UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
PacifiCorp
)
)
)
Docket No.
EL08-___-000
PETITION FOR DECLARATORY ORDER OF PACIFICORP
TO CONFIRM INCENTIVE RATE TREATMENT FOR
THE ENERGY GATEWAY TRANSMISSION EXPANSION PROJECT
July 3, 2008
Table of Contents
Page
I.
Introduction .............................................................................................................. 1
II.
Description Of PacifiCorp........................................................................................ 6
III.
Description Of The Project....................................................................................... 6
A.
Facilitation of the Delivery of Remote Renewable Resources ..................... 7
B.
Project Configuration .................................................................................... 8
C.
Priority One ................................................................................................. 10
D.
E.
F.
1.
Walla Walla to McNary – Segment A ............................................. 10
2.
Populus to Terminal – Segment B ................................................... 10
3.
Mona to Oquirrh – Segment C ......................................................... 11
4.
Sigurd to Red Butte to Crystal – Segment G ................................... 11
Priority Two ................................................................................................ 12
1.
Windstar to Aeolus to Bridger – Segment D ................................... 12
2.
Bridger to Populus – Segment E ...................................................... 13
Priority Three .............................................................................................. 14
1.
Populus to Hemingway – Segment E............................................... 14
2.
Hemingway to Captain Jack – Segment H....................................... 14
Priority Four ................................................................................................ 15
1.
Aeolus to Mona – Segment F........................................................... 15
IV.
Correspondence and Communications................................................................... 15
V.
PacifiCorp’s Project qualifies for Incentive transmission Rates under order no. 67916
A.
PacifiCorp is Entitled to a Rebuttable Presumption of Eligibility for the
Requested Incentives................................................................................... 17
B.
In the Alternative, Available Studies Demonstrate Requisite Project
Benefits Sufficient to Satisfy the Order No. 679 Eligibility Criteria.......... 19
1.
PacifiCorp’s IRP and Renewable Energy Procurement................... 20
2.
Transmission Studies Have Identified Significant Transmission
Bottlenecks, Many of Which the Project Will Help Alleviate......... 21
3.
The Project Will Enable PacifiCorp to Access Location-Constrained
Resources and Renewable Sources of Energy ................................. 24
i
C.
D.
VI.
1.
PacifiCorp Meets The Commission’s Nexus Test for a Non-Routine
Project............................................................................................... 25
2.
The Total Package of Requested Incentives Are Necessary to
Compensate PacifiCorp for the Unique and Substantial Risks Posed
by the Multi-State Project ................................................................ 35
The Commission Should Authorize The Requested Incentives.................. 41
Advanced technology statement............................................................................. 41
A.
B.
VII.
The Requested Incentives Meet the Commission’s Nexus Test and Are
Rationally Related To The Project’s Risks and the Investment Being Made25
Advanced Technologies to be Used By the Project .................................... 43
1.
Trapezoidal Conductor..................................................................... 43
2.
Static VAR Compensators ............................................................... 44
3.
Fiber Optic Shield Wires.................................................................. 45
4.
Phase Shifters ................................................................................... 46
5.
Special Protection Schemes ............................................................. 46
6.
Monitors for Transformers and Phase Shifters ................................ 47
PacifiCorp’s Decision to Forego the Use of Certain Advanced
Technologies ............................................................................................... 47
Conclusion.............................................................................................................. 49
ii
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
)
)
)
PacifiCorp
Docket No.
EL08-___-000
PETITION FOR DECLARATORY ORDER OF PACIFICORP
TO CONFIRM INCENTIVE RATE TREATMENT FOR
THE ENERGY GATEWAY TRANSMISSION EXPANSION PROJECT
Pursuant to Rule 207 of the Rules of Practice and Procedure of the Federal Energy
Regulatory Commission (“FERC” or “Commission”), 18 C.F.R. § 385.207 (2007), Section 1241
of the Energy Policy Act of 2005 (“EPAct 2005”), adding new Section 219 of the Federal Power
Act (“FPA”),1 and Order No. 679,2 PacifiCorp hereby submits this Petition for Declaratory Order
(“Petition”) seeking incentive rate treatment in connection with PacifiCorp’s Energy Gateway
Transmission Expansion Project (“Project”).
I.
INTRODUCTION
The Project is one of the most ambitious electric infrastructure projects planned in the
Western United States in the past two decades. By all reasonable measures, the size, scope,
complexity and purpose of the Project is exceptional, far exceeding any of the proposed
transmission projects that have been granted incentive rate treatment by the Commission to date
1
Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Star. 594, 315 and 1283 (2005)
(“EPAct 2005”).
2
See Promoting Transmission Investment Through Pricing Reform, Order No. 679, 116
FERC ¶ 61,057 at P 77 (2006) (“Order No. 679”), order on reh’g, Order No. 679-A, 117 FERC
¶ 61,345 (2006) (“Order No. 679-A”), order on reh’g, Order No. 679-B, 119 FERC ¶ 61,062
(2007) (“Order No. 679-B”).
1
under Order No. 679 and its progeny. At an estimated cost exceeding $6 billion,3 according to
Mr. John Cupparo, PacifiCorp’s Vice President of Transmission, the Project will enlarge and
expand PacifiCorp’s system-wide transmission network by adding approximately 2,000 miles of
new extra-high voltage (“EHV”) transmission lines located in Idaho, Oregon, Utah, Washington,
and Wyoming.4
The Project is intended to cost-effectively respond to regional needs and opportunities by
providing: 1) improved reliability; 2) congestion reduction; 3) transmission access for renewable
resources; 4) transmission for forecasted load growth; and 5) deployment of advanced
transmission technologies. The Project also has the potential to provide other benefits consistent
with the Commission’s policy objectives. Once completed, the Project will provide PacifiCorp’s
customers across the West with substantial economic, reliability and environmental benefits.
The Project has been scaled to improve the reliability of the bulk power system, and to reduce
transmission congestion and the future cost of delivered power throughout PacifiCorp’s six-state
service territory (California, Idaho, Oregon, Utah, Washington, and Wyoming). Were
PacifiCorp only focused on small-scale, short-term solutions for serving its load, it would have
proposed transmission projects that would have been far less comprehensive or as risky as the
Project. However, PacifiCorp intends to do more than simply serve anticipated load growth
through its development of the Project. For example, the Project is expected to deliver up to
3
As of the date of the filing of this Petition, this figure represents PacifiCorp’s best
estimate of its forward-looking capital expenditures, as adjusted for inflation, and based on
current estimates including Allowance for Funds Used During Construction (“AFUDC”). Given
the long-lead times associated with regulatory and environmental approvals, securing qualified
labor crews, and the costs of materials such as steel, this number will likely change over time.
See Rebecca Smith, Costs to Build Power Plants Pressure Rates, WALL STREET JOURNAL, May
27, 2008 at B3 (noting the inflationary risks associated with energy project development).
4
The description of the Project, along with its associated risks and benefits, are set forth
in Mr. Cupparo’s Affidavit, attached to this Petition as Appendix A (“Cupparo Affidavit”).
2
3,000 megawatts (“MW”) of capacity from location-constrained renewable resources in
Wyoming to distant load centers. The Project will also provide a platform for integrating and
coordinating future regional and sub-regional electric transmission projects being considered in
the Pacific Northwest and the Intermountain West.5
This massive, multi-state, multi-jurisdictional Project is the very type of project that
Congress envisioned when it added Section 219 to the FPA and that the Commission sought to
encourage companies to explore when it issued Order No. 679.6 When the Project’s benefits are
weighed against the substantial risks that PacifiCorp is taking on in developing it, the case for
granting PacifiCorp’s requested incentives is a compelling one. The geographic and financial
scale of the Project plainly places it in the category of “non-routine” projects to which the
Commission has previously granted incentives. To offset the risks associated with the
development of the Project, PacifiCorp, consistent with Section 219 of the FPA and Order No.
679, is requesting that the Commission issue a declaratory order granting the following incentive
rate mechanisms for the Project:
5
The Project will establish the first-of-its-kind energy superhighway (500 kilovolt
(“kV”)) connecting Wyoming, Idaho, Utah and Oregon.
6
See Order No. 679, 116 FERC ¶ 61,057 at P 24 (the Commission “must encourage
investors to take risks associated with constructing large new transmission projects that can
integrate new generation and otherwise reduce congestion and increase reliability. [The
Commission’s] policies also must encourage all other needed transmission investments, whether
they are regional or local, designed to improve reliability or to lower the delivered price of
power”).
3
•
A 250 basis point incentive rate adder to PacifiCorp’s base return on equity
(“ROE”), not to exceed the upper end of the zone of reasonableness, as
determined in a subsequent Section 205 proceeding; and
•
Authorization to recover all prudently incurred development and construction
costs if the Project is cancelled or abandoned, in whole or in part, as a result of
PacifiCorp’s inability to obtain necessary approvals, or as a result of any action or
inaction by a governmental authority, or regulatory agency, for any reason outside
PacifiCorp’s control.
As described in greater detail below, these requested incentives have been narrowly
tailored to address the considerable risks and challenges that PacifiCorp will face in constructing
the Project. Rather than seeking a blanket request for all of the incentives identified in Order No.
679 (such as recovery of 100 percent of prudently incurred Construction Work In Progress
(“CWIP”) and recovery of pre-commercial costs), PacifiCorp has instead limited its incentive
requests to only those that are “rationally related to the investments being proposed.”7
Any Commission-granted incentives will compensate PacifiCorp’s retail electric
customers for supporting the transmission investment through their retail electric rates, unlike
many other projects considered to date by the Commission. PacifiCorp’s state regulators will be
asked by – and are expected to allow – PacifiCorp to include the Project’s investment in retail
electric rates. Of critical importance is the fact that such customers will be asked to support the
portion of the investment needed for reliability and future growth – key elements that would be
absent if this were a merchant project. To the extent that state regulators permit the recovery of
all of the transmission investment in its retail rate base, PacifiCorp will compensate its retail
customers by crediting the transmission-related revenues, inclusive of any incentives granted by
the Commission, against its retail revenue requirement. PacifiCorp will also seek to optimize
third-party usage of the transmission capacity created by the Project, and such revenues will also
7
Order No. 679, 116 FERC ¶ 61,057 at P 48.
4
be credited against PacifiCorp’s retail revenue requirement if all of the investment is included in
retail rate base. Accordingly, PacifiCorp’s requested incentives will be an important
consideration in obtaining state regulator support for including in retail rates the reliability and
future growth elements of the Project.
PacifiCorp is not at this time filing a request for a change in rates under Section 205 of
the FPA. Consistent with Order No. 679,8 PacifiCorp intends to make a subsequent Section 205
rate filing at a future date to implement the applicable incentive rate treatment granted by the
Commission in its order on this Petition. Due to the substantial risks associated with this Project,
and the limited time available to coordinate with potential equity partners for commitments
before a final decision can be made on whether PacifiCorp should commit to single or double
circuit configuration on various segments of the Project,9 PacifiCorp respectfully requests that
the Commission act upon this Petition within 60 days of this request, or in the alternative, by
September 18, 2008.10
In support hereof, PacifiCorp respectfully states as follows:
8
See Order No. 679, 116 FERC ¶ 61,057 at P 79 (To implement authorized incentives,
“applicant will have the option of filing a comprehensive section 205 rate case in which all of the
utility’s rates would be reviewed in conjunction with the proposed recovery of the incentivebased rate treatments or filing a single-issue section 205 rate filing in which only the impact of
the incentive-based rate treatment for the facility granted the incentive will be addressed”).
9
As discussed infra, the Project allows for the flexibility to be upsized from a singlecircuit to a double-circuit system, specifically for three discrete portions (Segments D, E and F).
PacifiCorp is actively working with potential equity partners to determine the interest and
commitment to such an upsize. PacifiCorp’s expectation is that any incentive rate treatment
granted by the Commission in this proceeding would be applied to any variation in capital
expenditure and Project scope.
10
Order No. 679, 116 FERC ¶ 61,057 at P 77 (“The Commission will seek to process
petitions for declaratory orders quickly. While we cannot guarantee Commission action within
60 days of the request (as is statutorily required for section 205 filings), we will strive to meet
that standard. . . . ”).
5
II.
DESCRIPTION OF PACIFICORP
PacifiCorp, an indirect, wholly-owned subsidiary of MidAmerican Energy Holdings
Company (“MidAmerican”), is an investor-owned utility with its principal place of business in
Portland, Oregon. PacifiCorp is primarily engaged in the business of providing electric service
to approximately 1.7 million retail customers in six western states: California, Idaho, Oregon,
Utah, Washington, and Wyoming. The company operates as Pacific Power in Oregon
Washington and California, and as Rocky Mountain Power in Wyoming, Utah and Idaho.
PacifiCorp’s retail rates and certain aspects of its operations are regulated by the following state
public utility commissions: the California Public Utilities Commission, the Idaho Public Utilities
Commission, the Oregon Public Utility Commission, the Public Service Commission of Utah,
the Washington Utilities and Transportation Commission, and the Wyoming Public Service
Commission.11
PacifiCorp provides electric transmission service in nine Western states, owning and
operating approximately (1) 15,494 miles of transmission lines ranging from 46 kV to 500 kV
and (2) 12,131 MW of generation capacity from coal, natural gas, hydroelectric, wind, and
geothermal resources. PacifiCorp provides electric transmission service pursuant to a
Commission-approved open access transmission tariff.12
III.
DESCRIPTION OF THE PROJECT
The Project, which was first announced by PacifiCorp in May 2007, is a system-wide
transmission expansion program. Currently estimated to cost more than $6 billion, the Project is
a substantial undertaking that is expected to add approximately 2,000 miles of new EHV
11
PacifiCorp is providing copies of this Petition to each of these state public utility
commissions.
12
See PacifiCorp, 121 FERC ¶ 61,223 (2007).
6
transmission lines capable of delivering up to 3,000 MW of capacity from location-constrained
renewable resources to distant load centers throughout the West. In terms of dollars of
investment, miles of transmission lines and the number of states traversed, it is larger than any of
the other transmission expansion projects that have been recently presented to the Commission.
Appendix B to the Petition sets out the geographic and economic footprint of the Project, as
measured against seven other regional transmission projects that have been found eligible for
incentives by the Commission. Appendix B shows that the Project is the most ambitious
transmission project to which the Commission has been asked to authorize rate incentives since
the passage of EPAct 2005. The Project is a substantial financial undertaking by PacifiCorp,
representing more than a 330% increase in PacifiCorp’s existing transmission rate base.13
A.
Facilitation of the Delivery of Remote Renewable Resources
The new EHV transmission lines proposed under the Project will move power from new
renewable generation resources planned to be developed in Wyoming and Idaho to customer
growth areas in Wyoming, Utah, and Oregon. Since its acquisition by MidAmerican, PacifiCorp
has been actively adding renewable resources to its generation portfolio. Of the approximately
12,131 MW in PacifiCorp’s existing generation portfolio, approximately 1,556 MW comes from
hydroelectric sources, and approximately 800 MW is produced by a combination of wind,
geothermal, biomass and other renewable sources of energy. PacifiCorp’s 2007 Integrated
Resource Plan (“IRP”) targets the system-wide procurement of an additional 2,000 MW of post2005 renewable resources (other than hydro) by 2013, assuming the procurement is costeffective.14 When completed, the Project will enhance the ability of PacifiCorp to gain access to
13
Cupparo Affidavit at ¶¶ 9, 63.
14
See 2007 IRP at http://www.pacificorp.com/Navigation/Navigation23807.html.
7
renewable energy sources, as well as will help PacifiCorp to continue to provide reliable and
cost-effective electric service to its customers, while helping to relieve congestion in the
transmission-constrained Western Interconnection.
B.
Project Configuration
The Project is premised on a “hub and spoke” design that is characterized by major EHV
transmission lines that connect areas with a strong potential for generation resource development
(“hubs”) to an enhanced transmission system (“spokes”) for ultimate delivery to customers
throughout the western United States. Under the Project, hubs are planned for western
Wyoming, south central Wyoming, southeastern Idaho, southwestern Idaho, south central Utah,
and southern Oregon. From these hubs, power will be collected and then moved in different
directions, thereby allowing PacifiCorp to efficiently deliver power from a variety of generation
sources to load. The significant improvement to critical transmission capacity and the Project’s
“hub and spoke” design will provide flexibility, improve efficiency and enable development of
(and access to markets for) clean and renewable energy resources.15
PacifiCorp’s approach to the design of the Project is a significant departure from past
approaches to the development of major transmission projects. Historically, such projects were
built when associated generation resources were sited. However, with the current uncertainty of
the role of conventional generation technology, time duration to permit and construct major
transmission, and the inability of many renewable resource developers to finance major
15
In addition to supporting PacifiCorp’s retail and network customers’ needs, the Project
has adopted a flexible design approach to accommodate potential joint ownership participation in
some segments of the Project, as well as potential upgrades driven by commitments from third
parties with pending requests for points of new interconnection. The Project will strengthen the
connections between PacifiCorp’s Rocky Mountain Power and Pacific Power service areas, and
will help PacifiCorp ensure that its system is adequate and capable of meeting future regional
needs.
8
transmission investments, transmission must be sited “ahead” of specific generation resources to
best position utilities to meet future forecasted load growth. This approach presents greater
additional risks for transmission investment than the historical norm: a risk that is only magnified
by the scale and scope of the Project.
As is common with any significant transmission project, PacifiCorp is developing the
Project in separate stages. The Project will be comprised of eight interrelated and interdependent
line segments. Each segment has been assigned one of four priority classifications, and are
grouped as follows:16
•
Priority One - Segments A, B, C and G
•
Priority Two - Segments D and E
•
Priority Three - Segments E and H
•
Priority Four - Segment F
As most of these Segments are necessarily dependent on the development of the others,
the different priority levels have been established to ensure the most prudent approach toward the
overall in-service delivery of the Project, the most useful transfer capability as each segment is
brought into service, and the ability to respond as flexibly as possible to the market demands.
PacifiCorp is still moving forward to meet the announced 2014 in-service dates through its
permitting, technical planning, and design workstreams. The later Priority segments will be
shaped to best compliment the ability to deliver the first two Priority tiers.
16
A map of the Project, showing the individual Segments and their respective priorities,
is located on PacifiCorp’s OASIS site at http://www.oasis.pacificorp.com/oasis/ppw/
EnergyGWMap_200806.pdf; see also Exhibit No. 1 to the Cupparo Affidavit. Some of the
segments have also been grouped as follows: 1) Segments B and C – Gateway Central
Transmission Project; 2) Segments D and E – Gateway West Transmission Project; and 3)
Segments F and G – Gateway South Transmission Project.
9
Prioritizing the segments facilitates efficient and cost-effective development and
construction of the Project by clustering segments that offer similar general benefits and asset inservice dates. Due to the scope and geographic characteristics of the Project, concurrent
development of all the Project segments would not be not cost-effective. Development of all of
the segments is progressing, and due to the inter-relationship of some of the segments, an order
of priority is necessary to construct the segments in a prudent manner.
C.
Priority One
The four segments that comprise Priority One of the Project are being built to enhance
the base load service and reliability of PacifiCorp’s transmission system. Together, these
segments are anticipated to be among the earliest portions of the Project to be placed into
service, and PacifiCorp has already begun the preliminary permitting and contracting work
necessary for getting these segments on line between 2010 and 2014.
1.
Walla Walla to McNary – Segment A17
Segment A of the Project is an estimated $108 million project that will run approximately
56 miles between Walla Walla, Washington and Umatilla, Oregon, and will connect existing
power substations at Walla Walla, Wallula and McNary. When completed in 2010, the 230 kV
segment could be used to link existing and future sources of renewable resources to better benefit
system power transfers.
2.
Populus to Terminal – Segment B18
Segment B of the Project is an estimated $800 million project that will run from a new
Populus substation, near Downey, Idaho, approximately 135 miles south to the existing Terminal
17
See Cupparo Affidavit at ¶ 14.
18
See Cupparo Affidavit at ¶¶ 15-17.
10
substation near the Salt Lake City Airport west of Salt Lake City, Utah. The double circuit 345
kV line will be constructed in two segments. The first segment will link the new Populus
substation with the existing Ben Lomond substation north of Ogden, Utah. The second segment
will link Ben Lomond with the Terminal substation. Both pieces of Segment B are anticipated to
be placed in service in 2010, and are intended to deliver reliable power to the growing load
demand along the Wasatch front in Utah. This segment is also critical to achieve the planned
transfer capability rating on other Project segments.
3.
Mona to Oquirrh – Segment C19
Segment C of the Project is an estimated $425 million project that will run north
approximately 86 miles from the Mona substation near Mona, in Juab County, Utah, to two
future substations. The line will then split and connect to the Oquirrh substation located in
West Jordan, Utah and the Terminal substation located in Salt Lake City. The double circuit line
will have one segment constructed at 500 kV and the other at 345 kV. Segment C is intended to
serve one of the fastest growing areas in Utah, and in the region, by providing the additional
capacity necessary to serve the growing customer demand, and to improve reliability and
operational flexibility of the bulk transmission system. The line is also anticipated to assist in
linking future generation resources with load centers in Utah. This Segment is also critical to
achieve the planned transfer capability rating on other Project segments.
4.
Sigurd to Red Butte to Crystal – Segment G20
Segment G is an estimated $754 million transmission project that will span
approximately 280 miles, and will connect the existing Sigurd substation (about 50 miles south
19
See Cupparo Affidavit at ¶ 18.
20
See Cupparo Affidavit at ¶ 23.
11
of Mona), through the Red Butte substation in the southeast corner of Utah, to the Crystal
substation north of Las Vegas, Nevada. The lines linking Sigurd to Red Butte will be a single
circuit 345 kV line, and the one linking Red Butte to Crystal will be a single circuit 345 kV line,
both lines will be dependent on the best determined voltage and scale needed to most efficiently
interconnect with neighboring utilities and to meet customer needs.
Segment G will provide additional capacity and access to resources from Wyoming
necessary to serve growing customer demand, to meet point-to-point customer commitment
requirements, and to improve the reliability and operational flexibility of the bulk transmission
system. This project could be upsized to include a 500 kV line configuration, and additional line
segments added between Mona and Crystal, if commitment is received from wholesale
customers. The 345 kV lines would also provide the reliability base needed to support any of
these scaled options, while also meeting the load service needs of PacifiCorp’s customers.
PacifiCorp is actively working with interested parties to determine levels of interest and
commitment in pursuing an upsize to this segment.
D.
Priority Two
The two segments that have received the Priority Two classification (Segments D and
part of Segment E) are designed to enhance the resource adequacy of the region by helping to
connect transmission-constrained wind resources in Wyoming to westward load centers.
1.
Windstar to Aeolus to Bridger – Segment D21
Segment D of the Project is an estimated $880 million line that will run approximately
298 miles from the Windstar substation in eastern Wyoming westward to the Bridger substation
in western Wyoming. Segment D is part of the Gateway West Transmission Project, and is
21
See Cupparo Affidavit at ¶ 19.
12
currently jointly sponsored by PacifiCorp and Idaho Power. Segment D is expected to be in
service by 2014, and will consist of two single circuit 230 kV lines connecting Windstar to
Aeolus, and a double circuit 500 kV/230 kV line(s) connecting Aeolus to Bridger. The 230kV
portion of the segment of the line from Aeolus to Bridger could be potentially upsized to 500 kV
depending on the outcome of queue requests and equity partner interest. In addition to
construction of a new Windstar substation, a new substation will also be built at Aeolus (to
integrate new generation resources and to provide connection with the Gateway South Project).
Segment D is intended to access and deliver energy from new and existing generating resources,
which are currently anticipated to be primarily renewable energy resources such as wind.
2.
Bridger to Populus – Segment E22
Segment E of the Project is also part of the jointly-sponsored Gateway West Project.
This segment will be comprised of an estimated $1.02 billion line, which will run from a planned
transmission hub near Rock Springs, Wyoming across Idaho to a point southwest of Boise. The
line will be constructed in two sections. The first section, classified as Priority Two, will link the
Bridger substation to the Populus substation via a single circuit 500 kV line. The second section
has been categorized as Priority Three and is intended to connect the Populus substation to the
Hemingway substation.23 A new substation will be built at Populus (to connect with Path C
transmission into Utah as further described in the Cupparo Affidavit) for this portion of Segment
E. Together with Segment D, Segment E will help access and deliver energy from new and
existing generating resources, including renewable energy resources such as wind in Wyoming,
22
See Cupparo Affidavit at ¶ 20.
23
This portion of the segment will link the Idaho to Oregon segments. Exact location
may change as a result of the Western Electricity Coordinating Council (“WECC”) regional
planning process.
13
to load centers further west. The two single circuit Segments that comprise Gateway West have
the potential to be upscaled if equity partners or wholesale customers commit to equitable cost
sharing.
E.
Priority Three
The remaining portion of Segment E, as well as Segment H, constitute the third level of
priority for the Project. These segments are intended to help integrate PacifiCorp’s control area
within the Project footprint, and to help provide a means for transmitting renewable energy
supplies.
1.
Populus to Hemingway – Segment E24
The second section of Segment E will connect the new substation at Populus to the new
substation to be built at Hemingway as described above. Compared to the first section of
Segment E, this portion will be placed into service at a later date as partner and construction
conditions allow, as construction is planned to directly follow the Priority Two Segment E work.
2.
Hemingway to Captain Jack – Segment H25
Segment H of the Project is an estimated $786 million line that will run approximately
375 miles from the Hemingway substation in western Idaho to the Bonneville Power
Administration’s Captain Jack substation. The western terminus of this project, while currently
planned for Captain Jack, has some ability to be moved within the same general area if equity
partner and/or wholesale customer commitments are secured and efficiencies are identified.
24
See Cupparo Affidavit at ¶ 21.
25
See Cupparo Affidavit at ¶ 24.
14
F.
Priority Four
Segment F of the Project has been classified as Priority Four. This Priority status is
intended to provide back up system reliability, as well as rating support for PacifiCorp’s newly
enhanced system.
1.
Aeolus to Mona – Segment F26
Segment F of the Project is an estimated $764 million line that will run approximately
395 miles from the Aeolus substation in eastern Wyoming southwest to the Mona substation in
Juab County, Utah. This Segment is part of the Gateway South Transmission sub-area of the
Project. This segment could be upsized to a double circuit 500 kV line depending on the
outcome of queue requests and equity partner interest.
IV.
CORRESPONDENCE AND COMMUNICATIONS
Correspondence or communications regarding this matter should be sent to the following
individuals:
Joseph H. Fagan
Becky M. Bruner
Sandy I. Grace
Heller Ehrman LLP
1717 Rhode Island Ave., N.W.
Washington, DC 20036-3001
Phone: (202) 912-2162
Fax: (202) 912-2020
joseph.fagan@hellerehrman.com
becky.bruner@hellerehrman.com
sandy.grace@hellerehrman.com
Natalie L. Hocken
Ryan Flynn
PacifiCorp
825 NE Multnomah Avenue
Suite 2000
Portland, OR 97232-2149
Phone: (503) 813-7205
Fax: (503) 813-7262
natalie.hocken@pacificorp.com
ryan.flynn@pacificorp.com
Jay Carriere
Manager, Federal Regulatory Affairs
MidAmerican Energy Holdings Co.
1800 M Street, NW, Ste. 330N
Washington, DC 20036
(202) 828-4590
JGCarriere@midamerican.com
26
See Cupparo Affidavit at ¶ 22.
15
Copies of the filing are also available for inspection at PacifiCorp’s office and on
PacifiCorp’s website at http://www.pacificorp.com/Article/Article43351.html. PacifiCorp has
also served a copy of this filing on all of its customers by posting this filing electronically on its
website, and requests waiver of the requirement to post by mailing paper copies to its customers.
V.
PACIFICORP’S PROJECT QUALIFIES FOR INCENTIVE TRANSMISSION
RATES UNDER ORDER NO. 679
EPAct 2005 directed the Commission to “promote reliable and economically efficient
transmission and generation of electricity by promoting capital investment in the enlargement,
improvement, maintenance, and operation of all facilities for the transmission of electric energy
in interstate commerce . . . .”27 In response to EPAct 2005, the Commission issued Order Nos.
