
reflect a $6/ton CO2 cost rather than a $9/ton cost.
REC
adjustment
The “REC Adjustment”
noted in the above table accounts for the lower wind cost between the
Settlement Scenario and all others. As
on page 4 of this report, wind was
priced at $53.44/MWh in the Settlement run and $60.06/MWh in all other
runs. In order to compare the Settlement
plan costs with the other plans that, it is necessary to put all the plan costs
on comparable terms. This was
accomplished by taking the Settlement plan and recalculating its Non-PTC wind
costs to reflect a $60.06/MWh cost.
Least-Cost
Resource Mix for 10-Year Acquisition period
The actual mix of
resources associated with the various modeling runs discussed above is
illustrated below along with each plans total present value of costs over the
2003-2034 time period. For simplicity,
only those resources contained within the ten-year resource acquisition period
(2003-2013) are shown. The remaining mix
of resource additions from 2014 –2034 are not shown; however their costs are
included in the 2003-2034 PVRR values.
It should also be noted that the PVRR costs shown do not include the
adjustments for DSM, CO2 costs, and REC costs.
|
Year
|
|
Revised
Screen Run 1
Least-Cost
Resource Mix
|
|
Revised
Screen Run 2
Least-Cost
Resource Mix
|
|
Revised
Screen Run 3
Least-Cost
Resource Mix
|
|
Revised
Screen Run 4
Least-Cost
Resource Mix
|
|
Revised
Screen Run 5
Least-Cost
Resource Mix
|
|
Revised
Screen Run 6
Least-Cost
Resource Mix
|
|
Rebuttal
Scenario Run 1
Least-Cost
Resource Mix
|
|
Rebuttal
Scenario Run 2
Least-Cost
Resource Mix
|
|
Settlement
Scenario
Least-Cost
Resource Mix
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
PTC_W (6)
|
|
PTC_W(6)
|
|
PTC_W (6)
|
|
PTC_W (6)
|
|
PTC_W (6)
|
|
PTC_W (6)
|
|
PTC_W (6)
|
|
PTC_W (6)
|
|
PTC_W (6)
|
|
|
2007
|
|
C_CT (4)
|
|
C_CT (4)
|
|
C_CT (4)
|
|
C_CT (4)
|
|
C_CT (4)
|
|
C_CT (4)
|
|
C_CT (4)
|
|
C_CT (4)
|
|
C_CT (3)
|
|
|
2008
|
|
A_CC (1)
|
|
C_CT (2)
|
|
A_CC (1)
|
|
C_CC (1)
|
|
C_CC (1)
|
|
A_CC (1)
|
|
C_CT (2)
|
|
A_CC (1)
|
|
C_CT (2)
|
|
|
2009
|
|
IGCC (1)
|
|
C_CT (2)
|
|
A_CC (1)
|
|
IGCC (1)
|
|
C_CT (1)
|
|
A_CC (1)
|
|
C_CT (1)
|
|
A_CC (1)
|
|
C_CT (1)
|
|
|
|
|
|
|
A_CC (1)
|
|
C_CT (1)
|
|
|
|
A_CC (1)
|
|
|
|
A_CC (1)
|
|
|
|
A_CC (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPTC_W (1)
|
|
|
2010
|
|
A_CC (1)
|
|
C_CT (3)
|
|
C-CC (1)
|
|
A_CC (1)
|
|
C_CT (1)
|
|
C_CT (3)
|
|
Com_3 (1)
|
|
C_CT (3)
|
|
Com_3 (1)
|
|
|
|
|
|
|
|
|
C_CT (2)
|
|
|
|
C_CC (1)
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
A_CC (1)
|
|
C_750 (1)
|
|
C_CT (2)
|
|
C_CT (2)
|
|
C_750 (1)
|
|
C_CT (3)
|
|
|
|
C_CT (3)
|
|
|
|
|
2012
|
|
C_CC (1)
|
|
C_500 (1)
|
|
C_750 (1)
|
|
C_CT (3)
|
|
C_500 (1)
|
|
C_CT (1)
|
|
C_500 (1)
|
|
Com_3 (1)
|
|
C_500 (1)
|
|
|
|
|
C_CT (4)
|
|
|
|
C_500 (1)
|
|
A_CC (1)
|
|
|
|
C_500 (1)
|
|
|
|
C_500 (1)
|
|
|
|
|
2013
|
|
C_CT (3)
|
|
C_CT (1)
|
|
C_500 (1)
|
|
C_CT (3)
|
|
C_CT (1)
|
|
C_750 (1)
|
|
C_CT (4)
|
|
|
|
C_CT (3)
|
|
|
|
|
IGCC (1)
|
|
C_500 (1)
|
|
|
|
IGCC (1)
|
|
C_500 (1)
|
|
C_500 (1)
|
|
C_500 (1)
|
|
C_500 (1)
|
|
C_500 (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003-2004
PVRR
|
|
$
|
26,117,310
|
|
$
|
25,300,200
|
|
$
|
25,342,848
|
|
$
|
25,895,524
|
|
$
|
25,089,454
|
|
$
|
25,123,488
|
|
$
|
24,794,992
|
|
$
|
24,931,480
|
|
$
|
25,004,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PTC_W
|
|
= 80 MW PTC Subsidized
Wind
|
|
|
|
|
|
A_CC
|
|
= 368 MW Advanced CC
|
|
|
|
|
|
|
NPTC_W
|
|
= 80 MW Non-PTC
Subsidized Wind
|
|
|
|
|
|
IGCC
|
|
= 506 MW Integrated
Gasification CC
|
|
|
|
|
|
|
C_CT
|
|
= 139 MW Conventional CT
|
|
|
|
|
Next Section
Previous Section