679 and 679-A which provide incentive-based rate treatment for transmission infrastructure
investment projects that will help ensure the reliability of the bulk power transmission system
and/or reduce the cost of delivered power to customers by reducing transmission congestion.
Order No. 679-A adopts a rebuttable presumption of eligibility for incentives with respect
to transmission projects that either (1) result from a fair and open regional planning process that
considers and evaluates projects for reliability and/or congestion and is found acceptable to the
Commission, or (2) have received construction approval from an appropriate state commission or
siting authority, provided that these approval processes require that a project ensures reliability
or reduces the cost of delivered power by reducing congestion.28 Specifically, an applicant may
rely on either of these rebuttable presumptions to support its request for a finding that the
27
16 U.S.C. § 824s(b)(1) (emphasis added).
28
Order No. 679-A, 117 FERC ¶ 61,345 at PP 48-49.
16
facilities qualify for incentive rate treatment.29 Under Order No. 679, the applicant requesting
incentive rate treatment is required to provide a detailed explanation of how the proposed rate
treatment complies with Section 219 of the FPA.30
In order to meet these standards, the applicant must demonstrate that: (1) the facilities for
which it seeks incentives satisfy the requirements of FPA Section 219 (i.e., that they ensure
reliability or reduce the cost of delivered power by relieving congestion); and (2) the total
package of incentives is tailored to address the demonstrable risks or challenges faced by an
applicant in undertaking the project.31
As described below, this Petition demonstrates that PacifiCorp’s request is entitled to a
rebuttable presumption of eligibility for incentives. Alternatively, if the Commission does not
determine that PacifiCorp is entitled to a rebuttable presumption, PacifiCorp submits that it has
made the requisite showing, under Section 219 and Order No. 679, to justify the awarding of
incentives for the Project. In either case, the Petition demonstrates the required nexus between
the Project and PacifiCorp’s requested incentives.
A.
PacifiCorp is Entitled to a Rebuttable Presumption of Eligibility for the
Requested Incentives
PacifiCorp is entitled to a rebuttable presumption under Order No. 679 and its progeny on
the basis that substantially all segments of the Project were approved by a fair and open subregional planning processes. Virtually all segments of the Project, were planned, coordinated
29
Id. at P 77.
30
18 C.F.R. § 35.35 (d).
31
Id.
17
and approved under the auspices of the Northern Tier Transmission Group (“NTTG”) planning
process.32
PacifiCorp adopted NTTG as its sub-regional planning organization for the purposes of
meeting the principles of Order No. 890, as described in its filed Attachment K which is
currently pending at the Commission.33 NTTG is a coalition of investor-owned and public
utilities, state agency officials, and customer groups committed to working with stakeholders to
increase the efficient use of the grid and to develop the infrastructure needed to ensure reliability
and to reduce congestion in the Pacific Northwest and Rocky Mountain states. NTTG performs
both reliability and economic planning coordination for projects in the NTTG footprint,34 and
coordinates with the WECC Regional Planning Process, which is responsible for coordinating
and promoting electric system reliability across the Western Interconnection.35
NTTG’s 2007 Annual Report36 identified the need for additional transmission facilities to
increase transmission capacity to reduce congestion and to improve reliability in the existing
paths spanning the sub-region. In accordance with this need, NTTG members have developed a
Fast Track Process, with the participation of stakeholders through a series of open meetings, in
which projects required for reliability, and which are supported by transmission service requests
32
Segments A, B, and C originally represented transaction commitments agreed to as part
of MidAmerican’s acquisition of PacifiCorp. As currently constituted, Segment A represents a
variation, while Segments B and C represent significant expansions, of the original transaction
commitments.
33
Compliance Filing Pursuant to Order No. 890, Docket No. OA08-40 (Dec. 7, 2007).
34
The NTTG footprint includes Oregon, Idaho, Utah, Montana and Wyoming.
35
WECC has developed policies and procedures for stakeholders to participate in the
regional planning and project rating process and serves as the regional planning organization for
evaluating the Project.
36
See discussion of NTTG in Cupparo Affidavit at ¶¶ 27-29, 32-35; the NTTG 2007
Annual Report is attached as Exhibit No. 2 to Cupparo Affidavit.
18
throughout the region are identified.37 Implicit in the NTTG planning process are the
considerations of relieving congestion and enhancing reliability;38 therefore, in the course of
developing the Fast Track Process, NTTG reviewed, among other things, the 2004 Rocky
Mountain Area Transmission Study (“RMATS”) and the Seams Steering Group – Western
Interconnection (“SSG-WI”) studies.39 As a participant in the NTTG Fast Track Process,
PacifiCorp was required to develop a technical study plan that, among other things, identified
interested and affected parties; coordinated with other regional and sub-regional planning groups,
including the Northwest Transmission Assessment Committee, Columbia Grid and West
Connect; and performed required WECC Regional Planning Review Studies. Among the Fast
Track projects approved and identified in the 2007 Annual Report were Gateway South
(Segments F and G), Gateway West (Segments D and E), Gateway Central (Segments B and C),
and Segment H (Hemingway to Captain Jack).
B.
In the Alternative, Available Studies Demonstrate Requisite Project
Benefits Sufficient to Satisfy the Order No. 679 Eligibility Criteria
In the event the Commission determines that PacifiCorp is not yet entitled to a rebuttable
presumption that it meets the criteria of FPA Section 219, PacifiCorp submits that it has
nonetheless met the burden of demonstrating that the Project satisfies such criteria. There should
be little doubt that the Project, once completed, will result in increased reliability and a reduction
in congestion sufficient to fulfill the Order No. 679 eligibility criteria for the requested
37
NTTG 2007 Annual Report at 1.
38
Id. at 7 (identifying as the first step in the NTTG Fast Track Planning Process, the
“[r]eview, with stakeholders, past transmission provider studies and additional data to identify
congested transmission that impedes efficient and reliable operation of the grid”) (emphasis
added).
39
The SSG-WI study summary is available, beginning on page 104, at:
http://www.wecc.biz/documents/library/WCATF/Report_to_DOE_050806_Templates_Report_v
er3.doc
19
incentives. Moreover, consistent with Commission policy, the Project will enable PacifiCorp to
access location-constrained renewable sources, and thus provides an independent basis on which
the Commission can grant the requested incentives.
1.
PacifiCorp’s IRP and Renewable Energy Procurement
As a threshold matter, the Project is consistent with the mandates set forth in PacifiCorp’s
2007 IRP.40 PacifiCorp’s IRP is the product of a collaborative public process, drawing
considerable involvement from customer interest groups, regulatory staff and regulators, and
other stakeholders. From late 2005 though April 2007, PacifiCorp held 13 public meetings to
discuss important planning issues and to solicit comments on IRP analysis, methods and
assumptions. The result of this public process was the 2007 IRP.
The Project will assist PacifiCorp in meeting the mandate set forth in its 2007 IRP to
cost-effectively enhance grid reliability, both on its network and region-wide. For example, the
Project will 1) establish a 500 kV backbone;41 2) reduce curtailments resulting from
overscheduled use; 3) provide additional accessibility to resources and reserves; 4) increase the
40
PacifiCorp prepares and submits an IRP for the states in which it provides retail
service.
41
As there is currently no 500 kV infrastructure within the Project footprint in Idaho,
Utah, and Wyoming, the first entity to construct a new 500 kV system will ultimately be
responsible for mitigating the impacts caused on the underlying system by the introduction of a
higher voltage than currently exists. This requirement is a result of North American Electric
Reliability Corporation (“NERC”) reliability standards requiring that the system operate under
conditions to withstand the next major facility electrical outage, or “n-1 outage”. If the existing
system is equal to or higher in voltage to new additions, such additions do not typically cause as
large of a concern with additional outages. With additions larger in voltage than the existing
system, typically a fully redundant transmission system must be constructed. This is the case for
Project Segments D, E and F. This effectively raises the costs and risks associated with
incorporating a new higher voltage class of transmission facilities in any area. Once the initial
construction is completed, future 500 kV additions in the same footprint, whether by PacifiCorp
or others, could have much lower cost barriers to entry because of the network backbone created
by the Project facilities.
20
diversity of the available resource mix; 5) connect PacifiCorp’s Rocky Mountain Power and
Pacific Power control areas to better serve network load; and 6) assist in satisfying certain state
renewable portfolio requirements or goals through its delivery of wind power.
Further, as described in its 2007 IRP, PacifiCorp is also aggressively pursuing, on a longterm basis, renewable resources, if cost-effective. The Project will provide PacifiCorp and other
interested parties with unprecedented access to high-value location-constrained renewable
resources in Wyoming and other states. According to the American Wind Energy Association,
Wyoming alone has the potential to accommodate approximately 85,200 MW of wind power
capacity, with a substantial amount reflected in PacifiCorp’s interconnection queue.42 The
Project’s location will help to efficiently and cost-effectively integrate some of these vast wind
resources into the grid to the benefit of the entire region.
2.
Transmission Studies Have Identified Significant Transmission
Bottlenecks, Many of Which the Project Will Help Alleviate
As discussed in the Cupparo Affidavit, over the past decade, numerous studies have been
issued that have documented the urgent need for new transmission in the Western United States.
As early as 2002, the DOE National Transmission Grid Study identified the Wyoming-Idaho
interface as a major constrained interface, and found, under optimal conditions, the WyomingNorthern Utah interface to be congested during 50 percent or more of the hours during the year.43
42
See American Wind Energy Association at
http://www.awea.org/projects/projects.aspx?s=Wyoming. Information about PacifiCorp’s
interconnection queue is located at
http://www.oasis.pacificorp.com/oasis/ppw/lgia/pacificorplgiaq.htm.
43
Cupparo Affidavit at ¶ 47; this study listed the Wyoming-to-Idaho interface as major
constraint and WY to Northern UT as congested 50% of hours or greater. See National
Transmission Grid Study at pp 15, 18. An excerpt of this report is provided as Exhibit No. 8 to
the Cupparo Affidavit. A full copy of this report is available at
http://www.pi.energy.gov/documents/ TransmissionGrid.pdf.
21
The 2004 RMATS reached similar conclusions, the result of which was a recommended
expansion of the 345 kV transmission lines connecting the Bridger substation (included in
Segments D and E of the Project) to points south and west as critically needed improvements.44
In addition, the Department of Energy’s 2006 National Electric Transmission Congestion Study
(“DOE Congestion Study”) identified several constrained transmission paths in the West,
including lines used to deliver electricity from generation plants in Wyoming to loads in Utah
and Oregon.45 Specifically, the DOE Congestion Study illustrated that the expansion of the
Bridger West facility is critical for relieving congestion from Wyoming to Northern Utah, and
Wyoming to Idaho.46 Similarly, the Western Interconnection 2006 Congestion Assessment
Study, which was issued by the DOE Western Congestion Analysis Task Force, identified areas
of congestion in the Rocky Mountain states, and projected that based on 2005 load and resource
forecasts and a production model, many of the paths associated with the various segments of the
Project were forecasted to be heavily congested.47 Lastly, reports initiated by the Western
Governor’s Association (“WGA”) also show certain paths in PacifiCorp’s service territory (such
44
See Cupparo Affidavit at ¶ 43 (discussing the RMATS at Chapter 3-2, which shows the
Bridger expansion as a critical expansion area from Wyoming to Northern Utah and Wyoming to
Idaho). An excerpt of this report is provided as an attachment to the Cupparo Affidavit as
Exhibit No. 4. The full report is available at:http://psc.state.wy.us/htdocs/
subregional/Reports.htm
45
See Cupparo Affidavit at ¶ 44 (discussing the National Electric Transmission
Congestion Study (August 2006) at pp 31-35)). The transmission constraints identified in this
study were identified by reviewing recent transmission studies such as those conducted by
WECC and SSG-WI. An excerpt of the study is provided as an attachment to the Cupparo
Affidavit, as Exhibit No. 5. The full report is available at http://nietc.anl.gov/documents/
docs/Congestion_Study_2006-9MB.pdf.
46
Such expansion is addressed by the Segment E portion of the Project.
47
Cupparo Affidavit at ¶ 45. See also Exhibit 6 to Cupparo Affidavit. A full copy of this
study is available at http://www.oe.energy.gov/DocumentsandMedia/
DOE_Congestion_Study_2006_Western_Analysis.pdf.
(Footnote continued)
22
as the Segment C Populus to Terminal portion of the Project) to be constrained.48 The Project is
PacifiCorp’s affirmative response to these identified critical areas of congestion.
In this respect, the Order No. 679 criteria dovetail with PacifiCorp’s long-term
operational goals and its parallel obligation to provide its customers with cost-effective, safe and
reliable electric service. To ensure long-term reliability, PacifiCorp must upgrade, reconfigure
and supplement transmission facilities throughout its service area on an ongoing basis. The
Project will be built to satisfy all of the WECC and NERC’s planning and reliability standards as
they relate to system adequacy and security, system modeling data requirements, system
protection and control, and system restoration.49
Without the new transmission capacity created by the Project, PacifiCorp would have to
rely on existing transmission interconnections, or small-scale, low benefit projects, many of
which are already fully utilized, or have already been undertaken. Such projects would not
provide any long-term meaningful transmission capacity necessary for future projected load and
ability to access generation. In the process of planning the Project, PacifiCorp considered many
small-scale projects with limited risks and benefits, all of which were ultimately rejected because
they did not yield the Project’s long-range benefits. PacifiCorp’s network load obligation is
expected to grow during the next ten years at an average annual rate of approximately two to
three percent.50 Accordingly, the amount of planning reserves, which are required to maintain
reliability obligations, will increase. For example. the existing transmission capacity from
48
Cupparo Affidavit at ¶ 46; see also Exhibit No. 7 to the Cupparo Affidavit. The full
report is available at http://www.westgov.org/wga/initiatives/cdeac/TransmissionReportfinal.pdf.
49
Cupparo Affidavit at ¶ 38.
50
Cupparo Affidavit at ¶ 42.
23
southeastern Idaho into Utah is fully utilized and no additional capacity can be made without the
addition of new transmission lines. The proposed transmission segments under the Project’s
umbrella are PacifiCorp’s long term response to the projected demands on PacifiCorp’s available
capacity. These lines will also provide PacifiCorp with the ability to access power from
numerous location-constrained renewable generation sources and to negotiate the most
competitive pricing for those sources of power.
3.
The Project Will Enable PacifiCorp to Access LocationConstrained Resources and Renewable Sources of Energy
In addition to relieving already constrained paths, the Project will facilitate PacifiCorp’s
access to location-constrained resources, especially renewable sources of energy. The WGA and
its working groups have also identified the important need to develop transmission projects
throughout the West to access location-constrained resources. The WGA’s Transmission Task
Force Report, dated May 2006, considered the location and availability of location-constrained
renewable resources and the effect that timely transmission projects could have on increasing the
percentage of renewable resources serving load in the West. Specifically, the report commented
with regard to location-constrained renewable resources that “[t]he key challenge for generation
development in these areas is to build new transmission capacity in a synchronized manner.”51
As such, this Project represents the type of coordinated and comprehensive transmission
development that meets the critical need (as well as the Commission policy) of linking remote
renewable resources to load centers throughout the West.52
51
See Exhibit No. 7 to Cupparo Affidavit.
52
See Department of Energy Report - 20% Wind Energy by 2030, Increasing Wind
Energy's Contribution to U.S. Electricity Supply, May 2008 at Chapter 4.2, 93 (concluding that if
the United States is to reach the 20% wind scenario by 2030, that "a significant amount of new
transmission will be required" as "[t]ransmission must be recognized as a critical infrastructure
(Footnote continued)
24
C.
The Requested Incentives Meet the Commission’s Nexus Test and Are
Rationally Related To The Project’s Risks and the Investment Being
Made
Order No. 679 requires a utility to demonstrate a nexus between the requested incentives
and the investment being made, i.e., that the incentives are “rationally related” to the investment
based on the facts of the particular case.53 In evaluating whether a utility has satisfied the
required nexus test, the Commission examines the total package of incentives being sought, the
inter-relationship between any incentives, and how the requested incentives address the risks and
challenges faced by the project.54 The Commission does not require a utility to demonstrate that
the project would not be built “but for” the requested incentives,55 and the Commission has
clarified that it retains the discretion to grant incentives that promote particular policy objectives,
unrelated to whether a project presents specific economic risks or challenges.56
1.
PacifiCorp Meets The Commission’s Nexus Test for a Non-Routine
Project
As part of its evaluation of whether the total package of requested incentives are tailored
to address the demonstrable risks or challenges faced by the applicant, the Commission considers
the question of whether a project is “routine” to be particularly probative.57 Among other things,
the Commission evaluates whether the project’s stated risks involve common issues faced by
element needed to enable regional delivery and trade of energy resources, much as the interstate
highway system does for the nation's transportation needs"). This report is available at
http://www1.eere.energy.gov/windandhydro/pdfs/41869.pdf.
53
Order No. 679, 116 FERC ¶ 61,057 at P 48.
54
Order No. 679-A, 117 FERC ¶ 61,345 at P 21.
55
Id at PP 21, 25; see also Bangor Hydro Elec. Co., 117 FERC ¶ 61,129 at P 105 (2006).
56
Order No. 679-A, 117 FERC ¶ 61,345 at P 21, n 37; see also Pacific Gas and Elec.
Co., 123 FERC ¶ 61,067 at P 33 (2008) (“PG&E”).
57
Baltimore Gas and Elec. Co., 120 FERC ¶ 61,084 at P 48 (2007) (“BG&E”), order on
reh’g, 123 FERC ¶ 61,262 (2008) (“BG&E Rehearing Order”).
25
other utilities in constructing transmission facilities in the normal course of business. Because
the purpose of rate incentives under Order No. 679 is to encourage construction of non-routine
regional transmission projects (routine projects are presumed to be undertaken as a matter of
good utility practice or obligation), the less routine a project is determined to be, the more likely
it is to merit rate incentives.58
To determine whether a project is not routine, the Commission will consider all relevant
factors including: (i) the scope of the project (e.g., dollar investment, increase in transfer
capability, involvement of multiple entities or jurisdictions, size, effect on region); (ii) the effect
of the project (e.g., improving reliability or reducing congestion costs); and (iii) the challenges or
risks faced by the project (e.g., siting, internal competition for financing with other projects, long
lead times, regulatory and political risks, specific financing challenges, other impediments).59
PacifiCorp’s Petition seeks a package of incentives that are narrowly tailored to address
the demonstrable risks and challenges that it faces in developing the Project. The incentives
proposed by PacifiCorp satisfy the required nexus test, as they are necessary to promote further
investment in the Project, to ameliorate the considerable financial and resource challenges that
the Project would impose upon PacifiCorp and to offset the substantial additional risks identified
58
Id., at P 54 (“By definition, projects that are not routine under [the Commission’s]
analysis … face inherent risks and challenges and/or provide benefits that are worthy of
incentives.”); Southern California Edison, 123 FERC at P 38 (While “the Commission will
consider applications for ROE incentives for all projects”. . . “the most compelling case for
incentive ROEs are new projects that present special risks or challenges, not routine investments
made in the ordinary course of business”) (internal citations omitted).
59
BG&E, 120 FERC ¶ 61,084 at P 52, n. 53 (The Commission has explained that “these
are only examples of evidence that can help inform the Commission on the question of whether a
project is routine” and that this is not a “new formulaic checklist that must be met by every
applicant for every proposed incentive or project”).
26
below. By any reasonable measure, this Project is non-routine, and is deserving of the requested
incentives.60
a.
Scope
As an initial matter, the immense size and financial scope of the Project supports a
determination by the Commission that PacifiCorp is entitled to such an incentive. The Project is
the very type of large scale interstate bulk transmission project that Congress intended to
encourage in EPAct 2005. By all reasonable measures, the size, scope, complexity, and purpose
of the Project is exceptional, far exceeding any of the proposed transmission projects that have
been granted incentive rate treatment by the Commission to date under Order No. 679.61 The
Project is intended to address regional needs and opportunities, including reliability, congestion
reduction and the transmission of renewable resources, and it will support compliance with
individual state renewable portfolio standards (“RPS”), to the extent that the acquisition of such
resources is cost-effective, by providing the necessary transmission to location-constrained
renewable resources.
In fact, the Commission has granted ROE incentives for projects that are much smaller
and provide fewer benefits than this Project.62 The Commission determined that smaller projects
60
See Order No. 679, 116 FERC ¶ 61,057 at P 24 (the Commission “must encourage
investors to take risks associated with constructing large new transmission projects that can
integrate new generation and otherwise reduce congestion and increase reliability. [The
Commission’s] policies also must encourage all other needed transmission investments, whether
they are regional or local, designed to improve reliability or to lower the delivered price of
power”).
61
Cupparo Affidavit at ¶ 64.
62
See, e.g., BG&E, 120 FERC ¶ 61,084 at PP 8-9 (authorizing a 100 basis point ROE
adder for two projects that involved replacing transformer banks and reconfiguring a switchyard
at two substations at a total cost of less than $100 million); Duquesne Light Co., 118 FERC ¶
61,087 (2007) (authorizing a 100 basis point adder for several upgrades to the transmission
system in the Pittsburgh area, costing $184 million).
27
with generally localized benefits, like BG&E and Duquesne, faced sufficient risk, and were
“non-routine” in nature such that they qualified for incentives. Accordingly, the case for
granting incentives for the Project is compelling, since, among other things, it involves an
undertaking of substantially greater geographic scale and financial commitment. Further, the
Commission has provided incentives to projects crossing only one state boundary and costing no
more than $1 billion on the basis that the attendant siting and regulatory risks justify the
treatment.63 By comparison, this Project, a six-state, multi-segment EHV transmission
expansion project necessitating construction of over 2,000 miles of new transmission lines,
substations and related facilities, at an estimated cost of $6 billion, must also satisfy the Order
No. 679 eligibility requirements.
b.
Effects
Once completed, the Project has the potential for realizing a number of benefits that are
consistent with significant policy objectives of the Commission. As discussed in the Cupparo
Affidavit, the Project is an integral part of the major transmission upgrades that are either being
planned or are underway in the NTTG footprint to address regional reliability issues, reduce
congestion, and provide transmission access to serve load by securing new energy supplies,
including renewable energy resources, in a manner that is expected to lower the delivered cost of
power for customers and to support compliance with RPS obligations in the western states.
63
See, e.g., Southern California Edison Co., 121 FERC ¶ 61,168 (2007), reh’g denied,
123 FERC ¶ 61,293 (2008) (granting ROE incentives for a set of transmission projects expected
to cost $2.3 billion involving 450 miles of construction and linking two states) (“SCE”); PPL
Electric Utilities Corp., et al., 123 FERC ¶ 61,068 (2008) (granting ROE incentives for a
proposed jointly-owned 130-mile transmission project spanning two states and estimated to cost
$900 million to $1 billion) (“PPL”).
28
Indeed, as described above, the Project is intended to alleviate many of the region’s major
constrained interfaces previously identified in government studies as needing improvements.
One key benefit of the Project will be to strengthen PacifiCorp’s existing ability to
withstand outages, thereby improving the overall reliability of PacifiCorp’s transmission system,
as well as that of the neighboring utilities. As the backbone for a future 500 kV infrastructure in
the Project footprint, the Project is anticipated to improve the ability of the existing Western grid
to transmit bulk power and to improve reliability, while at the same time preserving the existing
reliability of the underlying lower voltage systems. The Project has the potential to reduce the
need to curtail transmission schedules and associated energy access. Post-Project completion,
PacifiCorp will likely also have the ability to increase deliveries of energy from reserve sharing
pools in contingencies.
With respect to congestion reduction, the Project is anticipated to have the effect of
reducing the loading of highly used lines. This will prevent increased energy costs associated
with line loading, which prevents low cost energy from being delivered to demand areas. By
creating greater access from resource-rich areas to market access points, the Project has the
ability to facilitate a more efficient energy market and to reduce overall consumer costs. The
Project will also potentially contribute to reductions in overall net power costs and differentials
in pricing between multiple market points, as supported by numerous studies, and will reduce
overall line losses associated with lost generation needed to transport energy. This may
ultimately increase the benefits of economically-based energy transfers.
The Project also supports an important policy objective recognized by the Commission of
encouraging companies to explore new ways of finding and delivering renewable resources.64
64
See PG&E, 123 FERC ¶ 61,067 at P 33.
29
The significant infrastructure provided by the Project will facilitate the diversification of energy
resources, including renewables and traditional baseload resources and further the policy of
domestic energy independence. In this context, the Project specifically offers the opportunity to
further diversify intermittent resources on the grid with existing areas under development, which
may reduce the need to carry unnecessary reserves. Moreover, by providing the necessary
transmission to access location-constrained renewable resources, the Project supports compliance
with state RPS objectives, to the extent that the acquisition of such resources is cost-effective.65
c.
Risks and Challenges
Without question, PacifiCorp faces significant financial and regulatory risks in
developing and constructing a project of this magnitude. The Project constitutes precisely the
major, non-routine investment that the Commission had in mind when it observed that “the most
compelling case for incentive ROEs are new projects that present special risks or challenges, not
“’routine investments made in the ordinary course’” of business.”66
(1)
Financial Risk
Compared to PacifiCorp’s previous years’ transmission expansion expenditures, the
Project’s currently estimated $6 billion cost is substantial.67 As Mr. Cupparo explains, during
2002-2007, PacifiCorp spent an average of $111 million in capital expenditures annually on
65
By supporting one of the Commission’s policy objectives, the Project presents another
independent basis on which the Commission can grant the requested incentives. See SCE, 121
FERC ¶ 61,168 at P 45 (2007) (“[T]he Commission . . . retains the discretion to grant incentives
that promote particular policy objectives, unrelated to whether or not a project presents specific
economic risks or challenges”) (citing Order No. 679-A, 117 FERC ¶ 61,345 at n. 37) (footnote
omitted), Commissioner Wellinghoff concurrence at 2 (“In light of the broad and substantial
benefits associated with increasing the availability of renewable energy resources, I believe that
it is appropriate for the Commission to provide investment incentives in this area”).
66
SCE, 123 FERC ¶ 61,168 at P 38 (quoting Order No. 679-A, 117 FERC ¶ 61,345 at P
67
Cupparo Affidavit at ¶ 63.
60).
30
transmission projects; the average annual capital expenditure for the Project alone will be nearly
seven to eight times greater than PacifiCorp’s annual transmission expenditures during these
years.68 Moreover, the estimated $6 billion cost of the Project is more than three times
PacifiCorp’s current transmission rate base of $1.8 billion, and is nearly double the cost of the
next highest cost projects that have been granted incentives in response to petitions filed with the
Commission.69
Several other factors contribute to the enormity of PacifiCorp’s financial risk in
undertaking the development of the Project. First, PacifiCorp faces added risk by virtue of its
“first in time” status. As described above, the Project provides for the establishment of a 500 kV
transmission backbone that will improve reliability, reduce congestion, and provide access to
renewable resources across the Project footprint. However, in providing this 500 kV backbone,
PacifiCorp will be responsible for ensuring that the underlying system, within the Project’s
geographic footprint of Wyoming, Idaho and Utah, can withstand technical and regulatory
scrutiny, including the protection of neighboring electrical systems. Transmission developers
that come after PacifiCorp within this footprint will have the benefit of PacifiCorp’s experience
and technical upgrades. In this regard, PacifiCorp respectfully requests that the Commission
recognize PacifiCorp’s substantial risk in its pursuit of its groundbreaking Project.
The “first-in-time” phenomenon has been felt more acutely in PacifiCorp’s continuing
efforts to enlist business partners in the development of the Project. As currently contemplated,
the Project is capable of being upsized from a single-circuit to a double-circuit transmission
expansion for greater regional benefit. However, whether the Project is upsized depends on
68
Id.
69
See, e.g., Cupparo Affidavit and Appendix B.
31
whether regional participants are willing and capable of sharing in its costs and risks. PacifiCorp
continues to actively pursue third party equity partners, including investor-owned utilities and
public power entities, to join discrete portions of the Project, so as to facilitate broader regional
benefits. To date, however, such potential partners have been unwilling to fully commit to the
development of an upsized project of the scale that is described in this Petition.70
PacifiCorp’s financial risk is also impacted by the fact that its approach to the Project’s
development (siting the transmission lines ahead of the specific generation resources) departs
from past conventional approaches to developing transmission projects. Given the current
uncertainty of the role of conventional generation technology, and the inability of many
renewable developers to finance significant transmission investments, transmission cannot be
sited before specific generation resources have been developed. This approach presents greater
additional risks for transmission investment than the historical norm: a risk that is only magnified
by the scale and scope of the Project.
Yet another risk factor that PacifiCorp faces in the development of the Project is the
virtual certainty that the overall development costs, as measured in estimated 2008 dollars, will
likely change for reasons beyond PacifiCorp’s control. As the Commission itself has recognized,
the costs of construction have increased substantially over the past several years, and there is no
expectation that these increases will abate in the near future.71 It is no secret that the costs of raw
70
PacifiCorp anticipates making its final decision for moving forward with the Project on
a double- or single-circuit configuration basis later in the year. If no additional partners sign up
as co-sponsors for portions of the Project by that date, PacifiCorp will necessarily proceed on its
own.
71
See “Increasing Costs in Electric Markets,” Presentation, Commission Public Meeting
June 19, 2008 at 7-9 (powerpoint slides showing dramatic increases in capital and raw material
costs since 2000 for energy construction); Statement of Chairman Joseph T. Kelliher on Cost of
Electric Generation Staff Presentation, June 19, 2008 (noting the reality that “higher capital costs
(Footnote continued)
32
materials for energy infrastructure projects, such as iron, steel and copper, have increased
substantially, as the potential buyers for these materials are not just electric and natural gas
project developers in the United States, but are also developers located overseas. PacifiCorp also
anticipates increasing labor costs as Project construction progresses. The bulk of the Project’s
segments will be located in remote regions where the available labor supply is limited, and the
specialized personnel otherwise required for the construction of a project of this size may not be
easy to locate and hire. Obtaining and retaining the skilled labor necessary for the construction
of the Project presents a significant cost escalation risk.72
(2)
Regulatory Risk
PacifiCorp faces significant regulatory risks relating to local, state, and federal approval
and permitting processes that make its Project unique among previous incentive rate applicants.
The fact that no fewer than six states are involved in authorizing portions of the Project, and that
federal land management and tribal issues are implicated in its construction and development
further demonstrate the unprecedented scope of the Project. While PacifiCorp is taking all
necessary action to work with affected jurisdictions and their constituents, these proceedings are
expected to be prolonged and contested. As such, obtaining all of the necessary approvals, in a
timely cost-effective fashion, is far from certain. Any delay in obtaining the necessary local,
state and federal approvals will jeopardize the reliability, congestion and environmental benefits
associated with the Project. Such a risk presents the exact type of regulatory and political risk
for new power plants, higher construction costs, and higher fuel costs – will continue for some
time”). See Rebecca Smith, Costs to Build Power Plants Pressure Rates, WALL STREET
JOURNAL, May 27, 2008 at B3 (noting the inflationary risks associated with energy project
development).
72
Cupparo Affidavit at ¶ 70.
33
that the Commission has determined to be “relevant to determining whether [a transmission
project] is routine.”73
Further, with large portions of the Project expected to traverse federally-administered
lands, including in Idaho, Nevada, Oregon, Utah, and Wyoming, as well as through routes that
are not situated on existing right-of-ways (“ROWs”), PacifiCorp faces added authorization
complexities on a scale unlike previous transmission projects for which the Commission has
granted requested rate incentives. ROW applications have been filed, or will be filed with the
Bureau of Land Management (“BLM”) and the United States Forest Service (“USFS”), and other
federal agencies, as applicable. These agencies will consider various factors during the review
process, including alternatives to the Project, route alternatives and potential environmental
impacts and mitigation measures. As an illustration, the Gateway West portion of the Project is
not anticipated to obtain the necessary ROW authorization until late 2010 at the earliest,
according to the BLM Project Manager.74 This introduces additional risk to the Project in the
73
BG&E Rehearing Order, 23 FERC ¶ 61,262 at n. 42. In light of escalating capital
expenditure costs, PacifiCorp also faces potential litigation risk related to formal challenges
seeking to limit any incentives that it may otherwise receive from the Commission after-the-fact.
See “Complaint of the New England Conference of Public Utilities Commissioners, Inc.,
Seeking Limitation on Amount of Transmission Costs to which Incentive ROE Adder Applies,”
Docket No. EL08-69-000 (June 12, 2008) (complaint filed under Section 206 of the FPA seeking
to limit application of ROE cost adder for certain qualified projects in ISO-New England two
years after Commission order originally granting incentives due to the escalating costs of the
transmission projects qualifying for the ROE adder).
74
See Dustin Bleizeffer, Officials Lay Out Power Line Project, CASPER STAR-TRIBUNE
(June 10, 2008), available at
http://trib.com/articles/2008/06/10/news/casper/c4ad3235b59ce7158725746400009725.txt
(quoting Wyoming BLM Project Manager).
34
form of siting delays and potential re-routing of various portions of the Project that will
inevitably add to the overall cost and time completion of the Project.75
Finally, as noted earlier, state regulators will be asked to include in PacifiCorp’s retail
rate base all of this transmission investment, including that portion that represents investments
for reliability and future growth. PacifiCorp faces a risk that state regulators will not include all
of the investment in retail rates if the benefits to retail customers are not proven to be sufficient.
(3)
Technology Risk
The Project also faces uncommon technology-related risks because of PacifiCorp’s
contemplated investment in several advanced transmission technologies that have not been
widely deployed. Reliance on novel technologies inherently poses increased risks in the form of
added uncertainty as to how they will perform within the context of the larger Project. As
described in the Cupparo Affidavit and as noted further below, PacifiCorp plans on utilizing
Trapezoidal Conductors, a newer form of technology that allows transmission lines to conduct at
more than twice the accepted temperature limit of more conventional lines, as well as Fiber Optic
Shield Wires that assist in enhancing the functionality and reliability of the Project’s
transmission lines. The use of these and the other innovative technologies described herein must
be designed, constructed and tested to ensure they meet the requirements of the Project.
2.
The Total Package of Requested Incentives Are Necessary to
Compensate PacifiCorp for the Unique and Substantial Risks Posed
by the Multi-State Project
As demonstrated herein, the Project represents the type of large scale interstate
transmission project that Congress intended to encourage in EPAct 2005. From a broader policy
perspective, granting PacifiCorp a 250 basis point ROE adder and authorization to seek
75
See PPL, 123 FERC ¶ 61,068 at P 37 (acknowledging that siting issues associated with
securing ROE approvals “can be both protracted and challenging”).
35
prudently-incurred abandonment costs in a future rate filing fulfills and reinforces the goals of
Congress of encouraging and compensating those who undertake significant regional bulk power
transmission projects that benefit customers by ensuring reliability or reducing congestion.76 In
addition, a favorable ruling on this Petition may attract greater participation from potential equity
partners.
The Project merits an ROE enhancement above and beyond all other project-specific
ROE basis point adders previously approved by the Commission.77 As noted by Mr. Cupparo, it
represents the largest, most ambitious transmission project when compared to other projects for
which incentive rate treatment has been sought under Order No. 679 and its progeny, and this
Petition demonstrates that the Project offers broad customer benefits by addressing regional
needs and opportunities, including improved reliability, congestion reduction, transmission
access for renewable resources and deployment of advanced transmission technologies.78
Granting PacifiCorp an ROE adder of 250 basis points reasonably compensates PacifiCorp and
its investors for the unique and substantial risks attributable to the Project, and facilitates the
completion of the Project by, among other things, encouraging PacifiCorp to devote the
necessary management, regulatory and political attention in order to see this Project to fruition.
As described below in the Advanced Technology Statement, PacifiCorp intends to use a
number of advanced technologies, as defined by Section 1223 of EPAct 2005 and Order No. 679,
in the construction of portions of the Project. PacifiCorp is investing in these technologies based
76
Order No. 679, 116 FERC ¶ 61,057 at P 7.
77
See Appendix B.
78
Cupparo Affidavit at ¶ 64 (“The projected capital investment is nearly double the
highest capital investment projected among projects previously granted incentive rate
treatment”).
36
on its expectation that they will improve reliability and project efficiency, just as the
Commission intended in Order No. 679-A. However, as explained in the Cupparo Affidavit,
using and obtaining the benefits of these advanced technologies pose several unique risks and
challenges.79 As such, a portion of PacifiCorp’s 250 basis point ROE adder request is intended
to help compensate for the costs of the portion of the Project utilizing such advanced
technologies.
In its ongoing efforts to develop and construct the Project, PacifiCorp will incur
significant costs to determine whether the Project is feasible from a financial, environmental,
regulatory and a siting perspective. Indeed, PacifiCorp anticipates spending approximately $70
million alone on continued planning, studies, and permitting and design activities associated with
the Project. Accordingly, PacifiCorp requests authorization to recover 100 percent of its
prudently incurred transmission–related development and construction costs in the event the
Project is cancelled or abandoned, in whole or in part, due to an action or inaction by a
governmental authority, regulatory agency, or for other reasons beyond PacifiCorp’s control.
In Order No. 679, the Commission held that the abandoned plant rate incentive is an
effective means to encourage transmission development by reducing the risk of non-recovery of
costs.80 The incentive is available to any applicant that can show that any such abandonment is a
result of factors beyond its control; this demonstration could be made in any subsequent section
79
Id. at ¶ 69.
80
Order No. 679, 116 FERC ¶ 61,057 at P 163; see also Order No. 679-A, 117 FERC ¶
61,345 at P 115 (explaining that an abandoned plant incentive “may be needed (and requested) in
advance of a project being approved through a regional planning process or receiving any
necessary siting approvals. To the extent an applicant demonstrates that the incentives sought . .
. are tailored to address the demonstrable risks and challenges of the applicant, we will permit
recovery of such prudently-incurred costs”).
37
205 filings for recovery of abandoned plant.81 The Commission has in recent cases granted
similar requests for such recovery.82 In previously granting a requested abandonment incentive
where only two states were involved, the Commission noted that “[d]ependence upon approval
by multiple jurisdictions introduces a significant element of risk to the [transmission p]roject that
is not faced by utilities building transmission facilities within a single jurisdiction.”83 Given the
scope and complexity of the Project, the same conclusion holds true in this circumstance.
PacifiCorp submits that this incentive will be an effective means to encourage the
completion of its Project. The Project faces several risks that no other applicant for rate
incentives has encountered before, including approvals from six different states, along with
various federal approvals from BLM and USFS. Moreover, the capital commitment that will be
required in a time project of this magnitude will be substantial. PacifiCorp plans to capitalize its
construction financing costs through accrual of AFUDC. However, under this approach,
PacifiCorp will not be able to recover its expenditures related to the construction of the Project or
to earn its allowed rate of return until the segments of the Project are placed in service. Because
PacifiCorp is not seeking an incentive to include CWIP in rate base or the recovery of precommercial costs, it faces additional exposure related to its significant capital investment absent
the incentive for recovery of costs in the event some or all of the Project was abandoned before
being placed in service.
81
Order No. 679, 116 FERC ¶ 61,057 at PP 165-66.
82
See Allegheny Energy Inc., 116 FERC ¶ 61,058 at P 122 (2006), Southern California
Edison Co., 112 FERC ¶ 61,014 at PP 58-61 (2005), reh’g denied, 113 FERC ¶ 61,143 (2005);
Duquesne, 118 FERC ¶ 61,087 at P 61.
83
SCE, 121 FERC ¶ 61,168 at P 72.
38
As conceived, PacifiCorp is under no federal or state obligation to construct this scale of
a project, other than general service obligations. However, PacifiCorp has voluntarily decided to
move forward with its development for the reasons stated throughout this Petition. The overall
risks associated with building the Project are not fully mitigated by an abandonment incentive.
In contrast to past petitioners that have sought incentives under Order No. 679, PacifiCorp
receives over ninety percent of its recovery on transmission investment through its native load
retail ratemaking processes. As such, Commission-authorized transmission incentives, such as
abandonment and CWIP, do not provide significant protection against loss of recovery of
investment dollars for factors outside of PacifiCorp's control Accordingly, such an incentive
could never compensate PacifiCorp for the costs incurred as a result of choosing to spend
billions of dollars and several years on a regulated electric transmission project. Reducing
PacifiCorp's requested 250 basis point ROE adder on the basis that it has been granted the
abandonment incentive would misalign the scope of PacifiCorp's risks with its narrowly tailored
incentive package.
In Order No. 679-A, the Commission clarified that its nexus test is met when an applicant
demonstrates that the total package of incentives requested is tailored to address the
demonstrable risks or challenges faced by the applicant. The Commission further held that this
nexus test is fact-specific and requires the Commission to review each application on a case-bycase basis. Consistent with Order No. 679,84 the Commission has consistently approved multiple
rate incentives for particular projects85 in accordance with its policy that each incentive must be
84
Order No. 679, 116 FERC ¶ 61,057 at P 55.
85
See, e.g., Allegheny Energy, Inc., 116 FERC ¶ 61,058, at P 60, 122 (2006) (approving
ROE at the upper end of the zone of reasonableness and 100 percent abandoned plant recovery);
(Footnote continued)
39
justified by a showing that it satisfies the requirements of Section 219 and that there is a nexus
between the incentives being proposed and the investment being made. The same result is
warranted here.
This Petition does not seek pre-commercial operational costs, CWIP or any other
incentive described by the Commission. As a six-state utility, PacifiCorp has narrowly tailored
its request to those incentives that will most efficiently facilitate the continued development of
the Project, while accounting for the critical regulatory differences between PacifiCorp and other
utilities in the West. For purposes of establishing retail rates, PacifiCorp applies an allocation
methodology to determine how costs and revenues associated with PacifiCorp’s generation,
transmission and distribution system will be assigned or allocated among its six state
jurisdictions. PacifiCorp’s unique multi-state operations necessitates that it place a premium on
ensuring consistency between state and federal ratemaking procedures. Accordingly, PacifiCorp
has elected to forego any incentives that may compromise efficiencies and ratemaking clarity
among its state jurisdictions, either in the short-term or in the long-term.
PacifiCorp has demonstrated, consistent with Order No. 679-A, that the total package of
incentives is tailored to address the demonstrable risks or challenges faced by the Project.86 The
specific incentives sought by PacifiCorp are not mutually exclusive, and are in fact compatible
because they serve different purposes. Granting the ROE incentive, together with abandoned
plant recovery, will help PacifiCorp justify the extraordinary financial investment that will be
required to build the Project.
Duquesne, 118 FERC ¶ 61,087 at P 55 (granting an enhanced ROE, 100 percent CWIP, and 100
percent abandoned plant recovery).
86
Order No. 679-A, 117 FERC ¶ 61,345 at P 21, 27.
40
D.
The Commission Should Authorize The Requested Incentives
The Commission does not require that a utility demonstrate that a particular project
would only be built if the requested incentives are obtained. Such a test would impose an
impossible hurdle for applicants and would be inconsistent with the fundamental objective of
Section 219 of the FPA and the Commission’s current policy of encouraging new transmission
construction that helps ensure reliability of the bulk power transmission system and/or reduce the
cost of delivered power by reducing transmission congestion.87 Therefore, the nexus between
PacifiCorp’s proposed Project and the requested incentives should be viewed within the context
of PacifiCorp’s commitment to the Project, and its overall commitment to improving reliability,
reducing congestion, promoting renewable energy resource development and advanced
transmission technology utilization, and the positive correlation between that commitment and
the requested incentive rate treatment. The requested rate treatment will foster PacifiCorp’s
continued commitment to such goals, consistent with important state and federal policy
objectives.
Indeed, denial of the requested rate treatment would be at odds with the objectives of
Section 219 of the FPA, and the Commission’s policy of “encourage[ing] investors to take risks
associated with constructing large new transmission projects that can integrate new generation
and otherwise reduce congestion and increase reliability.”88
VI.
ADVANCED TECHNOLOGY STATEMENT
Order No. 679 requires applicants for incentive rate treatment to include a technology
statement with their requests describing any advanced technologies that have been considered
87
Id. at P 25; Bangor Hydro Elec. Co., 117 FERC ¶ 61,129 at PP 93 and 105.
88
Order No. 679, 116 FERC ¶ 61,057 at P 24.
41
and, if not employed, an explanation of the reasons why they were not.89 Section 1223(a) of
EPAct 2005 defines “advanced transmission technology” to mean “a technology that increases
the capacity, efficiency, or reliability of an existing or new transmission facility . . .” and
provides a non-exclusive list of examples that satisfy this definition.90 To the extent that a
transmission project intends to use advanced technologies that will increase efficiency, and will
enhance grid operations and reliability, thus contributing to system-wide benefits, the
Commission will view favorably in its determination of whether the project is worthy of an
incentive ROE adder.
As noted in the Cupparo Affidavit, PacifiCorp is committed to optimizing the technology
that will be utilized by the Project. Subject to further study and final engineering, PacifiCorp
intends to utilize several types of advanced technologies in connection with various segments of
the Project. All of these technologies meet the standard set forth in Order No. 679, and in
Section 1223 of EPAct, as they mitigate congestion and enhance grid reliability by increasing the
capacity, efficiency and reliability of an existing or new transmission facility. Falling into the
following statutory categories of advanced conductor technology, enhanced power device
monitoring, fiber optic technologies, power electronics and other technologies, PacifiCorp
intends to invest in the following advanced technologies for use in its Project.
89
Id. at P 302.
90
EPAct 2005, § 1223(a). The Commission regards this statutory list as being illustrative
of the kinds of technologies encouraged by Congress, but not otherwise exclusive of the
advanced technologies that can determine whether a project is deserving of incentive rate
treatment. Section 1223 also provides that advanced transmission technologies include any other
related technologies that the Commission considers appropriate.
42
A.
Advanced Technologies to be Used By the Project
1.
Trapezoidal Conductor91
PacifiCorp intends on utilizing Trapezoidal Conductor technology in its Project. This
technology involves the use of Aluminum Conductor Steel Supported/ Trapezoidal Wire
(“ACSR/TW”), which can conduct at more than twice the accepted temperature limit of
conventional Aluminum Conductor Steel Reinforced. The purpose of deploying such an
advanced conductor design is to increase transmission capacity, and to reduce the sag of the
transmission lines as well as reduced line energy losses.
To this end, PacifiCorp commissioned an expert to compare and contrast several
particular types of conductors under certain load factor assumptions to determine which offered
the highest overall value for customers. The study revealed that the Lapwing TWD reduced line
loss at a higher rate and with more overall benefit than the other conductors considered over the
life of the Project’s facilities. The use of this technology provides long term benefits to
customers and to connected generation. However, it also carries investment risk associated with
any large capital expenditure depending on long term benefit streams. Nonetheless, PacifiCorp
chose to undertake this risk in order to promote energy efficiency and to reduce the need for
future resources which would have otherwise been needed to offset transmission line losses.92
PacifiCorp estimates that use of these advanced technologies on the Project’s proposed
500 kV lines will provide substantial incremental benefits over conventional alternatives. For
example, as the Cupparo Affidavit explains, the ACSR-TW conductor will help avoid more than
120,000 MWhs of energy losses annually for the life of the Project over standard ACSR
91
Cupparo Affidavit at ¶¶ 51-52.
92
Cupparo Affidavit at ¶ 51.
43
conductor, and could approximately double those avoided losses for segments that are
constructed to 500 kV double circuit configuration. As Mr. Cupparo further states, an estimated
60,000 to 120,000 metric tons of carbon dioxide (“CO2”) could be avoided annually for the base
Project as a result of applying this technology.93 In this way, the Project’s use of advanced
technology captures Commissioner Wellinghoff’s goal of “increase[ing] efficiency, enhanc[ing]
grid operations and reliability, and result[ing] in greater grid flexibility, thus benefiting all users
of the grid and ultimate consumers,”94
2.
Static VAR Compensators95
PacifiCorp will use Static VAR Compensators (“SVCs”) in the Project. SVCs are
electrical devices used to automatically match impedance to regulate voltage. SVCs also
improve both dynamic and transient network stability, and are useful when placed near high and
varying loads as they can smooth flicker voltage. The loadability of a transmission line is highly
dependent on the line length. In order to increase line loadability and to balance phase voltages,
PacifiCorp is evaluating the installation of SVCs on several Segments of the Project (including at
several of the designated hubs). The intended use of SVC technology would not only support the
required dynamic voltage regulation and the “firming up” of the system, it is also expected to
improve reliability, power quality, contingency recovery, create operational benefits to support
the deliverability of intermittent renewable energy sources as well as to help maximize the
overall total transfer capability. The use of SVCs in the Project involves the use of relatively
93
Cupparo Affidavit at ¶ 52.
94
See, e.g., Potomac-Appalachian Transmission Highline, LLC., 122 FERC ¶ 61,188
(2008) (separate statement of Commissioner Wellinghoff at 2-4); PPL Electric Utilities Corp.,
123 FERC ¶ 61,068 (2008) (separate statement of Commissioner Wellinghoff at 2).
95
Cupparo Affidavit at ¶ 53.
44
new solid state transient power and voltage control technology that helps avert the need for
additional transmission infrastructure, including additional transmission line facilities, which
would otherwise be needed solely to regulate voltage and to maintain system stability.
3.
Fiber Optic Shield Wires96
PacifiCorp plans to use fiber optic technology in the Project. The use of this type of
technology will provide several benefits that will enhance Project operations and efficiency. For
example, PacifiCorp is planning to use fiber optic shield wires that will protect transmission lines
by shielding phase conductors from direct lightning strikes. Fiber optic cable, in lieu of wave
trap or microwave technology, allows a communications link to overhead transmission lines. In
addition, shield wires with fiber optic cores enable the novel application of differential line
protection, a superior technique borrowed from transformer protection that reliably detects short
circuits. Fiber optic shield wires will also provide high-capacity, high-speed communication
channels allowing system dispatchers to switch facilities remotely and reliably for voltage
control, assist in the maintenance of grid reliability and security, and aid the engineering and
maintenance staff in performing diagnostics of the remotely-located equipment.
PacifiCorp is voluntarily incorporating the use of fiber optic technology to provide a
more reliable communication path to operate the Project’s transmission facilities. The
installation of fiber optic technology can also create additional latent capacity bandwidth, which
while not currently anticipated to be used outside the operation of the transmission system, could
also provide an alternate secure communication path that could be used for national security and
regional development purposes.
96
Id. at ¶¶ 54-55.
45
4.
Phase Shifters97
Phase shifters are intended to be utilized by PacifiCorp in the operation of the Project.
Phase shifters improve and/or increase stability limits of transmission lines when the maximum
power transfer is reached by changing the alternating current phase angle between the sending
and receiving ends of the line. Specifically, the use of this technology maximizes the utilization
of existing and newly installed transmission system assets by regulating alternating current
(“AC”) power flows in both magnitude and direction. In this way, phase shifters help provide
operational and seasonal flexibility, and allow the dispatch of flow patterns required to maximize
the grid and to provide operational benefits during contingencies. PacifiCorp is pursuing
targeted applications of this technology to reduce overall system losses by eliminating circulating
currents, and helping to protect neighboring transmission systems. Phase shifters are a
technology primarily used in the Western Interconnection due to the large number of highvoltage, long-distance transmission lines that are located in this region of the country.
The use of phase shifters on the Project can reduce the detrimental impact of new
transmission facilities on the existing underlying transmission system. Using this technology
avoids the need for additional transmission infrastructure, including additional transmission line
facilities, which would otherwise be needed solely to mitigate inadvertent transfer path flows on
neighboring electric systems.
5.
Special Protection Schemes98
PacifiCorp intends to employ Special Protection Schemes (“SPS”) to respond to system
events and disturbance data that could potentially cause undue stress on its system. PacifiCorp
97
Id. at ¶¶ 56-57.
98
Id. at ¶ 58.
46
will employ advanced SPS technology as necessary to maximize grid total transfer capability,
improve long-term reliability and reduce negative impacts to the interconnected systems, as well
as to benefit the interim ratings of the lines. SPS technology will also be used to reduce the need
for additional transmission infrastructure that would otherwise be needed only in extreme
contingency situations. Despite having the benefit of avoiding redundant transmission
construction, SPS technology places connected generation at risk for tripping to avoid creating
an unstable system condition in the event of a transmission facilities outage.
6.
Monitors for Transformers and Phase Shifters99
PacifiCorp is evaluating the use of advanced monitors in transformers at the new
substations planned as part of the Project. PacifiCorp will employ the use of such technologies
for real-time measurement and monitoring of dissolved combustible gases in oil filled
equipment. This technology provides real-time monitoring of highly combustible gases (such as
acetylene, hydrogen, methane and oxygen) that are dissolved in power equipment insulating oil,
and will provide notification when the affected equipment is near failure. These monitors can
improve the reliability of the Project, and can help insure that the transmission assets safely reach
their useful expected life span. This technology, while not required by reliability standards,
helps protect high-cost investments and improve reliability by providing for early detection of
potential issues.
B.
PacifiCorp’s Decision to Forego the Use of Certain Advanced
Technologies
PacifiCorp considered, but does not currently plan to adopt, other types of advanced
technologies. For example, PacifiCorp has evaluated the use of advanced composite core
99
Id. at ¶¶ 59-61.
47
conductors for the Project, and is using this technology on a limited basis on a small portion
of Segment B by rebuilding an existing line with this technology to accommodate the new
double-circuit 345 kV line. However, this technology is not economically justified on other
portions of the Project, given the use of Trapezoidal conductor technology on the 500 kV
facilities. In a similar vein, PacifiCorp decided to forgo the use of underground conductors on
the Project, as the capital costs were multiples of overhead construction configurations, and
would have rendered the Project economically unfeasible.
Another type of technology that PacifiCorp has opted not to use in the Project is direct
current (“DC”) technology. This technology will not be used so as to better optimize
PacifiCorp’s ability to flexibly interconnect with the current and future additions to the existing
alternating current system, and to best allow generation interconnection at intermediate points.
The use of AC technology on the Project allows future projects to build off of the backbone that
the Project will form in the Wyoming, Idaho, and Utah areas. DC technology can cause
technology feasibility concerns when more terminals are used on a line. As such, a DC project
can have a limited ability to interconnect with future projects and with generation additions at
intermediate points. DC technology also may not have the direct benefit of strengthening the
ability of the underlying network alternating current system to resist voltage stability
disturbances. The AC configuration used on the Project will best meet these reliability and
flexibility objectives.
48
Appendix A
Affidavit of John Cupparo
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
)
PacifiCorp
)
)
Docket No. EL08-___-000
AFFIDAVIT OF
JOHN CUPPARO
ON BEHALF OF PACIFICORP
1
Appendix A
Affidavit of John Cupparo
Table of Contents
Page
I.
INTRODUCTION AND EXPERIENCE.........................................................................3
II.
PURPOSE...........................................................................................................................4
III.
OVERVIEW OF PACIFICORP’S TRANSMISSION SYSTEM .................................4
IV.
ENERGY GATEWAY TRANSMISSION EXPANSION PROJECT ..........................5
V.
A.
Overview .................................................................................................................5
B.
Project Development..............................................................................................8
1.
Walla Walla to McNary – Segment A ......................................................8
2.
Populus to Terminal – Segment B ............................................................9
3.
Mona to Limber to Oquirrh– Segment C ..............................................10
4.
Windstar to Aeolus to Bridger – Segment D .........................................10
5.
Bridger to Populus to Hemingway– Segment E ....................................11
6.
Aeolus to Mona – Segment F...................................................................11
7.
Sigurd to Red Butte to Crystal – Segment G.........................................11
8.
Hemingway to Captain Jack– Segment H .............................................12
THE PROJECT IS THE RESULT OF A FAIR AND OPEN REGIONAL
TRANSMISSION PLANNING PROCESS...................................................................12
A.
Overview ...............................................................................................................12
B.
The Project Has Been Designated By NTTG As A Critical Fast Track Project
And Is Now Proceeding Through The WECC Process ....................................15
VI.
THE PROJECT IS ELIGIBLE FOR INCENTIVES...................................................18
VII.
ADVANCED TECHNOLOGIES ...................................................................................24
A.
Trapezoidal Conductor .......................................................................................24
B.
Static VAR Compensators (SVCs) .....................................................................25
C.
Fiber Optic Shield Wires.....................................................................................26
D.
Phase Shifters .......................................................................................................27
E.
Special Protection Schemes.................................................................................27
F.
Monitors for Transformers and Phase Shifters ................................................28
VIII. RISKS AND CHALLENGES FACED BY PACIFICORP..........................................29
Appendix A
Affidavit of John Cupparo
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
)
PacifiCorp
)
)
Docket No. EL08-___-000
AFFIDAVIT OF
JOHN CUPPARO
ON BEHALF OF PACIFICORP
I.
INTRODUCTION AND EXPERIENCE
1.
My name is John Cupparo and I am Vice President of Transmission for PacifiCorp. My
business address is 825 NE Multnomah Street, Portland, Oregon, 97232.
2.
I have a Bachelor of Science degree in Computer Information Systems from Colorado
State University. My experience spans 23 years in the energy industry, including oil, gas
and electric utilities. The majority of my experience has been in information technology
supporting natural gas pipelines, energy commodity trading and end-to-end electric utility
operations. I have been employed at PacifiCorp since September, 2000. Prior to
assuming my current position in August 2006, I was Chief Information Officer for
PacifiCorp. My responsibilities have covered many aspects of utility operations –
commercial and trading, outage management, customer service, transmission scheduling
and regulatory issues. My experience within PacifiCorp includes management of multifunction organizations, large project delivery and resolving complex scheduling and
contract scenarios. I am responsible for all aspects of PacifiCorp’s transmission
investment strategy, customer service, main grid planning, contract administration and
tariff management. I am the co-chair of the Northern Tier Transmission Group
3
Appendix A
Affidavit of John Cupparo
(“NTTG”) which coordinates transmission planning, and transmission expansion and
project reviews with sub-regional and regional planning organizations within the Western
Electricity Coordinating Council (“WECC”).
II.
PURPOSE
3.
My Affidavit provides an overview of PacifiCorp’s transmission system and describes
the new Energy Gateway Transmission Expansion Project (“Project”) for which
PacifiCorp is seeking incentive rate treatment. Energy Gateway is a major, multi-state
project designed to address regional reliability issues, reduce congestion, serve load,
secure energy supply, and/or provide transmission access to new renewable energy
resources in a manner that is expected to lower the delivered cost of power for customers
and to meet RPS compliance obligations in the western states. My Affidavit describes
the pressing need for investment in new transmission infrastructure in the West, as
demonstrated by the Department of Energy’s (“DOE”) National Electric Transmission
Congestion Study and other transmission studies. I will explain the process by which the
company coordinates transmission planning and project review with stakeholders,
including participation in the NTTG sub-regional and the WECC regional planning
process. I also identify and explain the advanced technologies intended to be used by
PacifiCorp as part of the Project. Finally, my Affidavit demonstrates the Project’s
eligibility for incentives and describes the risks and challenges that the company faces in
connection with the Project.
III.
OVERVIEW OF PACIFICORP’S TRANSMISSION SYSTEM
4.
PacifiCorp is an indirect, wholly-owned subsidiary of MidAmerican Energy Holdings
Company (“MidAmerican”). PacifiCorp provides delivery of electric power and energy
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to approximately 1.7 million electric customers in six western states. The company
operates as Pacific Power in Oregon, Washington and California, and as Rocky Mountain
Power in Wyoming, Utah and Idaho. PacifiCorp owns and operates approximately
15,494 miles of transmission lines ranging from 46 kV to 500 kV across ten states. As of
December 31, 2007, PacifiCorp’s current net transmission plant in service is
approximately $1.8 billion. PacifiCorp is interconnected with more than 80 generation
plants and 15 adjacent control areas at approximately 124 points of interconnection. To
provide electric service to its customers, PacifiCorp owns, or has interest in, generation
resources directly interconnected to its transmission system with a system peak capacity
of approximately 12,131 MW. This generation capacity includes a diverse mix of coal,
hydro, wind power, natural gas-fired combined cycles and combustion turbines, and
geothermal capacity.
5.
Transmission capacity on PacifiCorp’s existing transmission system is at or near full
utilization. The company’s most recent Integrated Resource Plan (“IRP”) identifies the
need for investment in major new transmission facilities to meet forecasts of customers’
electricity usage, and to help satisfy renewable portfolio standards throughout its service
territory. PacifiCorp’s existing transmission system, as well as the transmission grid
across the western region, is severely constrained, and numerous regional study groups
have identified the pressing need for investment in new transmission infrastructure.
IV.
ENERGY GATEWAY TRANSMISSION EXPANSION PROJECT
A. Overview
6.
The Project is a system-wide transmission expansion program, first announced by
PacifiCorp in May, 2007. The Project will traverse six states, numerous communities and
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areas of federally-administered lands. Community outreach, siting, permitting and design
work are underway for many segments of the multi-phased project that will add
approximately 2,000 miles of new transmission lines and related improvements to the
PacifiCorp transmission system. The Project will enhance reliability, reduce transmission
congestion and improve the flow of electricity throughout the region. The Project’s 500
kV transmission lines will be the first such lines to be installed in the Project footprint
(primarily Wyoming, Idaho and Utah), and the infrastructure will provide an essential
reliability bedrock that will contribute to the addition of future 500 kV transmission lines
in the region.
7.
The Project will connect areas rich in energy resources to load centers, enabling access to
markets for the development of new energy resources, including renewables. For
example, Wyoming currently has more than 10,000 MW of wind resources associated
with pending requests for interconnection to PacifiCorp’s transmission system. The
Project will move power generated from these and other new renewable resources
planned to be developed in Wyoming to customer growth areas in Wyoming, Utah and
Oregon.
8.
The Project is primarily driven by the long-term needs of PacifiCorp’s retail and network
customers. Upgrades to core elements of the Project (e.g., installation of double-circuit,
rather than single-circuit, 500 kV transmission lines) may be required if other participants
express interest in portions of the Project (Idaho Power has agreed to participate in
portions of Gateway West) or if the Company receives commitments from parties with
pending requests for points of new interconnection.
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9.
The Project will provide the first direct interconnection between the Rocky Mountain
Power and Pacific Power service areas, and it will help PacifiCorp ensure that its system
is adequate and capable of meeting forecasted needs. PacifiCorp estimates that the entire
project, or substantial elements of the project, will be completed in 2014, subject to
schedule variations as necessary, at a cost of approximately $6 billion, as adjusted for
inflation, and based on current estimates including Allowance for Funds Used During
Construction (“AFUDC”)The Project is the first transmission investment of this scale in
the western region in the last 15 years, and it represents a 330% increase to PacifiCorp’s
current net transmission investment.
10.
The Project is designed to provide an enhanced transmission delivery system utilizing
major extra-high voltage (“EHV”) transmission lines. The Project will connect areas
with abundant existing and potential generation resources, including renewables
(“resource hubs”), with concentrated areas of customer load (“load centers”) throughout
the PacifiCorp’s system, and it may enable future EHV projects within the region to rely
upon and to expand this backbone infrastructure, if needed. The significant improvement
to critical transmission capacity and the “hub and spoke” design will provide flexibility,
improve efficiency and enable development of (and access to markets for) clean and
renewal energy resources, such as wind.
11.
The Project is a challenging undertaking. In terms of dollars of investment, miles of
transmission lines and number of states traversed, the Project is larger than any of the
recent transmission expansion projects presented to the Commission, and found eligible
for incentives.
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B. Project Development
12.
Development for a project of this magnitude must necessarily be undertaken in segments
and the segments must be prioritized to maximize reliability and integration benefits,
while incorporating the necessary flexibility in construction sequencing to prudently
deliver all of the Project segments. The Project consists of eight segments located within
four sub-regions, as shown on the Energy Gateway map provided in Exhibit No. 1.
Project segments that offer similar general benefits and in-service dates have been
grouped into levels of priority, with the goal of having the earliest prioritized groups in
service and supporting the reliable construction of later groups. Project segments
undertaken at the Priority One level are intended to reinforce reliable service to the
company’s base load. Project segments undertaken at the Priority Two level are intended
to support deliveries of wind energy and resource diversity. Project segments included in
the Priority Three level are undertaken to enhance the integration of PacifiCorp’s east and
west control areas, and to further support delivery of renewable energy. Project segments
included in the Priority Four level are intended to provide reliability backup and ratings
support for the grid. The priority levels allow PacifiCorp to exercise flexibility to adjust
for cost and resource pressures and to accommodate potential third-party participation.
13.
Priority level and transmission lines for each of the eight segments of the Project are
summarized below.
1. Walla Walla to McNary – Segment A
14.
A Priority One level project, Segment A is part of the Energy Gateway that will satisfy a
transaction commitment made by MidAmerican in its acquisition of PacifiCorp, among
other things. Estimated to cost $108 million, a 230 kV transmission line will run
approximately 56 miles between Walla Walla, Washington and Umatilla, Oregon, and
8
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connect existing power substations at Walla Walla, Wallula and McNary. When
completed in 2010, this segment will be the first leg of the Project to be placed in service,
and it could be used to link existing and future sources of renewable resources.
2. Populus to Terminal – Segment B
15.
Also a Priority One level project, Segment B is part of Gateway Central. Double circuit
345 kV transmission lines will run from a new Populus substation near Downey, Idaho,
135 miles south to the existing Terminal substation near the Salt Lake International
Airport west of Salt Lake City, Utah. This segment is estimated to cost approximately
$800 million and will be constructed in two sections. The first section will link the new
Populus substation with the existing Ben Lomond substation north of Ogden, Utah. The
second section will link Ben Lomond with the Terminal substation. Both sections of
Segment B are anticipated to be placed in service in 2010, and are intended to deliver
reliable power to the growing load demand along the Wasatch front in Utah.
16.
PacifiCorp has submitted an application for certificate of public convenience and
necessity for the Populus to Terminal transmission line and the new Populus substation to
the Idaho Public Utilities Commission (“IPUC”), and a similar application for the
transmission line to the Utah Public Service Commission (“UPSC”). PacifiCorp
anticipates approval by October 2008 and September 2009, respectively.
17.
Segment B will supplement a constrained path in Utah known as Path C. During its
acquisition of PacifiCorp, MidAmerican agreed to increase transfer capacity on Path C by
300 MW. In fact, Segment B will increase transfer capacity by 1,400 MW when
combined with other segments of the Project. As such, Segment B will significantly
improve a point of constraint on the system that currently affects numerous transmission
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customers, strengthen reliability and enable the company to achieve the planned transfer
capability rating of subsequent Project segments.
3. Mona to Limber to Oquirrh– Segment C
18.
A Priority One level project, Segment C is part of Gateway Central. The new line,
estimated to cost $425 million, will run approximately 86 miles north from the existing
Mona substation in central Utah to two future substations (Limber and Oquirrh). Double
circuit 500 kV/345 kV transmission lines are intended to improve reliability and
operational flexibility of the electrical system, and to link distant generation resources to
one of the fastest growing areas in Utah. Segment C fulfils and expands upon a prior
transaction commitment. The Project is critical to achieving the planned transfer
capability rating of subsequent Project segments.
4. Windstar to Aeolus to Bridger – Segment D
19.
A Priority Two level project, Segment D is part of Gateway West. Segment D is
expected to be jointly owned by PacifiCorp and Idaho Power. Segment D is estimated to
cost $880 million. Two single circuit 230 kV transmission lines will run 156 miles from
the new Windstar substation in eastern Wyoming southwest to a new Aeolus substation.
From Aeolus, double circuit 500 kV/230 kV transmission lines will run 141 miles west to
connect to the existing Bridger substation in western Wyoming. The 230 kV portion of
the line from Aeolus to Bridger could be upsized to 500 kV if supported by queue
customer commitments or new equity partner participation. Segment D, expected to be
placed in service in 2014, is intended to access and deliver energy from new and existing
generating resources, including renewable energy resources such as wind.
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5. Bridger to Populus to Hemingway– Segment E
20.
Segment E, part of Gateway West, is comprised of two sections with an estimated total
cost of $1.02 billion. When both sections are completed, Segment E will run from a
planned generation resource hub near Rock Springs, Wyoming, across Idaho to a point
southwest of Boise, Idaho. The first section is a Priority Two level project that will link
the new Bridger substation in Wyoming to the new Populus substation in Idaho via a
single circuit 500 kV line.
21.
The second section, a Priority Three project, will continue the single circuit 500 kV
transmission line from Populus to a new Hemingway substation in western Idaho. The
two segments of Gateway West (Segment D and E) will provide connections to Gateway
South and Gateway Central, delivering energy from new and existing generating
resources, including renewable energy resources such as wind in Wyoming, to load
centers further west. PacifiCorp anticipates that portions of this section will be jointlyowned with Idaho Power and placed in service in 2014.
6. Aeolus to Mona – Segment F
22.
A Priority Four level project, Segment F is part of Gateway South. The single circuit 500
kV transmission line, estimated to cost $764 million, will run approximately 395 miles
from the new Aeolus substation in southeastern Wyoming southwest to the existing Mona
substation in central Utah. The line could be upsized to a double circuit 500 kV line if
warranted by queue customer commitments or new equity partner participation.
7. Sigurd to Red Butte to Crystal – Segment G
23.
A Priority One level project, Segment G is part of Gateway South and is estimated to cost
$754 million. The Segment G transmission line is approximately 280 miles and will
connect the existing substation Sigurd (in central Utah) through the existing substation
11
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Red Butte (in southeast Utah) to the existing substation Crystal (north of Las Vegas,
Nevada). The line linking these substations will be a single circuit 345 kV line, and is
expected to be in service in 2013. Segment G will provide additional capacity and access
to supplies from Wyoming to serve growing customer demand and it will improve the
reliability and operational flexibility of the electrical system. If warranted by queue
customer commitments or new equity partner participation, Segment G could be upsized
to a 500 kV transmission line and/or an additional line segment connecting the Sigurd
substation to the existing Mona substation, 50 miles north. PacifiCorp is actively
working to determine the level of interest among potential third parties equity partners,
including investor-owned utilities and public power entities, to help support upgrades that
could facilitate broader regional benefits. PacifiCorp is also working with neighboring
utilities to best interface at lowest cost through the WECC rating process.
8. Hemingway to Captain Jack– Segment H
24.
A Priority Three level project, Segment H is part of the Westside portion of the Project
and is expected to cost $786 million. The single circuit 500 kV transmission line will run
approximately 375 miles from the existing Hemingway substation in western Idaho to the
Bonneville Power Administration’s Captain Jack substation in Northern California. The
line will provide access to the resource-rich areas of the Inland West with the growing
population centers of the Pacific Coast.
V.
THE PROJECT IS THE RESULT OF A FAIR AND OPEN REGIONAL
TRANSMISSION PLANNING PROCESS
A. Overview
25.
Due largely to failed or aborted efforts to develop regional transmission organizations in
the West, the development and coordination of a definitive regional transmission
12
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planning process was slower to materialize than in some other areas of the country. The
region, however, has developed a highly coordinated approach to regional planning and
expansion that accommodates the existence of numerous sub-regional groups of utilities,
and, in PacifiCorp’s view, satisfies the Commission’s requirements for a coordinated,
open and transparent process that meets the planning principles stated in Order No. 890.
Regional transmission planning and expansion within the West is coordinated under the
auspices of the WECC. Three distinct, but coordinated, levels can be identified within
the overall regional planning process: 1) the local planning processes of individual
transmission providers, 2) the sub-regional planning processes of organized groups of
utilities within the region, and 3) the regional planning processes of the WECC.
26.
PacifiCorp’s local planning process is open and transparent. The company’s 2007
Integrated Resource Plan (“IRP”) is a long-term strategy to help ensure that PacifiCorp
continues to provide reliable, least-cost service to its customers with consideration of risk
and uncertainty. The IRP is informed by an analysis of the tradeoff between various
resource options over a twenty-year period, as well as a collaborative public process with
involvement from customer interest groups, regulators and other stakeholders. For
example, from late 2005 though April 2007, the company held 13 public meetings with
stakeholders to discuss important planning issues and to solicit comments on IRP analysis
methods and assumptions.
27.
PacifiCorp’s sub-regional planning process is also open and transparent. PacifiCorp is a
member of the NTTG, a coalition of investor-owned and public utilities, state
government agencies and customer groups that provides an open and transparent
planning process for its transmission-owning members in the Pacific Northwest and
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Rocky Mountain states. NTTG coordinates transmission planning within its footprint
with planning being undertaken by other sub-regional groups and with the Western
Interconnection-wide planning efforts of the WECC. In addition to PacifiCorp, the
NTTG sub-regional planning group includes Idaho Power, Deseret Power Electric
Cooperative, NorthWestern Energy and Utah Associated Municipal Power Systems, and
recently-joined Portland General Electric. The NTTG footprint includes approximately
2.7 million customers and more than 27,000 miles of transmission lines within Oregon,
Washington, California, Idaho, Montana, Wyoming and Utah.
28.
Exhibit No. 2 is a copy of the NTTG’s first annual report (“2007 Annual Report”). As
explained in the 2007 Annual Report, stakeholder participation is important to the
planning process. All interested parties are encouraged to attend and contribute to the
many stakeholder meetings conducted by the NTTG transmission use, planning and cost
allocation committees, and in preparing, developing and analyzing planning studies. The
management arm of the NTTG – the Steering Committee -- is comprised of
representatives of state regulatory commissioners, executive level utility representatives,
and representatives of state consumer advocacy groups.
29.
NTTG performs both reliability and economic planning coordination within its footprint,
and works with the WECC Planning Coordination Committee for reliability planning and
the WECC Transmission Expansion Planning Policy Committee for economic planning.
In addition, NTTG coordinates and synchronizes its transmission expansion plan with
neighboring sub-regional planning entities.
30.
Transmission providers receive and act on requests for transmission service in
accordance with their respective Open Access Transmission Tariffs. The 2007 Annual
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Report explains that transmission providers assess future load and resource developments
to plan the evolution of an efficient transmission system, and to undertake reliability
analysis and improvements. Where service requests and other identified needs call for
the development of transmission that involves participation of multiple transmission
providers within a sub-regional group’s footprint, the planning and analysis of
improvements are coordinated at the sub-regional level. Projects that span greater
distances are planned, analyzed and developed in coordination with other sub-regional
groups or at the regional WECC level.
31.
The WECC is responsible for coordinating and promoting electric system reliability for
the vast region that spans the Western Interconnection, including the provinces of Alberta
and British Columbia, the northern portion of Baja California, Mexico and all or portions
of 14 western states. The regional planning process coordinated by WECC is designed to
provide interested parties the opportunity to review and comment on proposed projects,
and to solicit participation in the construction of the transmission lines. Several Project
segments are completing the WECC planning process.
B. The Project Has Been Designated By NTTG As A Critical Fast Track Project
And Is Now Proceeding Through The WECC Process
32.
All segments of the Project other than Segments A and C were planned, coordinated and
approved by the NTTG Planning Committee. While the localized segments for Segments
A and C were not explicitly incorporated into the NTTG Fast Track process, as described
further, these segments will be incorporated into the NTTG biennial planning process.
Due to the pressing need for critical transmission infrastructure, a Fast Track process was
used by NTGG in advance of finalizing requirements for Attachment K of its Open
Access Transmission Tariff. While the approval process was expedited to accommodate
15
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the critical need for timely transmission expansion, stakeholder participation was not
comprised. Page 5 of the 2007 Annual Report, Exhibit No. 2 to my Affidavit, contains a
summary of NTTG’s activities during 2007, including public stakeholder meetings and
comment periods concerning the proposed Fast Track projects.
33.
During 2007, NTTG undertook two parallel planning initiatives: 1) identification of Fast
Track transmission expansion projects needed for reliability and to meet transmission
service requests within the NTTG footprint, and 2) development of a prospective formal
biennial planning process to be undertaken in conjunction with the Western
Interconnection’s regional planning process. In order to quickly implement transmission
expansion projects needed to meet immediate needs, the Fast Track process relied on
studies previously done within the region to identify congested transmission that impedes
efficient and reliable operation of the grid. The process provided a forum for stakeholder
input and participation in the identification of Fast Track projects critical to relieving
these areas of congestion and improving reliability. Organic agreements necessary for
the going-forward biennial planning process were completed in 2007, and execution of
the process began in January of 2008. The first NTTG biennial planning report is
expected in the fourth quarter of 2009.
34.
The 2007 Annual Report describes these parallel planning initiatives and identifies the
Fast Track projects for the sub-region. As provided above, the projects identified under
NTTG’s Fast Track process include all segments of the Project other than Segments A
and C. Each sponsor of a Fast Track project is required to develop a technical study
plan that, among other things, identifies interested and affected parties, provides a plan
and schedule for coordinating with other regional and sub-regional planning groups, and
16
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performs required WECC regional planning review studies and ratings. The NTTG’s
review of the Energy Gateway projects during the Fast Track process was coordinated
with Northwest Transmission Assessment Committee, Columbia Grid, West Connect,
and the WECC Transmission Expansion Planning Policy Committee.
35.
Following the NTTG Planning Committee’s approval of the 2007 Annual Report and
Fast Track recommendations, the Project (with the exception of Segments A and C) was
submitted for WECC regional planning review. The regional planning review process is
conducted by the WECC Planning Coordination Committee and is an open, transparent
process that provides for stakeholder meetings and written comments in response to
proposed projects. Following completion of the planning review, the three-phase
facility rating process begins. During Phase I, studies are conducted to demonstrate the
proposed non-simultaneous rating of the facilities. A comprehensive report is
completed, and the proposed project’s facilities are granted a “planning rating.” During
Phase II of the rating process, a “project review group” is established to evaluate the
project’s plan of service. Other aspects of the project are also evaluated, including: i)
further assessments of the planned rating, ii) effects on simultaneous transfer capability,
and iii) impacts on neighboring systems. When this phase is completed, the project is
given an “accepted rating.” Finally, during Phase III of the ratings process, WECC
members and staff monitor the project as it is constructed. Phase III is completed when
the facilities are placed in service.
36.
As demonstrated in the letters from the WECC Planning Coordination Committee and
Technical Studies Subcommittee included in Exhibit No. 3, the regional planning review
process has been completed for Gateway West (Segments D and E) and Gateway South
17
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(Segments F and G). Segments A and H are currently in the regional planning review
process. Some segments are not required to go through the regional rating process,
however where segments may intersect, duplicate, or affect other proposed segments
regional planning and rating is to occur. Segment C is not required to go through the
WECC planning review process because this line is not likely to affect another system or
line. Final facility ratings for Gateway West and Gateway South segments are expected
in July of 2009.
VI.
THE PROJECT IS ELIGIBLE FOR INCENTIVES
37.
The Commission deems a transmission project to be entitled to a rebuttable presumption
of eligibility for transmission incentives if the project either (1) results from a fair and
open regional planning process that considers and evaluates projects for reliability and/or
congestion and is found acceptable to the Commission, or (2) has received construction
approval from an appropriate state commission or siting authority. The Project, including
any refinements or modifications resulting from completion of the WECC rating process
or regulatory approvals, is the product of a coordinated local (PacifiCorp), sub-regional
(NTTG) and regional (WECC) planning process that is fair and open and that considers a
proposed project’s impact on reliability. PacifiCorp’s Petition requests that, subject to
any modifications resulting from the coordinated regional planning and rating process,
the Commission find that the Project is eligible for incentives.
38.
By any measure, the Project’s eligibility for incentives is evident. The Project will be
built to satisfy all WECC and North American Electric Reliability Council (“NERC”)
planning and reliability standards for system adequacy and security, system modeling
data requirements, system protection and control and system restoration. By adding
18
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critical EHV infrastructure to the bulk power transmission system, the Project will
provide contingency capacity throughout the system, thereby enhancing reliability within
the NTTG footprint and the broader region. NERC reliability standards require that the
system operate under conditions that will withstand the next major facility electrical
outage, or “n-1” outage. If the existing transmission system is equal to or higher in
voltage to a new transmission addition, the new addition will not typically cause as
drastic impacts to the system when an outage occurs. With the addition of major
transmission facilities that are larger in voltage than the existing transmission system, a
fully redundant transmission system must be constructed. This is the case for much of
the Project (i.e., Segments D, E and F).
39.
Another important feature of the Project is that it will directly link PacifiCorp’s east and
west control areas, enabling the company to make efficient use of resources to meet its
load and reserve obligations, as well as minimize congestion and relieve loading along
paths between Wyoming and areas west and south. By adding interconnections and
increasing transfer capacity throughout the system, the Project will reduce the need for
curtailments resulting from overscheduled use, significantly improve access to generation
resources to meet system demand and reserve obligations, facilitate a more diverse mix of
available generation resources and assist in meeting renewable portfolio requirements.
40.
The EHV transmission lines and use of advanced technology will allow long distance
delivery of energy with reduced energy losses. The Project’s “resource hub-to-load
center” design will enable better utilization of resources and create multiple options to
serve customers. A significant benefit to the region as a whole is the establishment of the
first 500 kV transmission “super-highway” within the Project footprint. With this
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backbone infrastructure in place in the footprint, future EHV transmission lines will
likely face fewer engineering and system reliability obstacles.
41.
PacifiCorp must provide network customers with adequate transmission capability that
optimizes generation resources and provides reliable service. PacifiCorp’s decision to
undertake the Project was driven by capacity shortages, network congestion, service
obligations and the need to establish access to multiple resource types, including
emerging renewable resources. Importantly, PacifiCorp considered many smaller scale
projects with more limited risks and benefits, but these routine approaches were rejected
because they would not have achieved the long-range system-wide benefits of the
Project.
42.
Ten-year forecasts from PacifiCorp’s recent annual IRPs have shown a steady and
growing gap between existing resources and load/reserve obligations on the system.
PacifiCorp’s network load obligation is expected to grow during the next ten years at an
average annual rate of 2-3%. Renewable portfolio standards throughout PacifiCorp’s
service territory have served to magnify the need for long-distance deliverability from
resource hubs to load. Routine upgrades would not ensure long-term reliability and
planning reserves.
43.
The Western Governors and numerous regional study groups have been calling for new
transmission construction for several years. In identifying the Fast Track projects
recommended in the 2007 Annual Report, the NTTG Planning Committee reviewed
many of these prior studies, including the 2004 Rocky Mountain Area Transmission
Study (“RMATS”). The RMATS report was based on reviews by stakeholders,
populated work groups of load forecasting, and resource/transmission additions
20
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developed under a production cost model operated by PacifiCorp to examine the value of
potential transmission expansion under different generation scenarios. The RMATS
report recommended that the most feasible transmission additions move forward,
including a recommended expansion of PacifiCorp’s existing 345 kV transmission
system from the Bridger substation in Wyoming to Utah and Idaho (identified as the
“Bridger Expansion project”). While larger than the Bridger Expansion project
recommended by the RMATS report, Energy Gateway West is similar in concept and
will achieve the goals previously identified in the report. Relevant excerpts from the
RMATS report are provided in Exhibit No. 4.
44.
In August 2006, the DOE released the National Electric Transmission Congestion Study
(“2006 DOE Study”), which examined transmission congestion and constraints
nationwide. Within the Western Interconnection, DOE reviewed existing transmission
studies, expansion plans and reliability assessments and examined historical data
collected by the WECC, including hourly line flows. The 2006 DOE Study identified
numerous paths and areas within PacifiCorp’s footprint where congestion currently exists
or would result from future development of generation capacity in the Rocky Mountain
area. The Bridger West line from Wyoming to Utah was specifically identified as
currently one of the most heavily congested lines. Relying on projections from the
Western Governors Association’s Clean and Diversified Energy Advisory Committee
(“CDEAC”), the 2006 DOE Study finds that the Western Interconnection needs large
additions to its transmission network to encourage development and export of electricity
generated from the abundant coal and wind resources in the Montana-Wyoming area.
The Project addresses the Bridger West constraints, as well as the need for major
21
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additions to the bulk power transmission system to support energy exports from
Wyoming to loads located west and southwest. Relevant excerpts from the 2006 DOE
Study are provided in Exhibit No. 5.
45.
The Western Interconnection 2006 Congestion Assessment Study (“Congestion
Assessment Study”), issued May 8, 2006 by the DOE Western Congestion Analysis Task
Force, also identifies areas of congestion in the Rocky Mountain states. Based on 2005
load and resource forecasts and a production model, the Congestion Study Assessment
forecasted that by 2008:
•
the Bridger West path (associated with Segment E of the Project) would be
constrained at its limit 42% of the time in the most conservative gas price scenario;
•
Path C (associated with Segment B of the Project) would be constrained at its limit
7% of the time and heavily utilized in other hours;
•
the TOT 2C path (associated with Segment G of the Project) would be used at a
level above 90% of its transfer capability 86% of the time;
•
TOT 4A path (associated with Segment D of the Project) would start showing signs
of congestion in 2008 (hours at transfer limit), with the congestion significantly
increasing as additional resources come on line in Wyoming; and
•
the Idaho-Northwest path (associated with Segment H of the Project) would start to
show signs of congestion in 2008 (hours at transfer limit), with the congestion
significantly increasing as additional resources come on line in Wyoming.
Relevant excerpts from the Congestion Assessment Study are provided in Exhibit No. 6.
46.
Reports initiated by the Western Governor’s Association (“WGA”) also show certain
paths in PacifiCorp’s service territory (such as Segment C) to be constrained. The WGA
and its working groups have also identified the important need to develop transmission
projects throughout the West to access location-constrained resources. The WGA’s
Transmission Task Force Report (“WGA Report”), dated May 2006, considered the
location and availability of location-constrained renewable resources and the effect that
22
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timely transmission projects could have on increasing the percentage of renewable
resources serving load in the West. The Project represents the type of coordinated and
comprehensive transmission development that meets the critical need of linking remote
renewable resources to load centers throughout the West. Relevant excerpts from the
WGA Report are provided in Exhibit No. 7.
47.
As early as 2002, congestion has been documented within PacifiCorp’s footprint. The
2002 DOE National Electric Transmission Congestion Study (“2002 DOE Study”)
identified the Wyoming-Idaho interface as a major constrained interface and found that,
under optimum use of system resources, the Wyoming-Northern Utah interface was
congested during 50% or more of the hours during the year. Relevant excerpts from the
2002 DOE Study are provided in Exhibit No. 8.
48.
Initiated by the Governors of Utah and Wyoming because of concerns that protracted
regulatory uncertainties have left the industry reluctant to invest in new transmission
infrastructure, the Seams Steering Group – Western Interconnection (“SSG-WI”) issued a
study in 2005. The stakeholder-driven study found that investment in transmission
infrastructure in the West is critical to efficient use of the region’s lower cost coal and
wind generation. The SSG-WI study identified the Wyoming-Utah interface as a critical
constraint.
49.
The Project addresses these areas of congestion identified on the PacifiCorp transmission
system in these studies. The Project brings two major export paths from resource rich
Wyoming, each consisting of a targeted planned rating of 1,500 MW on each path for a
total of 3,000 MW of total export capacity. The Project will facilitate the flow of
electricity from resource hubs-to-load centers, and it will establish an EHV backbone
23
Appendix A
Affidavit of John Cupparo
transmission system to efficiently collect and connect existing and future resources and
load centers. Having this critical EHV infrastructure in place also will greatly facilitate
future EHV additions to the grid.
VII.
ADVANCED TECHNOLOGIES
50.
PacifiCorp will be making use of technology as part of the Project to ensure that
capacity, efficiency or reliability are maximized. Subject to further study and final
engineering, the company intends to utilize several types of advanced technologies to
mitigate congestion and enhance grid reliability. The advanced technologies fall under
categories of: advanced conductor technology, enhanced power device monitoring, fiber
optic technologies, power electronics and other technologies.
A. Trapezoidal Conductor
51.
Aluminum conductor steel supported trapezoidal wire conductors can conduct at more
than twice the accepted temperature limit of conventional aluminum conductor steel
reinforced conductors. Use of this advanced conductor design will increase transmission
capacity and reduce the sag of the transmission lines, as well as reduce line energy losses.
PacifiCorp commissioned an expert to compare and contrast five or more particular types
of conductors under certain load factor assumptions to determine which offered the
highest overall value for customers. The study showed that the Lapwing Trapezoidal
Wire same Diameter (recently renamed as Trapezoidal Wire “Athabaska”) reduced line
losses at a higher rate and with more overall benefit than the other conductors considered
over the life of the facilities. Use of this technology provides long term benefits to
customers and those with interconnected generation but at a higher upfront cost. Use of
the technology, however, carries investment risk associated with the large capital
24
Appendix A
Affidavit of John Cupparo
expenditure required. PacifiCorp chose to undertake this risk to further energy efficiency
and to reduce the need for future resources that otherwise would be needed to offset
transmission line losses.
52.
PacifiCorp estimates that use of the advanced technologies on the proposed 500 kV
transmission lines will provide substantial incremental benefits over conventional
alternatives. PacifiCorp estimates that use of these technologies will help avoid more
than 120,000 MWhs of energy losses annually for the life of the Project over more
standard technologies, and could approximately double those avoided losses for segments
that are constructed to 500 kV double circuit configuration. An estimated 60,000 to
120,000 metric tons of carbon dioxide (“CO2”) emissions could be avoided annually for
the base Project through the utilization of this technology over more conventional utility
applications.
B. Static VAR Compensators (SVCs)
53.
SVCs are electrical devices used to automatically match impedance to regulate voltage.
In addition, SVCs improve both dynamic and transient network stability, and are useful
when placed near high and varying loads where they can smooth flicker voltage. The
transfer capability of a high voltage transmission line is highly dependent on the line’s
length. In order to increase line transfer capability and balance phase voltages,
PacifiCorp is evaluating the installation of SVCs at several of the Project hubs, which
would support the required dynamic voltage regulation and firm up the system. The
intended use of SVC technology would not only support the required dynamic voltage
regulation and the “firming up” of the system, it would also improve reliability, power
quality, contingency recovery, create operational benefits to support the deliverability of
intermittent renewable energy sources as well as would help maximize the overall total
25
Appendix A
Affidavit of John Cupparo
transfer capability. The use of SVCs as part of the Project relies on relatively new solid
state transient power and voltage control technology to avoid the need for additional
transmission infrastructure, including additional transmission line facilities, which would
otherwise be needed solely to regulate voltage and maintain system stability.
C. Fiber Optic Shield Wires
54.
PacifiCorp is planning to use fiber optic shield wires to protect transmission lines by
shielding phase conductors from direct lightning strikes. Fiber optic cable, in lieu of, or
as complement to, wave trap or microwave technology, allows a communications link to
overhead transmission lines. Furthermore, shield wires with fiber-optic cores enable the
novel application of differential line protection, a superior technique borrowed from
transformer protection that reliably detects short circuits. Fiber optic shield wires also
provide high-capacity, high-speed communication channels allowing system dispatchers
to switch facilities remotely and reliably for voltage control and to maintain reliable grid
operation and security. In addition, these same channels will aid engineering and
maintenance staff in performing diagnostics of the remotely-located equipment.
55.
While not required by standard, PacifiCorp is incorporating the use of fiber optic
technology to provide a more reliable communication path to operate the transmission
facilities. The installation of fiber optic technology can also create additional latent
capacity bandwidth, which while not currently anticipated to be used outside the
operation of the transmission system, could also provides an alternate secure
communication path that could be used in the interest of national security and regional
development.
26
Appendix A
Affidavit of John Cupparo
D. Phase Shifters
56.
Phase shifters improve and/or increase stability limits of transmission lines when the
maximum power transfer is reached by changing the alternating current phase angle
between the sending and receiving ends of the line. Specifically, the use of this
technology maximizes the utilization of existing and newly installed transmission system
assets by regulating alternating current (“AC”) power flows in both magnitude and
direction. In this way, phase shifters help provide operational and seasonal flexibility,
and allow the dispatch of flow patterns required to maximize the grid and to provide
operational benefits during contingencies. PacifiCorp is pursuing targeted applications of
this technology to reduce overall system losses through elimination of circulating
currents and help protect neighboring transmission systems. Phase shifters are a
technology primarily used in the Western Interconnection due to the high-voltage, longdistance lines in order to reduce phase shifting between the sending and receiving ends of
the lines.
57.
The use of phase shifters on the Project can reduce the detrimental impact of new
transmission facilities on the existing underlying transmission system. Using this unique
technology avoids the need for additional transmission infrastructure, including
additional transmission line facilities, which would otherwise be needed solely to
mitigate inadvertent flows on neighboring electric systems. PacifiCorp anticipates that
this technology will help the Project to achieve an efficient integration with the Western
Interconnection.
E. Special Protection Schemes
58.
PacifiCorp will employ Special Protection Schemes (“SPS”) to respond to system events
and disturbance data that could potentially cause undue stress on its system. SPS
27
Appendix A
Affidavit of John Cupparo
technology will help PacifiCorp maximize grid total transfer capability, improve longterm reliability, and reduce negative impacts to the interconnected systems, as well as to
benefit interim ratings as bulk transmission systems are ultimately built out over a period
of time.
F. Monitors for Transformers and Phase Shifters
59.
PacifiCorp is evaluating the use of monitors in transformers at the new substations
planned as part of the Project. PacifiCorp will employ the use of such technologies for
real-time measurement and monitoring of dissolved combustible gases in oil filled
equipment. Such technology provides real-time monitoring of highly combustible gases
(such as acetylene, hydrogen, methane and oxygen) that are dissolved into power
equipment insulating oil, and will provide notification when the affected equipment is
near failure. These monitors can improve the reliability of the Project, and can help
insure that the transmission assets reach their useful expected life spans. While not
required by reliability standards, the use of monitors helps protect high-cost investments
and improve reliability by providing for early detection of potential issues.
60.
Other advanced technologies were considered by PacifiCorp, but not selected for this
Project. For example, PacifiCorp evaluated the use of advanced composite core
conductors, and we are using this technology on a limited basis on a small portion of
Segment B by rebuilding an existing line with this technology to accommodate the new
double-circuit 345 kV line. However, this technology is not economically justified on
other portions of the Project, given the use of Trapezoidal conductor technology on the
500 kV transmission facilities and new line construction. Similarly, PacifiCorp decided
to forgo the use of underground conductors, as the capital costs were multiples of
28
Appendix A
Affidavit of John Cupparo
overhead construction configurations and would have rendered the Project economically
unfeasible.
61.
Direct current (“DC”) technology was not used on the Project in order to optimize
PacifiCorp’s ability to flexibly interconnect the current and future additions to the
existing alternating current system and to best allow generation interconnection at
intermediate points. The use of AC technology on the Project also allows future projects
to build off of the backbone that the Project forms in the Wyoming, Idaho and Utah areas.
DC technology can cause feasibility concerns the more terminals are used on a line, and
as such can limit the ability of a direct current project to interconnect with future projects
and generation additions at intermediate points on a direct current project. DC also may
not have the direct benefit of strengthening the ability of the underlying network
alternating current system to resist voltage stability disturbances. The alternating current
configuration used on the Project will best meet these reliability and flexibility
objectives.
VIII. RISKS AND CHALLENGES FACED BY PACIFICORP
62.
As noted previously, PacifiCorp is requesting the following incentives, each of which
would be established in a future Section 205 rate case: 1) a 250 basis point adder to the
PacifiCorp base ROE applicable to investment in the Project, and 2) authorization to
recover prudently-incurred abandonment costs if the Project is abandoned for reasons
beyond PacifiCorp’s control.
63.
The requested incentives are rationally related to PacifiCorp’s investment in the Project,
which is a major undertaking that inherently carries with it complexity and tremendous
challenges and risks. PacifiCorp’s net transmission plant in service as of December 31,
29
Appendix A
Affidavit of John Cupparo
2007 was approximately $1.8 billion. The company’s projected investment of $6 billion
in the Project represents an increase in current net transmission plant of approximately
330%. When compared to PacifiCorp’s previous years’ transmission expansion budget,
the estimated $6 billion cost of the Project is also substantial. In the five previous years
(2002-2007), PacifiCorp expended an average of $111 million in capital expenditures per
year on transmission projects. The average annual capital expenditure for the Project
alone will be nearly seven to eight times greater than PacifiCorp’s historical annual
capital expenditure budgets for all transmission.
64.
In terms of investment, transmission miles and number of states traversed, the Project is
larger than any other transmission project that has been proposed for incentive rate
treatment to date. The projected capital investment for PacifiCorp is nearly double the
highest capital investment projected among projects previously granted incentive rate
treatment. The Project will result in construction of approximately 2,000 miles of EHV
transmission lines traversing six states and federally-administered lands. The largest of
the projects previously proposed for incentive rate treatment have proposed 550 miles of
new transmission lines traversing, at most, four states. By all of these objective
measures, the Project is larger, more complex and carries greater challenges and risks
than any transmission expansion project previously approved for incentives by the
Commission.
65.
Given the scale and scope of the Project, it faces significant regulatory risks at local, state
and federal levels. The Project requires siting/permitting approval of six state
jurisdictions: Idaho, Nevada, Oregon, Utah, Washington, and Wyoming, as well as
federal land management agencies for the various Project segments traversing federally-
30
Appendix A
Affidavit of John Cupparo
administered lands, and coordination with affected tribal interests. PacifiCorp will also
face significant financial risks when it seeks rate recovery for its investment in the Project
from its state regulators. PacifiCorp will ask all of the transmission investment for the
Project to be included in PacifiCorp’s rate base for delivered retail electric service.
However, PacifiCorp faces a risk that state regulators will not include all of the
investment in retail rates if the benefits to retail customers are not proven to be sufficient.
To the extent that state regulators permit the recovery of all of the transmission
investment in retail rate base, PacifiCorp will credit FERC-jurisdictional transmission
revenues, including any revenues associated with incentives granted by the Commission,
against its retail revenue requirement. Thus, the incentives authorized by FERC could be
an important consideration in the state regulators’ determination of whether to include
PacifiCorp’s entire investment in the Project in retail rates.
66.
The Project’s departure from conventional designs used in the past also represents a
financial risk. The Project involves siting transmission lines to resource-rich areas, but
prior to the actual siting of specific generation projects. This represents a departure from
past conventional approaches to developing transmission. The novel approach and
design of the Project presents investment risks greater than the historical norm, a risk that
is magnified by the scale and scope of the Project.
67.
PacifiCorp faces business, financial and technical risk by virtue of the “first in time”
status for constructing a 500 kV transmission backbone within the Project footprint. In
providing this 500 kV backbone, PacifiCorp will be responsible for ensuring that the
underlying system can withstand technical and regulatory scrutiny, including the
protection of neighboring electrical systems.
31
Appendix A
Affidavit of John Cupparo
68.
Large portions of the Project are expected to be routed through federally-administered
lands, including in Idaho, Nevada, Oregon, Utah and Wyoming. Right-of-Way (“ROW”)
applications have been filed with the Bureau of Land Management (“BLM”) and the
United States Forest Service. These agencies will now consider various factors during
the review process, including alternatives to the Project, route alternatives and potential
environmental impacts and mitigation measures. These proceedings are expected to be
prolonged, complex, controversial, and likely contested. As such, obtaining the
necessary approvals is far from certain. Any delay in obtaining the necessary local, state
and federal approvals will jeopardize the realization of reliability, congestion and
environmental benefits associated with the Project.
69.
The Project also faces risks in connection with the use of several advanced transmission
technologies that have not been widely deployed. Reliance on novel technologies
inherently poses increased risks in the form of added uncertainty as to how they will
perform within the context of this large project. As described above, the Project will use
Trapezoidal Conductors, a new form of technology that allows transmission lines to
conduct at more than twice the accepted temperature limit of more conventional lines, as
well as Fiber Optic Shield Wires that assist in enhancing the functionality and reliability
of the Project’s transmission lines. The use of these and the other advanced technologies
described in this Affidavit must be designed, constructed and tested to ensure they meet
the requirements of the Project.
70.
Escalation in land, material and labor costs presents increasing challenges and risks to
PacifiCorp as it moves forward with the Project. Costs for land and materials have
increased 20% in the last year alone. Steel costs have increased 40%. Across the globe,
32
Appendix A
Affidavit of John Cupparo
demand for labor and materials needed for major transmission expansion projects is
outpacing supplies driving costs upward. The downturn in the domestic economy and the
value of the US dollar exasperates the situation.
71.
In conclusion, whether compared to PacifiCorp’s current net transmission rate base or
historical annual transmission investment, or whether compared to the transmission
expansion projects previously proposed by other companies, the Project is one of
enormous size, scale and scope. As it moves forward with this major project, PacifiCorp
faces significant business, financial, regulatory and technological challenges and risks.
Moreover, the Project is a voluntary undertaking on the part of PacifiCorp and its parent
MidAmerican, a company with many investment opportunities.
72.
Further affiant sayeth not.
33
EXHIBIT 1
Energ y Gateway Status Update
June 2008
PacifiCorp remains fully committed to the Energy Gateway transmission expansion project, which holds benefits for both its
customers and the region. The company is moving on track to best meet the originally announced in-service dates, and is actively
pursuing outreach, permitting, planning and design work to meet these goals. PacifiCorp also is incorporating flexibility into later
priority segments that may be impacted by external factors. The priority levels below reflect current schedules based on what the
company has learned in the first year of implementation, and retains the flexibility to adjust as needed to accommodate cost and
resource pressures and the participation of third parties. For more information, please visit www.pacificorp.com/energygateway,
or contact Darrell Gerrard, Pacific Power vice president of transmission system planning, at 503-813-6994.
A
G AT E WAY W
EST
H
WYO M IN G
E
D
G AT E WAY
CENTRAL
E
B
F
C
S
PacifiCorp service area
Planned transmission lines
500 kV minimum voltage
A
G
G
A
T
E
O
U
T
H
Y
W
345 kV minimum voltage
230 kV minimum voltage
Transmission hub
Substation
Generation plant/station
Priority One
Base Load Service
and Reliability
Priority Two
Wind Integration
and Resource Adequacy
Priority Three
Integrated Control Area and
Renewable Energy Delivery
Priority Four
Reliability Backup
and Rating Support
• Segment B (Populus to Terminal 345 kV), 700 MW – 2010 & 1,400 MW – 2014
• Segment A (Walla Walla to McNary 230 kV), 400 MW – 2010
• Segment C (Mona to Oquirrh 500 kV), 1,500 MW – 2012
• Segment G (Sigurd to Crystal 345 kV), 400-600 MW – 2013
• Segment D/E (Windstar to Populus 230/500 kV), 1,500 MW – 2012-14
• Segment E (Populus to Midpoint/Hemingway 500 kV), 1,500 MW
• Segment H (Hemingway to Captain Jack 500 kV), 1,500 MW
• Segment F (Mona to Aeolus), 1,500 MW
EXHIBIT 2
NORTHERN TIER TRANSMISSION GROUP
Annual Planning Report – 2007
April 2, 2008
Preface
This report was prepared by Comprehensive Power Solutions, LLP, as part of its facilitation and
coordination work for the Northern Tier Transmission Group. The members and other
stakeholders participating in the effort to provide coordinated, efficient and effective planning for
expansion of transmission within the Northern Tier footprint have been helpful in developing the
content of this report.
While the report is made available to the public, neither Northern Tier or CPS accepts any duty
of care to third parties who may wish to make use of or rely upon information presented in this
report. CPS has exercised due and customary care in developing this report, but has not
independently verified information provided by others and makes no further express or implied
warranty regarding the report’s preparation or content. Consequently, CPS and Northern Tier
shall assume no liability for any loss due to errors, omissions or misrepresentations made by
others.
This report may not be modified to change its content, character or conclusions without the
express written permission of CPS and Northern Tier.
i
Preface | 2007 Annual Planning Report
To ensure efficient, effective, coordinated use and expansion of the members’
transmission systems in the Western Interconnection to best meet the needs of
customers & stakeholders.
Figure 1: Map of Northern Tier Member Transmission Lines
2007 Annual Planning Report | Preface
ii
Contents
Preface........................................................................................................................................... i Contents....................................................................................................................................... iii Figures ......................................................................................................................................... iv Summary....................................................................................................................................... 1 Background ................................................................................................................................... 2 The Northern Tier Transmission Group ........................................................................................ 4 NTTG – Chronology of 2007 Activities .......................................................................................... 5 Transmission Queue – NTTG Companies .................................................................................... 6 The Northern Tier Fast-Track Planning Process .......................................................................... 7 The NTTG Fast-Track Projects ..................................................................................................... 8 NTTG Project Development Timelines ....................................................................................... 10 The Sub-Regional Planning Process .......................................................................................... 11 Relationships among Planning Entities in the West .................................................................... 12 Regional and Sub-Regional Planning Timelines ......................................................................... 14 Details of the Northern Tier Transmission Projects .................................................................... 15 Hemingway to Boardman Transmission Project ......................................................................... 16 Hemingway to Captain Jack Transmission Project ..................................................................... 17 Southwest Intertie Project (SWIP) North ..................................................................................... 18 Mountain States Transmission Intertie Project ........................................................................... 19 Gateway West Transmission Project .......................................................................................... 20 Gateway South and TransWest Express .................................................................................... 21 Gateway Central Transmission Project ....................................................................................... 22 NorthernLights Transmission Project – Inland Project ................................................................ 23 Internet Links and Other References .......................................................................................... 24 Regional Planning .................................................................................................................................... 24 Sub‐Regional Planning ............................................................................................................................ 24 Northern Tier Transmission Group Members ......................................................................................... 24 Integrated Resource Plans ...................................................................................................................... 25 Additional Information for Northern Tier Transmission Projects ........................................................... 25 iii
Contents | 2007 Annual Planning Report
Figures
Figure 1: Map of Northern Tier Member Transmission Lines ....................................................... ii Figure 2: Structure of the Northern Tier Transmission Group ....................................................... 4 Figure 3: Northern Tier Transmission Request Queue ................................................................. 6 Figure 4: Northern Tier Fast-Track Project Map with Potential Resource Additions ..................... 8 Figure 5: Map of Fast-Track Transmission Showing Voltage & Points of Connection .................. 9 Figure 6: Development Timelines for Northern Tier Projects ...................................................... 10 Figure 7: Three-level Planning Process in the Western Interconnection .................................... 12 Figure 8: Timelines for Regional & Sub-Regional Planning ........................................................ 14 Figure 9: Proposed Transmission Projects as of December 2007 .............................................. 15 Figure 10: Map of Hemingway-to-Boardman Transmission Project ........................................... 16 Figure 11: Map of Hemingway to Captain Jack Transmission Project ........................................ 17 Figure 12: Map of Southwest Intertie Project (SWIP) ................................................................. 18 Figure 13: Potential Route of MSTI (Dashed Line) ..................................................................... 19 Figure 14: Map of the Gateway West Transmission Project ....................................................... 20 Figure 15: Map of Gateway South and TransWest Express Proposed Study Areas .................. 21 Figure 16: The Gateway Central Transmission Project .............................................................. 22 Tables
Table 1: Existing and Prior Regional Transmission Studies ......................................................... 2 Table 2: Chronology of NTTG Activities in 2007 ........................................................................... 5 Table 3: Fast-Track Project Data .................................................................................................. 9 2007 Annual Planning Report | Figures
iv
Summary
The Northern Tier Transmission Group was formed in the autumn of 2006 to establish a subregional planning process that would meet the needs of its members by coordinating the
operation and expansion of transmission to serve customers and wholesale power markets.
Northern Tier is also intended to meet the mandate set forth in the Federal Energy Regulatory
Commission’s Order No. 890, to provide greater transparency to regional transmission planning.
Northern Tier is a combined effort of transmission providers, state regulatory agencies, and
other stakeholders.
This document is a first annual report on the organization, structure, activities, accomplishments
and future plans for coordination and planning of transmission within the geographic footprint
defined by the members’ systems.
Following an overview of Northern Tier, this report describes the development and execution of
a Fast Track Project Process to expedite needed transmission additions without waiting for
design and development of a more permanent Biennial Planning Process.
A primary intent in forming the Northern Tier Transmission Group was to implement needed
transmission projects and initiatives quickly, without being held back by the time-consuming and
delaying processes that plagued development of RTO West and GridWest. The objective was
to develop required organizational structures as needed, but in parallel with production of work
products.
The Fast Track Project Process was used in 2007 to identify projects needed for reliability and
to meet Transmission Service Requests. The Fast Track Process, open to stakeholder input
and participation, was pursued at the same time that a more formalized Northern Tier
Transmission Group Sub-Regional Planning process was designed to dovetail with the Western
Energy Coordinating Council’s Regional Planning Process. Other transmission providers, which
would join the Northern Tier Transmission Group over time, were developing their own projects
that, with their membership, would be included in the Northern Tier portfolio.
Development of these synchronous planning processes, designed to meet requirements of the
Federal Energy Regulatory Commission’s Order 890, are now complete but would have delayed
needed transmission planning. 2007 saw the development of individual transmission providers’
Order 890, Attachment K, filings, which defined their individual processes, and the development
of Northern Tier’s Biennial Planning Process.
The Northern Tier Projects are comprised primarily of 500 kV lines designed to connect the
energy resource-rich regions of the Inland Northwest with the customer loads of the Pacific
Northwest and Southwest, and the growing demands of Intermountain population centers.
1
Summary | 2007 Annual Planning Report
Background
Between 2001 and 2006, a series of transmission planning processes took place in the Western
Interconnection. Among these were the SSG-WI (Seams Steering Group – Western
Interconnection) framework, and the RMATS (Rocky Mountain Area Transmission Study), which
led to creation of the Rocky Mountain Sub-regional Planning Group. The Western Governors
Association, in addition to the RMATS initiative, promoted the CDEAC (Clean and Diversified
Energy Advisory Committee) and the WGA Study (Conceptual Plans for Electricity Transmission
in the West).
Table 1: Existing and Prior Regional Transmission Studies
WGA: Conceptual Plans for Electricity Transmission in the West
SSG-WI: Seams Steering Group – Western Interconnection
NTAC: Canada-NW-California Transmission Study
Colorado Long-Range Transmission Planning Study
Nevada State Office of Energy – T4 Wind Project
RMATS: Rocky Mountain Area Transmission Study
Montana-Northwest Transmission Equal Angle Report
West of Hatwai System Upgrade Projects
Canada-to-Northwest Intertie Expansion
WECC Coordinated Phase Shifter Operation
Western Interconnection 2006 Path Utilization Study (Dept. of Energy)
CDEAC: Clean and Diversified Energy Advisory Committee Initiative
A Northern Tier Transmission initiative was announced on October 11, 2006, and its initial
meeting was held November 8, 2006. Northern Tier was initiated by members of the Grid West
regional transmission organization that remained following a number of departures in 2006, in
order to carry on several beneficial initiatives that were underway, including coordinated subregional planning, common assured transfer capability methods and coordination, and a
diversity interchange for area control errors. Its participants were involved in the RMATS
project, which identified several needed expansion projects that now form the core of the
Northern Tier Transmission Projects, as well as the ACE Diversity Interchange initiative.
2007 Annual Planning Report | Background
2
The Northern Tier initiative led to formal creation of the Northern Tier Transmission Group as a
sub-regional planning group and a part of the Western Energy Coordinating Council’s
Transmission Expansion Planning Policy Committee efforts.
The Transmission Expansion Planning Policy Committee was, like the Northern Tier
Transmission Group, formed in response to the direction the federal government was taking in
the FERC’s Order 890 promulgating regional and sub-regional transmission planning. The
objectives of Order 890 were to promote coordination, openness, transparency, information
exchange, interconnection-wide participation, and dispute resolution.
In early 2007, the Northern Tier transmission providers undertook two parallel planning
initiatives: Task I, to identify Fast Track projects, and a concurrent Task 2, to develop a biennial
planning process in conjunction with the regional planning process being established by the
Transmission Expansion Planning Policy Committee and the planning processes being set up
by the other sub-regional groups within the Western Interconnection.
In 2007, Northern Tier completed the Task 1 Fast Track Project Identification and, for Task 2,
completed the Biennial Planning Process Charter and Planning Agreement, and established the
organizational structure to carry out the task. Execution of the Biennial Planning Process began
in January of 2008 and is expected to produce the first Northern Tier Transmission Group
Biennial Planning Report in the fall of 2009. This report describes the Task 1 Fast Track Project
Process and its results, as well as the integration of transmission initiatives already in
development by providers joining the Northern Tier Transmission Group.
3
Background | 2007 Annual Planning Report
The Northern Tier Transmission Group
NTTG focuses its efforts on the evaluation of transmission projects that move power across the
sub-regional bulk transmission system servicing load in its footprint. The transmission providers
belonging to Northern Tier serve nearly 2.7 million retail customers with over 27,500 miles of
high voltage transmission lines. These members provide service across much of Utah,
Wyoming, Montana, Idaho and Oregon, and parts of Washington and California.
NTTG is committed to coordinating sub-regional planning efforts with adjacent sub-regional
groups and other planning entities. It is expected that the Western Electricity Coordinating
Council will continue to be responsible for coordinating and promoting electric system reliability
across the Western Interconnection through its role in regional reliability planning and facility
rating, and by providing economic
Transmission
State Regulatory
State Consumer
planning services to its members
Providers
Commissions
Advocacy Groups
through its Transmission Expansion
Planning Policy Committee.
Steering
NTTG performs both reliability and
Committee
economic planning coordination,
and has started by identifying
projects that have been previously
Transmission Use
Planning
Cost Allocation
studied and which spurred interest
Committee
Committee
Committee
from members within the NTTG
service area. NTTG works with the
WECC Planning Coordination
Biennial Integrated
Regional
Committee for reliability planning,
Transmission Plan
the WECC TEPPC for economic
planning, and is working to
Figure 2: Structure of the Northern Tier Transmission Group
implement a framework for
cooperation with neighboring subregional planning entities.
Stakeholder participation is important to the processes of the Northern Tier Transmission Group
and all interested parties are encouraged to attend and contribute to the many stakeholder
meetings conducted by the transmission use, planning and cost allocation committees, and in
preparing, developing and analyzing planning studies. A chronology of 2007 activities is
provided in Table 2, below.
2007 Annual Planning Report | The Northern Tier Transmission Group
4
NTTG – Chronology of 2007 Activities
Table 2: Chronology of NTTG Activities in 2007
Jan
9
Transmission Use Committee meeting
30
Area Control Error Diversity Interchange presentation
31
Public stakeholder meeting
Feb
16
FERC issues Order 890. Among other things, it requires a ‘straw man’
proposal outlining a process for complying with the planning principals
adopted in the Final Rule.
Mar
13
Transmission Use Committee meeting
14
Public stakeholder meeting to initiate development of the Straw Proposal.
15
Order 890 Final Rule posted in the Federal Registry.
23
Initial conference call to begin coordinating sub-regional planning with other
groups in the Western Interconnection, discuss order 890 compliance.
4
Northern Tier co-chair discussed the group’s efforts to comply with Order
890 with the Committee on Regional Electric Power Cooperation (CREPC).
6
Public meeting with the Northwest Transmission Advisory Committee and
Columbia Grid to discuss Order 890 compliance requirements and
approaches to integration and cooperation.
10
Northern Tier participated with the Western Electricity Coordinating Council
in a public meeting to discuss planning roles and relationships among
regional, sub-regional and transmission provider planning groups.
14
Planning & Stakeholder meeting
16-May 7
Open comment period for the Northern Tier Straw Proposal
23-24
Northern Tier public stakeholder meeting for final walkthrough and review of
the Northern Tier Straw Proposal.
29
Northern Tier Straw Proposal posted on the Northern Tier Web site and on
the transmission providing members’ OASIS sites.
Jun
13
Northern Tier presentation at FERC Technical Conference, Park City, Utah
Jul
9
Public stakeholder meeting – Planning
10
Transmission Use Committee meeting
Aug
20
Public stakeholder meeting – Planning
Oct
22
Public stakeholder meeting – Planning
Nov
7
Public stakeholder meeting
13
Public stakeholder meeting – Planning
16
Cost Allocation meeting
17
Joint Cost Allocation & Planning meeting
Apr
May
Dec
5
NTTG – Chronology of 2007 Activities | 2007 Annual Planning Report
Transmission Queue – NTTG Companies
The Northern Tier Transmission Group’s member transmission providers elicit requests for
transmission service from generation builders, electricity users and others in the first quarter of
each year in accordance with their Open Access Transmission Tariffs. Figure 3, below, shows
the amounts of capacity requested in the 2007 solicitation, along hypothetical paths between
different regions within the Northern Tier footprint.
Most of these requests are for service beyond current and forecasted Assured Transfer
Capability, given the existing transmission system and planned loads and resources.
To meet these needs in a timely fashion, a “Fast-Track” planning process was established and a
set of transmission additions were identified.
Figure 3: Northern Tier 2007 Transmission Request Queue
2007 Annual Planning Report | Transmission Queue – NTTG Companies
6
The Northern Tier Fast-Track Planning Process
Here are the steps followed in the fast-track planning process:
1) Review, with stakeholders, past transmission provider studies and additional data to identify
congested transmission that impedes efficient and reliable operation of the grid
2) Collect and review information available from the Western Electricity Coordinating Council and others
regarding future projects that affect the Northern Tier footprint
3) Review the RMATS and SSG-WI congestion studies, and historical Available Transmission Capacity
and utilization data from the Northern Tier Transmission Use Committee
4) Acquire, review and align loads and resources and Integrated Resource Plan data for member
transmission providers, augmenting and revising to accommodate shareholder input
a) Update and finalize 5-, 10- and 15-year load projections
5) Tabulate Available Transmission Capacity and Transmission Service Requests from member
transmission providers
6) Aggregate load and resource needs, locating them geographically and compare to existing
transmission path capabilities to determine if additional transmission construction is needed
7) Review expansion requirements with stakeholders
8) Identify hub and spoke candidates
9) Review RMATS and other studies’ recommended capacity expansions
10) Northern Tier transmission providers select transmission expansion candidates, identifying Fast Track
Projects by June 30, 2007
11) Each project sponsor develops a technical study plan that:
a) Identifies interested parties
b) Identifies affected parties
c) Invites participation in study efforts
d) Coordinates with other regional and sub-regional planning groups
e) Establish meeting times and locations, coordinated via Northern Tier with other sub-regional
planning groups and the Western Electricity Coordinating Council
f)
Defines a technical studies process to be integrated with the WECC Regional Planning Review
and Three-Phase Rating Process
12) Each project sponsor performs required WECC Regional Planning Review Process studies, Phase I,
Phase II rating studies, and submit to Northern Tier Planning Committee to review and present to
stakeholders
13) Northern Tier facilitates project implementation and coordination with the Western Electricity
Coordinating Council and other sub-regional planning groups.
14) Cost Allocation Committee processes Fast-Track Projects in the 2008 Biennial Planning Process as a
pilot project
7
The Northern Tier Fast-Track Planning Process | 2007 Annual Planning Report
The NTTG Fast-Track Projects
Figure 6, below, is a map of the Western Interconnection showing the set of transmission
improvements designed by the Northern Tier transmission providers to accommodate projected
needs for future capacity. The lines comprise the ‘Fast-Track Projects’ which provide for
pressing development needs and constitute the first iteration of the Northern Tier planning
process.
The primary benefit of the Fast-Track expansion plan is the timely connection of substantial and
diverse resource development in the sparsely populated Mountain States with population
centers along the West Coast and in the Desert Southwest. In addition, the interties will allow
significant diversity transactions among the distinctly different climate, weather and resource
regimes of the Western Interconnection.
Load Growth
Figure 4: Northern Tier Fast-Track Project Map with Potential Resource Additions
The table and map on the next page show the principal projects in the Fast-Track Program, their
points of termination, voltages, potential routes, current status and anticipated completion dates.
2007 Annual Planning Report | The NTTG Fast-Track Projects
8
Table 3: Fast-Track Project Data
Project Name
Voltage
(kV)
States
Length
(Miles)
Gateway South
500/345
WY, UT, NV
450±
Gateway West
500/230
WY, ID,OR
650
Gateway Central
345
ID, UT
136
HemingwayBoardman
500
ID, OR
230
HemingwayCaptain Jack
500
ID, OR
320
Mountain States
Transmission Intertie
500
MT, ID
460
SouthWest Intertie
Project - North
500
ID, NV
230
WECC
Rating
Phase
Permit
Status
InService
Year
In Phase 1
Applications
Submitted
2014
In Phase 1
Applications
Submitted
2012
In Phase 1
2010
In Phase 1
Applications
Submitted
2012
In Phase 1
2014
Phase 1
Complete
In Permitting
Process
2013
In Phase 1
Active in
Siting
2011
Figure 5: Map of Fast-Track Transmission Showing Voltage & Points of Connection
Townsend
WASHINGTON
MONTANA
Boardman
HemingwayBoardman
Mountain
States Intertie
Idaho Power
NorthWestern Energy
OREGON
HemingwayCaptain Jack
Gateway West
IDAHO
PacifiCorp
Idaho Power
Hemingway
PacifiCorp
Midpoint
Captain Jack
Legend
LSPower
Windstar
Aeolus
Populus
Cedar Hill
SWIP North
WYOMING
Bridger
Gateway
Central
PacifiCorp
Terminal
Existing
230 kV
Ely Energy Center
345 kV
345 kV Double Circuit
500 kV
Mona
UTAH
NEVADA
Gateway South
PacifiCorp
Sigurd
500 kV Double Circuit
CALIFORNIA
Crystal
9
ARIZONA
NEW MEXICO
NTTG Project Development Timelines | 2007 Annual Planning Report
NTTG Project Development Timelines
Figure 6: Development Timelines for Northern Tier Projects
2007 Annual Planning Report | NTTG Project Development Timelines
10
The Sub-Regional Planning Process
In addition to and in parallel with their Fast-Track Project activities, the Northern Tier
Transmission Group and its member transmission providers developed, in 2007, individual
Attachment K planning processes and a two-phase sub-regional Northern Tier Biennial Planning
Process. Initiated in January, 2008, the steps of the Biennial Planning Process include:
Phase 1: Northern Tier Transmission Group Planning Process
1. Annual Planning Process – identify needs, least cost expansion project
alternatives, technical benefits, and project costs.
2. Planning Committee – identify expansion beneficial projects with sponsorrecommended cost and benefit allocations.
3. Cost Allocation Committee – reviews identified projects, applies principles and
recommends likely cost allocation.
4. Planning Committee – develops and circulates a Draft Annual Expansion Plan.
5. NTTG Steering Committee – approves the draft expansion plan.
6. Final Annual Expansion Plan – includes likely cost and benefit allocation
estimates for the given planning assumptions.
7. Planning Estimates – for expansion projects, congestion and re-dispatch, and
additional assured transfer capability, costs and cost allocations are prepared by
the Economic Study Process with input from the Transmission Use Committee.
8. Customer Decision Process – customers, other stakeholders and interested
parties are informed of and asked to comment on the plan and its estimated
impacts, costs and benefits.
9. Formal Open Access Transmission Tariff Service Request Process – customers
make network transmission and point-to-point transmission requests via the
transmission providers’ Open Access Transmission Tariffs and planning for firm
needs and reliability is undertaken by members.
Phase 2: Transmission Provider Project Implementation Process
1. Transmission providers and project sponsors will finance projects, facilitate
permitting, and implement their formal Open Access Transmission Tariff
processes.
2. Service Request Aggregation Process – Northern Tier Transmission Group may
facilitate open seasons or coordinate requests made of individual transmission
providers as appropriate and requested.
3. Steering Committee – may initiate coordinated queues and consolidated
transmission service request processes in the future.
11
The Sub-Regional Planning Process | 2007 Annual Planning Report
4. Transmission Providers’ Formal Open Access Transmission Tariff Process
5. Transmission Providers – undertake transmission construction, including detailed
planning, permitting and building.
6. Transmission Providers – each undertakes its own regulatory approval and rate
process.
Relationships among Planning Entities in the West
Transmission planning in the Western Interconnection has evolved to incorporate three distinct
levels activity: Transmission providers, sub-regional transmission groups, and regional planning
entities. The relationships among regional, sub-regional and individual transmission providers
are shown in the following diagram:
Deseret G&T
Local Planning Processes
Idaho Power
Local Planning Processes
Northern Tier Transmission Group
Sub‐Regional Planning Processes: •Aggregated Planning Requests
•Cost Allocation Estimates
•Coordination with Other Regions
Northwestern Energy
Local Planning Processes
Western Interconnection Regional Planning
PacifiCorp
Western Electricity Coord. Council
Comm. on Regional Electric Power Coop.
Western Governors Association
Local Planning Processes
Additional Members
•Policies
•Standards
•Coordination
•Reliability & Economic Data
•Base Cases
•Annual Study Plan
•Economic Studies
•Congestion Analysis
Local Planning Processes
Transmission Provider
Local Planning Processes
Transmission Provider
Local Planning Processes
Transmission Provider
Local Planning Processes
Other Sub‐Regional Transmission Groups
Sub‐Regional Planning Processes
Figure 7: Three-level Planning Process in the Western Interconnection
Individual transmission providers were once (for the most part) fully-integrated generation,
transmission and distribution utilities that, with deregulation, have now changed focus to provide
equal access to all markets and customers.
The transmission providers each develop and maintain an Open Access Transmission Tariff
that receives and acts on requests for transmission service in accordance with a well-defined
procedure. The transmission providers also assess future load and resource developments to
2007 Annual Planning Report | Relationships among Planning Entities in the West
12
plan the evolution of an efficient transmission system, and undertake reliability analysis and
improvements.
Where service requests and other identified needs call for the development of transmission that
involves participation of multiple transmission providers within a sub-regional transmission
group’s footprint, the planning and analysis of improvements are coordinated at the sub-regional
level. Projects that span greater distances are planned, analyzed and developed in
coordination with other sub-regional groups or at the regional WECC level.
13
Relationships among Planning Entities in the West | 2007 Annual Planning Report
Regional and Sub-Regional Planning Timelines
The Northern Tier Transmission Group’s planning timelines are designed to coordinate with
those of the Western Electricity Coordinating Council, with a two-year cycle for transmission
expansion and reliability and a one-year economic study cycle that examines preliminary plans
for the first year of the biennial cycle, and draft plans for the second year of the preceding cycle.
Sep
2007
Oct Nov Dec Jan
Feb Mar
2008
Apr May Jun Jul
Execute Studies
Analyze
Aug Sep
Oct
Nov Dec Jan
2009
Feb Mar
Apr
Western Electricity Coordinating Council
Regional Planning Process Timeline
Get Approvals
Prepare Report
2007 Cycle
Prepare Database
Take Requests
Analyze
Develop Study Plans
Prepare Report
Execute Studies
Historical Data Analysis
Get Approvals
2008 Cycle
Prepare Database
Take Requests
Northern Tier Transmission Group
Sub-Regional Planning Process Timeline
Develop Study Plan
2009 Cycle
2008 Bienniel Cycle - Year 1
Gather Data
Do Study Plan
Analyze
Draft & Review
Take Requests
Econ Studies
Report & Review Results
Take Requests
Econ Studi
2008 Annual Cycle
Sep
2008
Oct Nov Dec Jan
Feb Mar
2009
Apr May Jun Jul
Aug Sep
Oct
Nov Dec Jan
2010
Feb Mar
Apr
2008 Bienniel Cycle - Year 2
Analyze
Draft & Review
Cost Allocation
Gather Data
Do Study P
Report & Review Results
Take Requests
Econ Studies
Report & Review Results
Take Requests
Econ Studi
Gather Data
Do Study Plan
Analyze
Draft & Review
Final Approval
Report, Review
Final Approval
2009 Biennial Cycle - Year 1
Figure 8: Timelines for Regional & Sub-Regional Planning
2007 Annual Planning Report |
14
Details of the Northern Tier Transmission Projects
Mountain States Intertie
NorthWestern Energy
Black Hills
Hem ingway-Boardman
Idaho Power
Hem ingway-Captain Jack
Gateway West
PacifiCorp
PacifiCorp
Idaho Power
S WIP North
Hyperlinks:
LS Power
Gateway
C entral
PacifiCorp
NTTG.biz
Gateway South
PacifiCorp
Northern Lights
(D C Projects)
TransCanada
TransWest Express
National Grid
Arizona Public Service
Wyoming Infrastructure Authority
Figure 9: Proposed Transmission Projects as of December 2007
The following pages provide maps and descriptions of major components of the Northern Tier
Transmission Group’s projects. Following these overviews, in the table of References, are links
to Web pages containing additional information for the projects.
Note: At the time of this report, the Sigurd-Crystal segment of the Gateway South was being evaluated in the WECC
Phase 1 Rating Process as a 500-kV line.
15
Details of the Northern Tier Transmission Projects | 2007 Annual Planning Report
Hemingway to Boardman Transmission Project
The project consists of a single-circuit 500-kV transmission line with a proposed bi-directional
rating of 1000 MW stretching about 230 miles from Hemingway substation (formerly Melba)
southeast of Boise, Idaho, to a new substation being planned near Boardman, in north-central
Oregon.
This project, sponsored by Idaho Power, is designed to provide for anticipated service-area load
growth and to meet transmission service requests. By 2017, Idaho Power forecasts an
additional 800 MW of Idaho native load. Further, Idaho Power is obligated, pursuant to its Open
Access Transmission Tariff, to plan and expand its transmission system based on needs of its
network customers and eligible customers that agree to expand the Idaho Power transmission
system.
Boardman
Constraints on the existing
Idaho to Northwest
transmission path (Path 14)
prevent Idaho Power from
meeting transmission
requests currently in its
queue. Path 14 is currently
rated at 1,200 MW with a
summer operating transfer
capability of 1090 MW westto-east, and is fully
subscribed.
The Hemingway-toBoardman Transmission
Hemingway
Project was initiated in
Figure 10: Map of Hemingway-to-Boardman Transmission Project
response to a transmission
request submitted by Idaho
Power’s merchant group and was identified in Idaho Power’s 2006 Integrated Resource Plan to
access Pacific Northwest energy resources to serve Idaho Power’s growing customer needs.
The Rocky Mountain Area Transmission Study (RMATS) of 2004 evaluated many expansion
scenarios, with the Phase 1 Report including a Midpoint-to-Oregon transmission path as a
recommended transmission path to support the development of Wyoming resources beyond the
RMATS study footprint, providing an estimated annual savings of $516 million.
A Regional Planning Review Group was established and held its first meeting on September 7,
2007, with additional stakeholder meetings on October 17 and November 13. Meeting notices,
presentations and minutes were posted on Idaho Power’s OASIS Web site
(http://www.oatioasis.com/ipco/index.html).
2007 Annual Planning Report | Hemingway to Boardman Transmission Project
16
Hemingway to Captain Jack Transmission Project
Northern Tier Transmission Group member PacifiCorp is sponsoring the development of a 500kV transmission line from the Hemingway substation at Melba, Idaho (southeast of Boise), to
the Bonneville Power Administration’s Captain Jack substation near Bonanza in Northern
California. The single-circuit line will span approximately 320 miles and is planned to be in
service in 2014.
The existing Midpoint-to-Summer Lake 500 kV line between South Central Idaho and Southern
Oregon will add a terminus at the Hemingway substation. The lines will provide a robust
pathway for energy between the Pacific Coast and the Inland West.
WASHINGTON
Boardman
HemingwayBoardman
Idaho Power
OREGON
HemingwayCaptain Jack
Hemingway
PacifiCorp
Captain Jack
Figure 11: Map of Hemingway to Captain Jack Transmission Project
17
Hemingway to Boardman Transmission Project | 2007 Annual Planning Report
Southwest Intertie Project (SWIP) North
The Southwest Intertie Project is being developed by LS Power, LLC, under the name Great
Basin Transmission, LLC, in cooperation with Idaho Power, which holds the permits. Great
Basin purchased an exclusive option to build the SWIP from Idaho Power, which has studied
the project for a number of years.
The project is being
approached in two
segments, with the
SWIP North segment
being part of the
Northern Tier
Transmission Group’s
Fast-Track Project.
SWIP North is a 500kV single-circuit line
that will be built
between the Midpoint
substation in South
Central Idaho and the
White Pine Generating
Station near Ely,
Nevada.
The initial proposed
rating for the MidpointWhite Pine line is
2,000 MW in each
direction, subject to
results of the WECC
Phase 1
Comprehensive
Progress Report. The
line is proposed to be Figure 12: Map of Southwest Intertie Project (SWIP)
in service in 2011.
2007 Annual Planning Report | Southwest Intertie Project (SWIP) North
18
Mountain States Transmission Intertie Project
The Mountain States Transmission Intertie (MSTI, pronounced ‘misty’) is sponsored by
Northwestern Energy and will provide a 500-kV link of approximately 460 miles between a new
Townsend substation in Southwestern Montana and the Midpoint substation in South Central
Idaho. An intermediate connection will be made at the existing Mill Creek substation.
The MSTI will be built to meet transmission service requests and to relieve constraints on the
region’s existing transmission system. The project will also improve transmission system
reliability, meet growing electricity demand in the region, provide regional energy diversification
and make a positive economic impact on the area. The project is planned to be in service in
2013, and has a proposed
north-south rating of 1,500
MW and a prospective southnorth rating of 950 MW.
The Townsend substation will
tie into two existing 500-kV
east-west interties
approximately mid-way
between the existing
Broadview and Garrison
substations. The new line will
have series compensation and
a phase-shifting transformer to
control power flow. Series
capacitors will be located at
the Midpoint substation, while
a substation for the phaseshifting transformer and
additional series capacitors
will be built near the Mill Creek
substation.
Figure 13: Potential Route of MSTI (Dashed Line)
Northwestern Energy initiated
both the WECC Regional Planning Process and Path Rating Process in 2007. NWE submitted
the Final Regional Planning Project Report to complete the Regional Planning Process in March
2008 after a 30-day comment period. In early April, NWE will finalize and submit its Comprehensive Progress Report to the Western Electricity Coordinating Council for the required 60-day
comment period to complete the Phase 1 Path Rating Process.
19
Gateway West Transmission Project | 2007 Annual Planning Report
Gateway West Transmission Project
The Gateway West Transmission Project is sponsored by Idaho Power and PacifiCorp, and is
planned to provide for growth in load within the service territory of the two companies. The
project will also meet their obligation to plan for and expand their transmission systems based
on the needs not only of native load customers but network customers and eligible customers
that agree to expand the transmission system.
The project was announced in May of 2007. It is a part of PacifiCorp’s broader Energy Gateway
initiative, which also encompasses the Gateway South and Gateway Central Transmission
Projects. The project is comprised of a number of new substations and a new, primarily 500-kV
pair of lines from a new Windstar substation near the Dave Johnston power plant in Eastern
Wyoming to the Hemingway substation near the western border of Idaho.
The project has a proposed combined rating of 3,000 MW, and will parallel three existing
WECC-defined bulk power transmission paths: TOT 4A (Path 37), Bridger West (Path 19), and
Borah West (Path 17). Besides the terminating Windstar and Hemingway substations, new
stations will be built at Aeolus (to integrate new generation resources and to provide connection
with the Gateway South Project), Populus (to connect with Path C transmission into Utah), and
at Cedar Hill (to tie the more southern of the two lines into the Midpoint substation for increased
reliability).
Figure 14: Map of the Gateway West Transmission Project
2007 Annual Planning Report | Gateway West Transmission Project
20
Gateway South and TransWest Express
The Gateway South Transmission Project is part of PacifiCorp’s Energy Gateway initiative and
proposes new high-voltage transmission between Wyoming and Southern Nevada. Arizona
Public Service, the Wyoming Infrastructure Authority and National Grid are proposing a similar
line from Wyoming through Southern Nevada and prospectively on to the Phoenix, Arizona
area.
Recognizing a number of common
interests and similar planning and
development requirements, the
participants in the two projects an
interim agreement in August of 2007
to pursue initial development while
more complex technical and
regulatory issues were considered.
The joint effort undertook a common
project team implementation strategy
and resource deployment, led by
National Grid, coordinating Regional
Planning and Rating Review
processes, coordinating
environmental permitting, and
engaging in a common stakeholder
and public outreach.
Each project would undertake its own
right-of-way filings, WECC rating
process and regulatory filings.
Figure 15: Map of Gateway South and TransWest
Express Proposed Study Areas
The Gateway South project calls for a
500-kV line from the proposed new
Aeolus substation in Southeast
Wyoming to the Mona substation in
Central Utah, to be completed by
2013. A 345-kV line will be built from the existing Sigurd substation (about 50 miles south of
Mona), through the Red Butte substation in the southeast corner of Utah, to the Crystal
substation north of Las Vegas, Nevada, with completion scheduled for 2012.
21
Gateway South and TransWest Express | 2007 Annual Planning Report
Gateway Central Transmission Project
PacifiCorp is sponsoring a double-circuit 345-kV transmission line from a new Populus
substation near Downey, Idaho, 136 miles south to the existing Terminal substation near the
Salt Lake International Airport west of Salt Lake City, Utah. The line is being developed in two
segments that will link north of Ogden, Utah, at the Ben Lomond substation. The southern
segment is planned to be in service in March of 2010, while the northern segment is targeted for
June, 2010.
The line is intended to
increase the ability to
deliver electricity to the
fast-growing population
along the Wasatch front
of Utah in an efficient
and cost-effective
manner.
The new transmission
lines and expanded
substations will also
provide for improved
reliability and
operational flexibility
with future generation
resources, including
renewable resources
such as wind
Figure 16: The Gateway Central Transmission Project
2007 Annual Planning Report | Gateway Central Transmission Project
22
NorthernLights Transmission– Inland Project
NorthernLights is a TransCanada initiative that proposes three major high-voltage direct current
(HVDC) transmission lines linking low cost, environmentally attractive fossil fuelled and
renewable generation with growing loads in the Pacific Northwest, Nevada, Arizona and
California.
The NorthernLights initiative consists of two projects – the Celilo Project between Northern
Alberta and the Bonneville Power Administration’s Big Eddy substation next to the high voltage
direct current inverter station at Celilo near The
Dalles, Oregon, and the Inland Project
connecting Montana and Wyoming generation
to Las Vegas and electricity users in Southern
California and the Desert Southwest.
The Celilo Project is being developed in
coordination with the Western Electricity
Coordinating Council and the ColumbiaGrid
regional transmission group.
The Inland Projects consist of two HVDC
transmission lines to Las Vegas, with one line
beginning in Wyoming and the other in
Montana. Several major inter-regional high
voltage transmission paths are already
interconnected at substations in the Southern
Nevada area.
The lines will connect wind generation
resources in Montana, Wyoming and other
western states with growing loads in Southern
Nevada, Arizona and California.
Extension of the Inland Project lines to
southern California and Arizona is
contemplated as market conditions evolve.
Current plans call for the two 500-kV direct current lines to be energized in 2014. It is
anticipated that they will carry up to 3,000 megawatts each and cost between $1.5 and $2.0
billion to construct.
23
NorthernLights Transmission– Inland Project | 2007 Annual Planning Report
Internet Links and Other References
Regional Planning
ƒ
Western Electricity Coordinating Council
(http://www.wecc.biz)
o
Transmission Expansion Planning Policy Committee
Western Interconnection economic transmission expansion planning support
o
Planning Coordination Committee
Evaluate transmission design and expansion, recommend criteria for reliable operation
ƒ
Committee on Regional Electric Power Cooperation
(http://www.westgov.org/wieb/site/crepcpage/)
A committee of the Western Governors Association’s Western Interstate Energy Board
Sub-Regional Planning
ƒ
Northern Tier Transmission Group
(http://www.nttg.biz)
ƒ
ColumbiaGrid
(http://www.columbiagrid.org)
ƒ
WestConnect (and Sub-Groups)
(http://www.westconnect.com/planning.php)
o
Colorado Coordinated Planning Group
o
National Renewable Energy Laboratory
o
Sierra Pacific Planning Group
o
Southwest Area Transmission
Northern Tier Transmission Group Members
ƒ
Deseret Generation & Transmission
(http://www.oasis.pacificorp.com/oasis/dgt/main.html)
ƒ
Idaho Power Company
(http http://www.oatioasis.com/ipco/index.html)
ƒ
Northwestern Energy
(http://www.oatioasis.com/NWMT/index.html)
ƒ
PacifiCorp
(http://www.oasis.pacificorp.com/oasis/ppw/main.htmlx)
ƒ
Utah Associated Municipal Power Systems
(http://www.uamps.com)
2007 Annual Planning Report | NorthernLights Transmission– Inland Project
24
Integrated Resource Plans
ƒ
Idaho Power Company
(http://www.idahopower.com/energycenter/irp/2006/)
Idaho Power is currently developing its 2008 Integrated Resource Plan, and preliminary information will be
made available on its Web site as it is evolved.
ƒ
NorthWestern Energy
(http://www.northwesternenergy.com/display.aspx?Page=Default_Supply_Electric&Item=16)
NorthWestern does not produce an ‘Integrated Resource Plan’, per se, but they maintain and make
available an “Electric Default Supply Resource Procurement Plan.’
ƒ
PacifiCorp
(http://www.pacificorp.com/Navigation/Navigation23807.html)
PacifiCorp’s currently posted plan was completed in May of 2007, and development of the 2008 IRP is
currently underway.
Additional Information for Northern Tier Transmission Projects
•
Hemingway to Boardman
•
Hemingway to Captain Jack
•
Gateway Central
(http://www.pacificorp.com/Article/Article79647.html)
•
Gateway South
•
Gateway West
(http://www.idahopower.com/newsroom/projnews/Gateway/)
•
NorthernLights
(http://www.transcanada.com/company/northernlights.html)
•
Mountain States Transmission Intertie
(http://www.msti500kv.com/default.htm)
•
Southwest Intertie Project - North
•
Transwest Express
(https://transwest.azpsoasis.com/)
25
NorthernLights Transmission– Inland Project | 2007 Annual Planning Report
EXHIBIT 3
Brian Silverstein
Chair, Planning Coordination Committee
Bonneville Power Administration
(360) 418-2122
blsilverstein@bpa.gov
May 28, 2008
PLANNING COORDINATION COMMITTEE
TECHNICAL STUDIES SUBCOMMITTEE
Subject: Acceptance of Regional Planning Report for the Gateway South Project
On June 25, 2007, PacifiCorp notified the Western Electricity Coordinating Council (WECC)
that it was initiating the WECC Regional Planning Review Process for the Gateway South and
Gateway West Projects. Since the initiation of the Gateway South project, four stakeholder
meetings occurred to solicit interest in the project. The meetings were held on October 17,
November 7 and December 5 of 2007, with a final stakeholder meeting January 23, 2008 for the
Project Rating Review Process.
The Gateway South Project as proposed by PacifiCorp is a 500 kV EHV AC transmission line
that is approximately 770 miles long. This project will have two separate timeframes to serve
load in growing markets. The first portion of the project is for a single-circuit 500 kV
transmission line approximately 330 miles that starts at the Mona substation in Utah and
terminates at the Crystal substation near Las Vegas, Nevada with a planned in-service date of
2012. The second portion of the project is a double-circuit 500 kV transmission line
approximately 400 miles originating at a new substation, Aeolus, in southeastern Wyoming and
continues to the Mona substation, with an in-service completion date of 2014.
On March 28, 2008, the Regional Planning Project Report for the project was provided to PCC
for a 30-day comment period. This comment period allowed PCC members the opportunity to
review and comment on the project conformity with the Regional Planning Guidelines. No
comments were received during the 30-day comment period. Accordingly, this letter serves as
notification that the Regional Planning Project Review has been completed for the Gateway
South Project.
Sincerely,
Brian Silverstein
Brian Silverstein
cc: Kent Bolton, WECC
Tom Green, TSS Chair
Darrell Gerrard, PacifiCorp
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L • W W W . W E C C . B I Z
615 ARAPEEN DRIVE • SUITE 210 • SALT LAKE CITY • UTAH • 84108-1262 • PH 801.582.0353 • FX 801.582.3918
Brian Silverstein
Chair, Planning Coordination Committee
Bonneville Power Administration
(360) 418-2122
blsilverstein@bpa.gov
May 30, 2008
PLANNING COORDINATION COMMITTEE
TECHNICAL STUDIES SUBCOMMITTEE
Subject: Acceptance of Regional Planning Report for the Gateway West Transmission Project
On July 5, 2007, Idaho Power Company (IPC) notified the Western Electricity Coordinating
Council (WECC) that it was initiating the WECC Regional Planning Review Process for a
transmission project from Jim Bridger to Northeastern Oregon. During this process, two distinct
projects, serving different purposes, emerged: the Gateway West Transmission Project, and the
Hemingway to Boardman Transmission Project. Idaho Power and PacifiCorp are proposing the
Gateway West Transmission Project because of service area load growth internal to both
companies. Idaho Power forecasts the need for 800 MW of additional power to serve its
southern Idaho load by 2017 and PacifiCorp forecasts that its load on the Wasatch Front of Utah
will double in the next 20 years. Additionally, both companies have independent obligations,
pursuant to their Open Access Transmission Tariffs, to plan for and expand their respective
transmission systems based upon the needs of their native load and network customers along
with eligible customers that agree to expand the transmission system.
Regional Planning for this project was coordinated through the Northern Tier Transmission
Group (NTTG) planning process. A Regional Planning Review Group (RPRG) was formed and
consisted of representatives from PacifiCorp, Deseret Power Electric Cooperative, NorthWestern
Energy and Utah Associated Municipal Power Systems, and utility commission representatives
from the states of Idaho, Oregon, Utah, Wyoming and Montana.
On February 27, 2008, the Regional Planning Project Report for the project was provided to PCC
for a 30-day comment period (Report and request letter dated February 19, 2008). This comment
period allowed PCC members the opportunity to review and comment on the project conformity
with the Regional Planning Guidelines. One comment and a request for additional information
were received during the 30-day comment period. The commenter agreed that the requested map
correction would be done in the Comprehensive Report and that the Regional Planning Report is
acceptable. Accordingly, this letter serves as notification that the Regional Planning Project
Review has been completed for the Gateway West Transmission Project.
Sincerely,
Brian Silverstein
Brian Silverstein
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L • W W W . W E C C . B I Z
615 ARAPEEN DRIVE • SUITE 210 • SALT LAKE CITY • UTAH • 84108-1262 • PH 801.582.0353 • FX 801.582.3918
cc: Kent Bolton, WECC
David Angell, IPC
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L • W W W . W E C C . B I Z
615 ARAPEEN DRIVE • SUITE 210 • SALT LAKE CITY • UTAH • 84108-1262 • PH 801.582.0353 • FX 801.582.3918
EXHIBIT 4
Rocky Mountain Area
Transmission Study
Connecting the region today
for the energy needs of the future
September 2004
Table of Contents
EXECUTIVE SUMMARY.......................................................................................................................................... I
RECOMMENDED PROJECTS ........................................................................................................................................ II
Recommendation 1: Expansion Projects within the Rocky Mountain Footprint ...................................................................II
Montana System Upgrade Project ................................................................................................................................... III
Bridger Expansion Project............................................................................................................................................. IV
Wyoming to Colorado Transmission Project ................................................................................................................ IV
Recommendation 2: Export Projects beyond the Rocky Mountain Footprint ...................................................................... IV
Economic Analysis of Recommendations ........................................................................................................................VI
NEXT STEPS........................................................................................................................................................... VIII
Needed Institutional Improvements ...............................................................................................................................IX
Further following specific actions are recommended............................................................................................................. X
CHAPTER 1
- IDENTIFYING TRANSMISSION EXPANSION OPPORTUNITIES ............................. 1-1
A. THE COST OF DOING NOTHING ........................................................................................................................ 1-1
B. GENERIC BENEFITS AND COSTS OF TRANSMISSION EXPANSION ...................................................................... 1-1
Discussion of Types of Benefits and Beneficiaries............................................................................................................ 1-2
Lower Cost Generation:.....................................................................................................................................................1-2
Fuel Diversity ....................................................................................................................................................................1-2
Enhanced Competition in Energy Markets: ........................................................................................................................1-4
Local and State Economic Development:...........................................................................................................................1-4
Reliability:..........................................................................................................................................................................1-4
C. BACKGROUND AND HISTORY OF THE RMATS EFFORT ................................................................................... 1-5
RMATS Charter (excerpts) ..................................................................................................................................... 1-6
PART 1.
PART 2.
PART 3.
Goals...........................................................................................................................................................1-6
Principles.....................................................................................................................................................1-6
Operating Procedures ..................................................................................................................................1-7
The RMATS Process.............................................................................................................................................. 1-9
CHAPTER 2
-TRANSMISSION STUDY APPROACH ................................................................................. 2-1
A. INTRODUCTION ................................................................................................................................................ 2-1
B. OVERALL APPROACH....................................................................................................................................... 2-2
Production Costs..................................................................................................................................................... 2-3
Capital and Other Fixed Costs ................................................................................................................................. 2-4
C. KEY DATA ASSUMPTIONS................................................................................................................................ 2-5
Transmission Topology............................................................................................................................................. 2-5
Transmission Path Ratings and Nomograms................................................................................................................ 2-7
Powerflow Case ...................................................................................................................................................... 2-7
Electricity Demand (i.e., “Loads”)............................................................................................................................. 2-7
Natural Gas Prices................................................................................................................................................. 2-8
Coal Prices ............................................................................................................................................................ 2-8
Existing Thermal Plants.......................................................................................................................................... 2-9
Hydroelectric Resources............................................................................................................................................. 2-9
Wind Resources...................................................................................................................................................... 2-9
Congestion and Congestion Costs................................................................................................................................ 2-9
D. RESOURCE AND TRANSMISSION EXPANSION ALTERNATIVES .........................................................................2-12
E. GENERATION ALTERNATIVES FOR 2013 .........................................................................................................2-14
Alternative 1: Existing IRPs................................................................................................................................. 2-14
Alternative 2: “Quasi” IRP for the RMATS Region................................................................................................. 2-14
Alternative 3: Double the Resource Additions in Alternative 2 for Export...................................................................... 2-16
Alternative 4: Triple the Resource Additions in Alternative 2 for Export to West Coast ................................................... 2-17
F. CONCLUSIONS ................................................................................................................................................2-18
i
CHAPTER 3
- RECOMMENDATIONS FOR TRANSMISSION EXPANSION ....................................... 3-1
A. INTRODUCTION ................................................................................................................................................ 3-1
B. RECOMMENDATIONS FOR TRANSMISSION EXPANSION .................................................................................... 3-1
Recommendation 1: Projects within the Rocky Mountain Footprint .................................................................................. 3-1
Montana System Upgrade Project ......................................................................................................................................3-2
Bridger Expansion Project .................................................................................................................................................3-3
Wyoming to Colorado Transmission Project ......................................................................................................................3-4
Recommendation 2: Export Projects Beyond the RMATS Footprint................................................................................. 3-5
C. TWO REFERENCE CASES .................................................................................................................................. 3-7
All-Gas Reference Case ........................................................................................................................................... 3-8
IRP-Based Reference Case ........................................................................................................................................ 3-8
D. ECONOMIC EVALUATION ................................................................................................................................. 3-9
Production Costs..................................................................................................................................................... 3-9
E. SENSITIVITIES .................................................................................................................................................3-10
F. CAPITAL REQUIREMENTS ...............................................................................................................................3-12
G. DISTRIBUTION OF ECONOMIC GAINS AND LOSSES ..........................................................................................3-15
H. CONCLUSIONS ................................................................................................................................................3-17
CHAPTER 4
- COST ALLOCATION AND COST RECOVERY ISSUES ................................................... 4-1
State Regulation ..................................................................................................................................................... 4-5
FERC Regulation .................................................................................................................................................. 4-5
Cost of Service Methodology....................................................................................................................................... 4-6
Transmission Recommendation 1 ............................................................................................................................... 4-8
Transmission Recommendation 2 ............................................................................................................................... 4-8
Phase II Initial Step............................................................................................................................................................4-9
Develop Multi-State Pricing Principles ............................................................................................................................. 4-10
Institutionalize RMATS Regional Planning ...................................................................................................................... 4-11
Coordinate Regional Transmission Planning with LSE Resource Plans............................................................................. 4-11
Engage the Wyoming Infrastructure Authority................................................................................................................. 4-11
Pursue More Efficient Ways to Use, Operate and Expand the Transmission System..................................................... 4-12
Strengthen Regional Coordination ................................................................................................................................... 4-13
Montana System Upgrade Project............................................................................................................................. 4-14
Bridger Expansion Project...................................................................................................................................... 4-15
Wyoming to Colorado Transmission Project................................................................................................................ 4-15
CHAPTER 5
- OTHER IMPORTANT ISSUES FOR TRANSMISSION EXPANSION ........................... 5-1
WECC Regional Planning Project Review Process ........................................................................................................ 5-1
Siting and Permitting............................................................................................................................................... 5-2
Rocky Mountain State Siting Requirements ................................................................................................................. 5-4
COLORADO ....................................................................................................................................................................5-4
IDAHO .............................................................................................................................................................................5-5
MONTANA .....................................................................................................................................................................5-6
UTAH...............................................................................................................................................................................5-7
WYOMING.......................................................................................................................................................................5-9
ROIWG Case Study Results.................................................................................................................................. 5-11
TOT3............................................................................................................................................................................... 5-11
West of Naughton ............................................................................................................................................................... 5-13
Montana-Northwest............................................................................................................................................................. 5-13
Case Study Conclusions ......................................................................................................................................... 5-13
ROIWG Tariff Development Results ....................................................................................................................... 5-14
CHAPTER 6
- SUMMARY OF RECOMMENDATIONS AND NEXT STEPS .......................................... 6-1
Recommendation 1: ................................................................................................................................................. 6-1
Recommendation 2: ................................................................................................................................................. 6-1
ii
iii
Table of Figures
FIGURE E- 1: RECOMMENDATION 1 PROJECTS ............................................................................................... III
FIGURE E- 2: TRANSMISSION EXPANSION EXTENDING BEYOND THE ROCKY MOUNTAIN REGION ............... V
FIGURE E- 3: GENERATION ADDITIONS ASSUMED IN RECOMMENDATION 2................................................. VI
FIGURE E- 4: ECONOMIC BENEFITS AND LOSSES ..........................................................................................VII
FIGURE E- 5: ECONOMIC BENEFITS AND LOSSES ........................................................................................ VIII
FIGURE 1- 1: NATURAL GAS AND COAL FUEL PRICES .................................................................................. 1-2
FIGURE 1- 2: 2008 FORECASTED GENERATING RESOURCE CAPACITY IN THE WESTERN INTERCONNECTION BY FUEL
TYPE ..................................................................................................................................................... 1-3
FIGURE 1- 3: GAS-FIRED GENERATION ACCOUNTS FOR 92% OF NEWLY ADDED CAPACITY OVER THE LAST 10 YEARS
............................................................................................................................................................. 1-3
FIGURE 1- 4: PHASES OF RMATS WORK ...................................................................................................... 1-8
FIGURE 1- 5: CHRONOLOGY OF RMATS PHASE I ACTIVITIES ...................................................................... 1-9
FIGURE 2- 1: POTENTIAL BENEFITS OF NEW TRANSMISSION INVESTMENT .................................................. 2-1
FIGURE 2- 2: RMATS ANALYSIS PROCESS .................................................................................................... 2-3
FIGURE 2- 3: TRANSMISSION SYSTEM TOPOLOGY......................................................................................... 2-6
FIGURE 2- 4: RMATS REGIONAL AGGREGATION ........................................................................................ 2-6
FIGURE 2- 5: ANNUAL ENERGY (GWH) WITH COINCIDENTAL SUMMER AND WINTER PEAKS (GW) ............ 2-8
FIGURE 2- 6: EXAMPLE OF HOW CONGESTION ARISES AS LOADS GO UP DURING A TYPICAL SUMMER DAY2-11
FIGURE 2- 7: SAMPLE DURATION CURVE ................................................................................................... 2-12
FIGURE 2- 8: CONGESTION IF NO TRANSMISSION IS ADDED IN ALTERNATIVE 2 ....................................... 2-15
FIGURE 2- 9: TRANSMISSION ADDITIONS IN ALTERNATIVE 2 ..................................................................... 2-15
FIGURE 2- 10: TRANSMISSION ADDITIONS IN ALTERNATIVE 4 ................................................................... 2-17
FIGURE 3- 1: RECOMMENDATION 1: TRANSMISSION EXPANSION IN THE ROCKY MOUNTAIN AREA ............. 3-2
FIGURE 3- 2: TRANSMISSION EXPANSION EXTENDING BEYOND THE ROCKY MOUNTAIN REGION .............. 3-5
FIGURE 3- 3: GENERATION ADDITIONS ASSUMED IN RECOMMENDATION 2................................................. 3-6
FIGURE 3- 4: WESTERN INTERCONNECTION PRODUCTION COSTS .............................................................. 3-10
FIGURE 5- 1: FEDERAL LANDS AND WESTERN UTILITY GROUP CORRIDOR RECOMMENDATIONS ................ 5-3
FIGURE 5- 2: STATUS OF RECENT TRANSMISSION PROPOSAL 345 AND ABOVE ............................................. 5-4
iv
Table of Tables
TABLE E- 1: ANNUAL SAVINGS COMPARED TO REFERENCE CASES ................................................................ VI
TABLE 2- 1: ANNUAL ENERGY (GWH) WITH COINCIDENTAL SUMMER AND WINTER PEAKS (GW)............... 2-8
TABLE 2- 2: TYPICAL PLANT OUTAGE RATES ................................................................................................ 2-9
TABLE 2- 3: 2013 RESOURCE ALTERNATIVES .............................................................................................. 2-13
TABLE 3- 1: RECOMMENDATION 1: TRANSMISSION EXPANSION IN THE ROCKY MOUNTAIN AREA ............. 3-3
TABLE 3- 2: BRIDGER EXPANSION INTERFACE (PATH) CAPACITY ADDITIONS ............................................. 3-4
TABLE 3- 3: WYOMING TO COLORADO INTERFACE (PATH) CAPACITY ADDITIONS ...................................... 3-4
TABLE 3- 4: CAPACITY INCREASES FROM CONSTRUCTION OF EXPORT TRANSMISSION ................................. 3-7
TABLE 3- 5: WESTERN INTERCONNECTION PRODUCTION COSTS (VOM) (MILLIONS OF DOLLARS) .............. 3-9
TABLE 3- 6: WESTERN INTERCONNECTION PRODUCTION COST SAVINGS FROM REFERENCE CASES .......... 3-11
TABLE 3- 7: ECONOMIC COMPARISONS ...................................................................................................... 3-13
TABLE 3- 8: ANNUAL SAVINGS COMPARED TO REFERENCE CASES............................................................. 3-14
TABLE 3- 9: ANNUAL SAVINGS COMPARED TO REFERENCE CASES- ........................................................... 3-14
TABLE 3- 10: ECONOMIC BENEFITS AND LOSSES (MILLIONS OF DOLLARS) ................................................ 3-16
TABLE 5- 1: AVERAGE CURTAILMENT BASED ON HOURLY ATC, IN PERCENT OF 100MW WIND FARM TOTAL OUTPUT
........................................................................................................................................................... 5-13
TABLE 5- 2: AVERAGE CURTAILMENT BASED ON HOURLY ATC, IN PERCENT OF 500 MW WIND FARM TOTAL
OUTPUT .............................................................................................................................................. 5-14
v
Executive Summary
On August 22, 2003, Wyoming Governor Dave Freudenthal and Utah Governor Michael Leavitt
announced the formation of the Rocky Mountain Area Transmission Study (RMATS). They did so
because the electric power industry has been reluctant to invest in new transmission infrastructure
due to protracted regulatory uncertainties. Without such investment, the region1 may not be able to
tap lower cost coal and wind generation for Rocky Mountain load growth, or to export generation
to other parts of the Western Interconnection. Making greater use of the region’s coal and wind
resources can lower power costs to consumers and reduce the volatility of electricity prices.
The Governors created a charter that established the guiding principles for the RMATS effort,
which are:
•
Include all interested stakeholder individuals and groups;
•
Work together for effective solutions in a balanced, open and inclusive public process;
•
Conduct analysis of generation and transmission alternatives based on data, assumptions,
and scenarios developed by participating stakeholders;
•
Consider every need, generation technology and location option that is appropriate for the
region;
•
Evaluate all potential transmission alternatives within the region;
•
Identify the costs and benefits of generation and transmission options for serving the
electricity needs of consumers that make operational, economic, and environmental sense
for the region; and,
•
Cooperate and coordinate with the west-wide Seams Steering Group-Western
Interconnection (SSG-WI) planning effort and other sub-regional planning efforts and with
WECC in order to ensure maintaining or improving system reliability.
The RMATS footprint covers the States of Colorado, Idaho, Montana, Utah and Wyoming.
In the first phase of the RMATS process, stakeholders joined in work groups on load forecasting,
resource additions, and transmission additions which developed assumptions that were input into a
production cost model to examine the value of potential transmission expansion under different
generation scenarios. The information used in the modeling effort is publicly available. A steering
committee guided the integration of the activities of the work groups and the RMATS modeling
team to: (1) evaluate the overall economics of transmission expansion under four generation
scenarios; and, (2) identify transmission projects that may be economic and feasible because of the
savings they provide Rocky Mountain region and elsewhere in the West. The analysis tested the
sensitivity of the results under a variety of assumptions, such as high and low hydroelectric
generation, high and low natural gas prices, significant improvements in energy efficiency, and
potential imposition of constraints on carbon dioxide emissions.
1
In this Report the term “region will refer to the Rocky Mountain area of the states of Idaho, Montana, Wyoming,
Utah and Colorado except where there are references to the Seams Steering Group-Western Interconnection (SSGWI) planning effort where the Rocky Mountain area will be referred to as a sub-region.
Executive Summary
I
The most feasible transmission additions are recommended to proceed to Phase II. The purpose
of Phase II is to conduct transmission technical studies, address siting and cost assignment and
recovery issues, identify project sponsors, and arrange project financing. To jumpstart Phase II
work, RMATS formed a cost allocation and cost recovery team to begin identifying promising
approaches to financing the recommended transmission additions. The team also recommended
process improvements that would (1) make it more likely that economic transmission expansion
projects would be implemented; and, (2) set the stage for continuing improvements in transmission
planning.
Because of the potential for significant new wind generation in the Rocky Mountain region in the
near term and the unique characteristics of wind development and operation, RMATS also formed a
work group to explore ways in which the existing transmission system could be used more efficiently
to enable the development of additional wind generation. The work group found, after comparing
wind output and existing flow data on three specific transmission paths in the region, that there is
substantial physical capacity available at most times of the year that current operational practices and
tariff requirements do not make available to wind on a long-term basis. Additional study work will
be required to take into account the scheduled use of the transmission system as well as the actual
power flows. There is potential for wind to make better use of the existing system through
innovative tariff products. A “conditional firm” product would offer firm service except for certain
defined periods, and a long term “priority non-firm” product would offer a high priority non-firm
service on a long-term contractual basis. Other resources may find this product attractive also.
Contractual, tariff and operating practices limit the use of existing transmission assets. Such
institutional impediments also limit transmission access and raise the cost of operating and
expanding the grid. Removing or reducing these impediments would enable the existing system to
be used more fully and optimally, and potentially allow some capital investment in grid expansion to
be deferred. The RMATS simulation includes the benefits of a regionally operated system that
avoids rate pancaking, consolidates control areas, and removes other institutional impediments to
fuller use of the existing system.
Recommended Projects
The RMATS process identified two projects that are needed to serve load in the near-term, involve
limited investment and provide significant benefits:
•
•
A transformer replacement at Flaming Gorge to increase transfer capacity on existing lines in
southwest Wyoming and northeast Utah; and
A phase shifter on the line between Montana and Idaho to increase the control of actual flow
and usability of the path from Montana.
The Western Area Power Administration will replace the transformers at Flaming Gorge in 2006;
and Northwestern Energy, Idaho Power Company and PacifiCorp are examining the addition of the
phase shifter.
Recommendation 1: Expansion Projects within the Rocky Mountain Footprint
RMATS identified projects that would provide significant economic benefit over the longer term.
There are three discreet transmission projects within the RMATS footprint included in
Recommendation 1, and several options in Recommendation 2 for longer-term development.
Figure E-1 shows the three discrete projects included in Recommendation 1: Montana Upgrades
Executive Summary
II
(tan oval), Bridger Expansion (green oval), and Wyoming to Colorado Project (yellow oval). The
capital cost for these three transmission expansion projects is estimated to be $970 million. An
economic comparison of Recommendation 1 with the two Reference Cases indicates these three
transmission expansion projects are cost justified and capable of producing annual net savings of
$61 million to $531 million per year. While each project is discrete, the three projects together
provide the greatest benefit to the region.
Figure E- 1: Recommendation 1 Projects
Montana to
NW
Taft
Modified Interface
280 Wind
West of
Broadview
Townsend
West of
Colstrip
Broadview
Garrison
Added Resource
250 Coal
Added 345 kV Line
Montana Upgrades
50 Wind
Colstrip
359 Coal
Added Series
Compensation Only
Borah West
Midpoint
250 Wind
125 Wind
Path C
Treasureton
700 Coal
West of
Bridger
Black Hills to
C. Wyoming
Dave Johnston
575 Coal
100 Wind
Antelope Mine
Bridger E
LRS
Jim Bridger
Ben Lomond
West of
Naughton
Naughton
Miners
1150 Wind
500 Wind
Cheyenne Tap
TOT 4A
TOT 3
Ault
575 Coal
Bridger Expansion
C Wyoming to
LRS
New WY- CO lines
TOT 7
Green Valley
140 Gas
210 Gas
500 Coal
500 Wind
Recommendation 1 is predicated on the new wind capacity and coal-fired generation additions
shown on the map. The new capacity will meet expected load growth in the Rocky Mountain region
for the 2013 timeframe.
Montana System Upgrade Project
This project upgrades the existing Montana 500 kV transmission system to enable exports from the
Rocky Mountain region to the Pacific Northwest and does not require new transmission lines. By
installing series compensation in the 500 kV lines from Colstrip to Taft, adding a 500/230 kV
autotransformer at Colstrip, and adding two new substations on the 500 kV transmission system
near Ringling and Missoula, transfer capacity can be increased by an estimated 500 MW. The capital
cost for the Montana System Upgrade project is estimated to be $72 million. The resource additions
assumed include 330 MW of nameplate capacity wind generation and 609 MW of coal-fired
generation in Montana.
The Montana System Upgrade is expected to have limited siting requirements. All the impacts are
local in nature and a new transmission corridor is not required. The additions at the Colstrip and
Broadview buses constitute upgrades to existing substation sites and will have little if any
Executive Summary
III
environmental impact. The new substation sites will have minimal siting requirements. Acquisition
of sufficient land for the substations may be the most serious issue. Local opposition may be
reduced if future ties to the lower voltage systems at these two locations reduce the requirements for
new transmission in these areas as loads grow.
Bridger Expansion Project
Expansion of the Bridger 345 kV transmission system involves the addition of 345 kV transmission
facilities from Miners to Bridger in Wyoming and from Bridger to Ben Lomond in Utah and to
Midpoint in Idaho. These additions would increase transfer capacity by an estimated 1,350 MW.
Resource additions are assumed to include 1,375 MW of wind and 575 MW of coal-fired generation
in southwest Wyoming and southern Idaho. The capital cost of the Bridger Expansion project is
estimated to be $580 million.
A new transmission corridor may be required between Naughton and northern Utah, and a new
transmission corridor will be required between Bridger and Midpoint (potentially traversing an
environmentally sensitive area north of Bear Lake in southern Idaho). New substation sites could
have siting requirements. Siting issues may be reduced through use of existing lower voltage
transmission corridors.
Wyoming to Colorado Transmission Project
This project involves the addition of a 345 kV line from northeastern Wyoming across the
constrained path between Wyoming and Colorado to Denver. The new line is estimated to increase
capacity by 500 MW. The addition of series compensation to this new line (and potentially other
lines) is estimated to increase capacity by an additional 250 MW. Assumed resource additions are
500 MW of wind capacity and 700 MW of coal-fired generation capacity. The capital requirements
for the Wyoming to Colorado project are an estimated $318 million.
The new 345 kV line would have substation interconnections in Wyoming potentially in the Dave
Johnston, Laramie River Station and Cheyenne areas. It would also require an interconnection in
northern Colorado, perhaps at the Ault substation, with a final destination near the Green Valley
substation northeast of Denver. Congestion resulting from the generation additions would be
reduced from an estimated high of 73 percent to below 30 percent with these line additions.
Substantial siting work is expected. Siting issues may be reduced through use of existing lower
voltage transmission corridors.
Recommendation 2: Export Projects beyond the Rocky Mountain Footprint
In addition to the projects in Recommendation 1, RMATS recommends transmission expansions
that extend beyond the Rocky Mountain States to enable exports of generation. This is a longerterm export proposal that: (1) includes the generation assumed for the projects in Recommendation
1; (2) assumes construction of an additional 3,900 MW of coal generation and remote wind
generation; and, (3) builds two export paths to the West Coast, Nevada and Arizona markets. The
viability of Recommendation 2 depends on the fuel preferences of load-serving entities outside the
Rocky Mountain region.
Recommendation 2 includes two of five optional 500 kV paths shown in the colored ovals in Figure
E-2. Additional transmission upgrades in the Rocky Mountain region are also part of
Executive Summary
IV
Recommendation 2, including:
• Upgrading the Bridger Expansion project from 345 kV to 500 kV west of Bridger.
Specifically, new 500 kV lines would be added between Bridger and Ben Lomond, Ben
Lomond and Midpoint, Ben Lomond and Kinport, Borah and Midpoint, Borah and Ringling
(including a phase shifter), and Ringling and Broadview;
• In lieu of a line from Broadview to Ringling to Borah, a 500 kV line from Broadview to Hot
Springs may be considered; and,
• Adding new 345 kV lines between Grand Junction and Emery, Antelope and Laramie River
Station, and Dave Johnson to Bridger.
In addition, the existing IPP-Adelanto DC line would be upgraded. The capital cost for the
Recommendation 2 transmission expansion is estimated to be $4,265 million.
Figure E- 2: Transmission Expansion Extending Beyond the Rocky Mountain Region
Bell
Noxon
Taft
Ashe
Great Falls
Hot Springs
Missoula
Grizzly
Broadview
Colstrip
Midpoint
500 kV
Kinport
345 kV
Dave Johnson
Borah
Inc. DC
Consistent with Rec 1
Ringling
Option 1
Jim Bridger
LRS
Ben Lomond
Naughton
Table Mtn.
IPP
Ant Mine
Miners
Mona
Cheyenne Tap
Ault
Emery
Grand Junction
Tesla
Crystal
Added Phase Shifter
Red Butte
This recommendation
requires two 500 kV lines
for export
Option 2
Green Valley
Option 3
Market Place
Adelanto
Options 2-4
Option 4
Option 1 Only
The economic analysis for these transmission export options was based on the assumed generation
additions shown in Figure E-3.
Executive Summary
V
Figure E- 3: Generation Additions Assumed in Recommendation 2
500 Coal
950 Wind
260 Gas
500
Wind
609 Coal
100 Wind
250 Wind
1400
Coal
125
Wind
50 Gas
575 Coal
160 Wind
1000
Wind
500 Wind
200 Wind
950
Coal
250
575 Coal
140 Gas
Wind
1540 Coal
210 Gas
800 Wind
120 Wind
Economic Analysis of Recommendations
To determine the benefits from transmission expansion, annual electricity production costs were
simulated using the generation additions outlined above. The production costs were then added to
the annualized capital and other fixed costs for the resource and transmission additions. These
project cost totals were then compared with the project cost totals from two reference cases, an “all
gas” case and an “IRP case”2. Table E-1 summarizes the annual savings from Recommendations 1
and 2 compared with the two reference cases.
Table E- 1: Annual Savings Compared to Reference Cases
(Savings West-wide for Representative Year, Millions of Dollars)
Reference Case
All-Gas Case
IRP-Based Case
Recommendation 1
(531)
(61)
Recommendation 2
(986)
(516)
These estimated economic benefits are based on critical assumptions, including the future price of
natural gas and hydroelectric conditions. These benefits assumed a 2013 gas price of $6.50/MMBtu
($5.20 in 2004 dollars). If natural gas prices drop and remain at $4.50 ($3.60 in 2004 dollars) over
the long term, then the economic benefits of the Recommendations would be largely eliminated.
However, if one assumes $6.50 gas prices and low hydro conditions over time, then the annual
2
The All-Gas Reference Case assumes all load growth in the Western Interconnection is met by gas-fired
generation. The IRP-based Reference (integrated resource plan) Case is grounded in the resource plans of
PacifiCorp, Idaho Power and Xcel Energy and assumes all new generation outside the RMATS footprint is gasfired.
Executive Summary
VI
production cost savings and the net benefit from constructing the projects in Recommendations 1
and 2 are significantly higher than shown in the table. Equally important, but not evaluated in the
modeling, are the natural gas price hedging benefits of increasing access to coal and wind resources,
through new transmissions. Strategies to hedge against volatile natural gas prices are important to
provide greater stability in electricity prices.
Analyses were also performed to test the sensitivity of the findings to increased energy efficiency
and potential constraints on carbon emissions. Increased energy efficiency could reduce or eliminate
the need for new generation and transmission to meet load growth within the Rocky Mountain
region. However, in that event, the transmission expansions in the Recommendation 2 would
enable exports that reduce costs outside the Rocky Mountain region. A carbon adder of $15 per ton
would not affect the dispatch of power plants that have been constructed by the time the adder is
imposed. However, such a carbon constraint would affect the choice of new generation, an issue
addressed in utility resource plans and not in this report.
Understanding where economic benefits will fall helps to identify likely project participants. The
distribution of economic benefits from the projects in Recommendations 1 and 2 can be inferred
from the modeling data, but not precisely calculated because the model diverges from current
conditions by assuming perfect competition and locational marginal pricing. Figures E-4 and E-5
show the estimated distribution of annual economic gains based on fuel and other variables from
Recommendations 1 and 2.
Figure E- 4: Economic Benefits and Losses
(Annual Benefits in Millions of Dollars)
Recommendation 1 Compared to Reference Cases
1,800
1,600
1,400
Annual Benefits in $ millions
1,106
1,200
1,000
The Rocky Mountain region
benefits, while other regions are
largely unaffected.
800
600
290
400
200
0
(200)
Rocky Mountain
California
Northwest
Recommendation 1 Compared to IRP-Based Reference Case
Executive Summary
Desert SW
Canada
Mexico
Recommendation 1 Compared to All Gas - Reference Case
VII
Figure E- 5: Economic Benefits and Losses
(Annual Benefits in Millions of Dollars)
Recommendation 2 Compared to Reference Cases
1,742
1800
1600
1400
Both the Rocky Mountain
region and California enjoy
significant benefits. Other
regions are largely unaffected.
Annual Benefits in $ millions
1200
926
1000
800
600
400
200
0
-200
Rocky Mountain
California
Northwest
Recommendation 2 Compared to IRP - Reference Case
Desert SW
Canada
Mexico
Recommendation 2 Compared to All Gas - Reference Case
The distribution of economic gains associated with the three projects in Recommendation 1 fall
predominantly within the Rocky Mountain region. This makes a compelling case for project
beneficiaries to undertake needed technical studies and for entities in the Rocky Mountain region to
work together to develop a cost allocation and cost recovery solution to capture this benefit.
Recommendation 2 entails exports from the Rocky Mountain region that would help the West
diversify fuels and reduce opportunities to exercise market power by allowing new generators to
develop projects that compete with incumbents.
With Recommendation 2, the annual consumer and generator benefits for the Rocky Mountain
region increases to between $926 million to $1.7 billion. California consumers also stand to benefit
from Recommendation 2, by $325 million to nearly $400 million annually. These results suggest that
RMATS Phase II should coordinate work on Recommendation 2 with California’s transmission
planning institutions.
Next Steps
As an initial step under Phase II, RMATS recommends, for each of the recommended transmission
expansion projects, that the Governors of the states where the line would be sited convene a
meeting of their public utility commissioners and the CEOs of entities that would benefit for the
purpose of: (1) presenting the RMATS findings; (2) urging the beneficiaries to sponsor the projects;
Executive Summary
VIII
(3) setting in place a process to address siting and cost allocation and recovery issues, (4) assessing
financing issues; and, (5) initiating technical studies. The Governors should also consider inviting
Governors and public utility commissioners from states outside the geographic scope of the
transmission projects that would also benefit.
•
For the Montana System Upgrade Project, RMATS recommends that the Governor of
Montana convene a meeting of the CEOs of Northwestern Energy, the Bonneville Power
Administration, the Montana Public Service Commission, coal and wind power plant
developers in Montana, merchant transmission developers, and other potential project
sponsors and participants.
•
For the Bridger Expansion Project, RMATS recommends that the Governors of Idaho,
Utah and Wyoming convene a meeting of the CEOs of Idaho Power, PacifiCorp, the Utah
Associated Municipal Power Systems, the Utah Municipal Power Authority, the Wyoming
Infrastructure Authority, coal and wind power plant developers in Wyoming, the Idaho
Public Utilities Commission, the Utah Public Service Commission, the Wyoming Public
Service Commission, merchant transmission developers, and other potential project
sponsors and participants.
•
For the Wyoming to Colorado Transmission Project, RMATS recommends that the
Governors of Colorado and Wyoming convene a meeting of the CEOs of Xcel Energy,
PacifiCorp, Black Hills Power, Basin Electric Power Cooperative, Tri-State G&T, the
Western Area Power Administration, the City of Colorado Springs, the Platte River Power
Authority, the Colorado Public Utilities Commission, the Wyoming Public Service
Commission, the Wyoming Infrastructure Authority, coal and wind power plant developers
in Wyoming and Colorado, merchant transmission developers, and other potential project
sponsors and participants.
•
For the export project options included in Recommendation 2, RMATS recommends that,
depending on the option under consideration, the Governors of the affected states convene
a meeting of the interested utilities, regulatory agencies and others. For example, if an
option enhancing exports to California were being considered, we recommend that the
Governors of Utah, Idaho and California convene a meeting including PacifiCorp, the Utah
Association of Municipal Power Systems, California investor-owned and municipal utilities,
the California ISO, the Utah Public Service Commission and the California Public Utility
Commission. The Wyoming Infrastructure Authority should also be involved in meetings
associated with Recommendation 2 projects.
Following such meetings, technical studies need to be conducted to examine the impact of the
recommended projects on transmission system operations.
Needed Institutional Improvements
To improve the process of evaluating and financing transmission expansion and to operate the
existing transmission system more efficiently, RMATS recommends that:
•
Multi-State transmission expansion pricing principles be developed;
Executive Summary
IX
•
The Wyoming Infrastructure Authority be engaged in transmission expansion financing
discussions;
•
The evaluation of transmission expansion to facilitate power exports from the Rocky
Mountain region be integrated with regional planning in other parts of the Western
Interconnection;
•
Governors and regulators consider the formulation of a Regional Transmission Organization
(RTO) with features appropriate to the region, including independence and costeffectiveness; and
•
The physical transfer capacity on existing lines be better utilized by requesting that
transmission owners develop conditional firm or priority non-firm transmission products
that quantify curtailment risks and place curtailment priority for conditional firm ahead of
any non-firm transactions and curtailment priority for priority non-firm ahead of any nonfirm transactions except secondary network resource service.
Further following specific actions are recommended:
1. To address cost allocation and recovery uncertainties, RMATS recommends that the state
public utility commissions and energy agencies in the five states in the RMATS footprint
deliver a report to their Governors in six months discussing multi-state transmission
expansion cost recovery and pricing principles.
2. RMATS recommends that the regulatory commissions in Colorado, Idaho, Montana, Utah
and Wyoming enter into a memorandum of agreement adopting pricing principles, and
jointly file the MOA with FERC, requesting its endorsement. These principles would then
apply to any applications for transmission cost recovery received by regulatory commissions
within the Rocky Mountain region, providing a degree of certainty and consistency in
regulatory treatment.
3. RMATS recommends that the RMATS Steering Committee, Load Forecasting Work Group,
Resource Additions Work Group, Transmission Additions Work Group, and Cost
Allocation/Cost Recovery Team be maintained and be available to conduct additional work
as conditions warrant. An agreement among states and the electric power industry to
maintain and finance a pro-active transmission planning process in the Rocky Mountain
region is needed.
4. RMATS recommends that SSG-WI use RMATS export case analyses in the development of
an interconnection-wide “realistic” generation scenario that would be studied in late 2004
and early 2005.
Executive Summary
X
Chapter 3 - Recommendations for Transmission Expansion
A.
Introduction
As noted in Chapter 2, the Work Groups developed and evaluated generation and transmission
alternatives through a series of scenarios and simulation studies. From these economic screening
analyses and with the professional judgment of Work Group members, two recommendations are
made to expand the region’s transmission system. These recommendations are dependent upon
further technical studies to address siting, financing, cost allocation and recovery, and other issues in
RMATS Phase II. They are endorsed by the Steering Committee, and are respectfully offered to the
sponsoring Governors, State and Federal regulators and potential project participants for their
consideration.
The two transmission expansion recommendations, along with two reference cases, are described in
this chapter. Production cost results from system simulation studies are presented, as are
cost/benefit analyses that take into account production costs, capital investment requirements, and
annualized fixed costs. Economic benefits and losses are then estimated by region within the West.
Chapters 4 and 5 address the challenging issues that lay ahead for further work on these
recommendations in Phase II and beyond.
B.
Recommendations for Transmission Expansion
The RMATS Steering Committee urges that the following transmission recommendations be
pursued in Phase II:
•
Recommendation 1, consisting of three transmission expansion projects within the Rocky
Mountain region. These include a Montana System Upgrade, a Bridger Expansion, and a
Wyoming to Colorado Project.
•
Recommendation 2, consisting of a larger transmission build, extending outside the Rocky
Mountain region to enable exports from the Rocky Mountain region.
The RMATS Steering Committee also supports two projects that are currently being analyzed by
local entities. These incremental projects are relatively low-cost enhancements that provide
economic benefits and can be accomplished in the near term to resolve some immediate congestion
problems. The projects involve adding a phase shifter on the Idaho to Montana Amps line and
upgrading the capacity of two transformers on the Flaming Gorge line. The economic analysis of
these investment priorities is included in Appendix B.3.
Recommendation 1: Projects within the Rocky Mountain Footprint
Figure 3-1 shows the three discrete projects included in Recommendation 1. These expansions
include:
•
•
Montana Upgrades (tan oval),
Bridger Expansion (green oval), and
Chapter 3 Rocky Mtn. Area Transmission Study
3-1
•
Wyoming to Colorado Project (yellow oval).
This recommendation is predicated on the new wind capacity and coal-fired generation additions
as shown in Figure 3-1. The new capacity will meet expected load growth in the Rocky
Mountain region.
Figure 3- 1: Recommendation 1: Transmission Expansion in the Rocky Mountain Area
Modified Interface
Montana to
NW
Taft
280 Wind
West of
Broadview
Townsend
Montana Upgrades
50 Wind
Colstrip
250 Coal
Added 345 kV Line
Added Series
Compensation Only
West of
Colstrip
Broadview
Garrison
Added Resource
359 Coal
Borah West
Midpoint
250 Wind
125 Wind
Path C
Treasureton
700 Coal
West of
Bridger
Black Hills to
C. Wyoming
Dave Johnston
575 Coal
100 Wind
Antelope Mine
Bridger E
LRS
Jim Bridger
Ben Lomond
Naughton
West of
Naughton
Miners
1150 Wind
500 Wind
Cheyenne Tap
TOT 4A
TOT 3
Ault
575 Coal
Bridger Expansion
C Wyoming to
LRS
New WY- CO lines
TOT 7
Green Valley
140 Gas
210 Gas
500 Coal
500 Wind
The capital cost for Recommendation I is estimated to be $970 million for the three transmission
expansion projects and $6.604 billion for generating resources. Using reasonable assumptions, an
economic comparison of Recommendation 1 with the two reference cases indicates these three
projects are economic, producing annual net savings of between $61 million and $531 million.
While each project is discrete, the three projects together provide the greatest benefit to the region.
Montana System Upgrade Project
This project upgrades the existing Montana 500 kV transmission system to enable exports from the
Rocky Mountain region to the Pacific Northwest. This project does not include new transmission
lines. By installing series compensation in the 500 kV lines from Colstrip to Taft, adding a 500/230
kV autotransformer at Colstrip, and adding two new substations on the 500 kV transmission system
near Ringling and Missoula, transfer capacity on this path will increase by 500 MW. The capital
costs for the Montana System Upgrade project are estimated to be $72 million.
These transmission additions efficiently reduced the congestion created by the assumed generating
resource additions, which include 330 MW of nameplate capacity wind generation and 609 MW of
coal-fired generation in Montana. Several transmission options were considered to expand capacity
to move this additional generation, including transmission from Ringling, Montana, to Borah, Idaho,
Chapter 3 Rocky Mtn. Area Transmission Study
3-2
transmission from Colstrip to Northern Wyoming, and upgrades to the existing Montana 500 kV
system. The Ringling-Borah transmission option relieved the congestion but provided more
capacity than would be needed for the assumed generation additions. A transmission line into
Northern Wyoming did not relieve the congestion across cut planes in Montana.
The Montana System Upgrade is expected to have limited siting requirements. All the impacts are
local in nature and a new transmission corridor is not required. The additions at the Colstrip and
Broadview buses constitute upgrades to existing substation sites and will have little if any
environmental impact. The new substation sites will have minimal siting requirements. This project
may be completed within a two-year period. Table 3-1 shows the transfer capacity associated with
the Montana System Upgrade.
Table 3- 1: Recommendation 1: Transmission Expansion in the Rocky Mountain Area
Interface
Transmission
Addition
West of Colstrip
Added Series
Capacitor
Added Series
Capacitor
Added Series
Capacitor
West of Broadview
Montana to Northwest
Before
(Reverse) –
Forward
N/A - 2,598
After
Incremental
(Reverse) –
(Reverse) –
Forward
Forward
N/A – 3,098
+500
N/A – 2,572 N/A – 3,072
+500
(1,350) - 2,200 (1,350) - 2,700
+500
Bridger Expansion Project
Expansion of the Bridger 345 kV transmission system involves the addition of 345 kV
transmission facilities from Miners to Bridger in Wyoming and from Bridger to Ben Lomond in
Utah and to Midpoint in Idaho. These additions would increase transfer capacity by an estimated
1,350 MW and support the resource additions of 1,375 MW of wind generation and 575 MW of
(Bridger) coal-fired generation in southwest Wyoming and southern Idaho. The capital cost of
the Bridger Expansion project is estimated to be $580 million.
A new transmission corridor may be required between Naughton and northern Utah, and a new
transmission corridor will be required between Bridger and Midpoint (potentially traversing an
environmentally sensitive area north of Bear Lake in southern Idaho). New substation sites could
have siting requirements. Siting issues may be reduced through use of existing lower voltage
transmission corridors. This project may be completed within a five-year period. Table 3-2 shows
the increases in transfer capacity with the recommended Bridger Expansion.
Chapter 3 Rocky Mtn. Area Transmission Study
3-3
Table 3- 2: Bridger Expansion Interface (Path) Capacity Additions
Interface
Addition
Bridger West- w/
series comp
Before
After
Incremental
(Reverse)
– (Reverse) – (Reverse) –
Forward
Forward
Forward
N/A – 2,200 N/A – 3,550 +1,350
Bridger to Treasureton
345kV
Bridger to Naughton 345kV
Borah West - w/
Treasureton to Midpoint
N/A – 2,307 N/A – 3,057
+750
series comp
345kV
Loop in Ben Lomond to
(750) – 750
(1,500) –
+750
Path C- w/ series
Borah at Treasureton
With seasonal
1,500
(Nominal)
variation
West of Naughton- Naughton to Ben Lomond
N/A – 920 N/A – 1,520
+600
w/ series comp
345kV
Bridger East
Miners to Jim Bridger
(600) - 600
(1,100) –
+500
345kV
1,100
Wyoming to Colorado Transmission Project
This project involves the addition of a 345 kV line from northeastern Wyoming across the
constrained path between Wyoming and Colorado to Denver. The new line is estimated to increase
capacity by 500 MW. The addition of series compensation to this new line (and potentially other
lines) is estimated to increase capacity by an additional 250 MW and support the assumed resource
additions of 500 MW of wind (nameplate capacity) and 700 MW of coal-fired generation capacity.
The capital requirements for the Wyoming to Colorado project are an estimated $318 million.
The new 345 kV line would have substation interconnections in Wyoming, potentially in the Dave
Johnston, Laramie River Station and Cheyenne areas. It would also require an interconnection in
northern Colorado, perhaps at the Ault substation, with a final destination near the Green Valley
substation northeast of Denver. Congestion resulting from the assumed generation additions would
be reduced from an estimated high of 73 percent to below 30 percent with these line additions.
Siting issues may be reduced through use of existing lower voltage transmission corridors. This
project may be completed within a five-year period. Table 3-3 shows the increased transfer capacity
associated with the Wyoming to Colorado Project.
Table 3- 3: Wyoming to Colorado Interface (Path) Capacity Additions
Antelope Mine to DJ 345kV
Before
(Reverse) –
Forward
(332) - 332
After
(Reverse) –
Forward
(832) - 832
Incremental
(Reverse) –
Forward
+500
LRS to C Wyoming
TOT 3- w/ series comp
DJ to LRS 345kV
Cheyenne Tap to Ault 345kV
(640) - 640
N/A – 1,424
(1,140) – 1,140
N/A – 2,174
+500
+750
TOT 7- w/ series comp
TOT 4A
Ault to Green Valley 345kV
Miners to Cheyenne
Tap 345kV
N/A – 890
N/A – 810
N/A – 1,640
N/A – 1,560
+750
+750
Interface
Addition
Black Hills to C. Wyoming
Chapter 3 Rocky Mtn. Area Transmission Study
3-4
Recommendation 2: Export Projects Beyond the RMATS Footprint
RMATS also recommends transmission expansions that extend beyond the Rocky Mountain
states to enable exports of generation. This is a longer-term export proposal that: (1) includes the
generating resources assumed for the projects in Recommendation 1; (2) assumes construction of
an additional 3,900 MW of coal generation and remote wind resources; and, (3) builds two
export paths to the West Coast, Nevada and Arizona markets. The viability of Recommendation
2 depends on the fuel preferences of load-serving entities (LSEs) outside the Rocky Mountain
region.
Recommendation 2 includes two of five optional 500 kV paths shown in the colored ovals in
Figure 3-2. Additional transmission upgrades in the Rocky Mountain region beyond those
identified in Recommendation 1 are also part of Recommendation 2, including:
•
Upgrading the Bridger Expansion project from 345 kV to 500 kV west of Bridger.
Specifically, new 500 kV lines would be added between Bridger and Ben Lomond, Ben
Lomond and Mid Point, Ben Lomond and Kinport; Borah and Midpoint, Borah and
Ringling (including a phase shifter), and Ringling and Broadview.
•
Adding new 345 kV lines between Grand Junction and Emery, Antelope and Laramie River
Station, and Dave Johnston to Bridger.
The capital cost for the Recommendation 2 transmission expansion is estimated to be $4.265 billion
and $ 10.05 billion for generating resources.
Figure 3- 2: Transmission Expansion Extending Beyond the Rocky Mountain Region
Recommended for Further
Development
Bell
Noxon
Taft
Ashe
Great Falls
Hot Springs
Missoula
Grizzly
Broadview
Colstrip
Midpoint
500 kV
Kinport
345 kV
Dave Johnson
Borah
Inc. DC
Consistent with Rec 1
Ringling
Option 1
Jim Bridger
LRS
Ben Lomond
Naughton
Table Mtn.
IPP
Ant Mine
Miners
Mona
Cheyenne Tap
Ault
Emery
Grand Junction
Tesla
Crystal
Added Phase Shifter
Red Butte
This recommendation
requires two 500 kV lines
for export
Option 2
Green Valley
Option 3
Market Place
Adelanto
Options 2-4
Option 4
Option 1 Only
Chapter 3 Rocky Mtn. Area Transmission Study
3-5
The economic analysis for these export options is based on the generation additions shown in
Figure 3-3.
Figure 3- 3: Generation Additions Assumed in Recommendation 2
500 Coal
950 Wind
260 Gas
500
Wind
609 Coal
100 Wind
250 Wind
1400
Coal
125
Wind
50 Gas
575 Coal
160 Wind
1000
Wind
500 Wind
200 Wind
950
Coal
250
Wind
1540 Coal
575 Coal
210 Gas
140 Gas
800 Wind
120 Wind
Total resource additions are assumed to include 660 MW of new gas-fired generation, 4,955 MW of
remote wind resources (nameplate capacity) and 6,149 MW of coal-fired Powder River Basin
generation.
To export this remote generation, the existing IPP-Adelanto DC line would be upgraded and two
500 kV lines to export markets would be needed. Five potential paths were examined for these 500
kV lines. Study results show the economic benefits for different combinations of paths to be
similar. Decisions on which two paths to pursue will need to be determined as technical studies,
right-of-way issues, cost recovery issues, and financing options are addressed in Phase II.
Chapter 3 Rocky Mtn. Area Transmission Study
3-6
Table 3-4 summarizes the estimated increases in transfer capacity from the transmission facilities
added in Recommendation 2.
Table 3- 4: Capacity Increases from Construction of Export Transmission
Interface
Option
West of Colstrip
West of Broadview
1-4
1-4
2-4
1
1-4
1
1
Added Series Capacitor
Added Series Capacitor
Broadview to Ringling 500kV
Broadview to Hot Springs (via Great Falls) 500kV
Added Series Capacitor
Hot Springs to Noxon 500kV
Noxon to Ashe (via Bell) 500kV
2-4
1-4
1
2-4
1-4
1-4
2-4
1
2-4
1
1-4
1-4
Ringling to Borah 500 kV [phase shifter]
Bridger to Borah 500kV (series comp)
Bridger to Ben Lomond 500kV (series comp)
Bridger to Naughton 500kV (series comp)
Kinport to Midpoint 500kV (convert 345kV)
2 Borah to Midpoint 500kV
Naughton to Ben Lomond 500kV (series comp)
Bridger to Ben Lomond 500 kV
Ben Lomond to Borah 500kV
Ben Lomond to Midpoint 500 kV
Miners to Jim Bridger 345kV
Ant Mine to DJ 345kV
1-4
1-4
1-4
Montana to
Northwest
West of Hatawai
Idaho to Montana
Bridger West
Borah West
West of Naughton
Path C
Bridger East
Black Hills to C.
Wyoming
Black Hills to LRS
LRS to C Wyoming
TOT 1A
Addition
Before
(Reverse) – Forward
N/A - 2,598
N/A – 2,572
(1,350) - 2,200
N/A – 4000
(337) – 337
N/A – 2,200
Incremental
(Reverse) – Forward
+500
+500
+1000
+1000
+500
+1000
+1000
(750) -750
w/ seasonal variations
(600) – 600
(332) – 332
+1000
+1000
+1000
+1000
+500
+2000
+1000
+1000
+1000
+1000
+500
+500
Ant Mine to LRS 345kV
DJ to LRS 345kV
Emery to Grand Junction 345kV
(332) – 332
(640) – 640
N/A – 650
+500
+500
+500
N/A – 2,307
N/A – 920
TOT 3
1-4
Cheyenne Tap to Ault 345kV
N/A - 1,424
+500
TOT 7
TOT 4A
1-4
1-4
N/A – 890
N/A – 810
TOT 2C
2-3
Ault to Green Valley 345kV
Miners to Cheyenne Tap 345kV
Dave Johnston to Jim Bridger
Ben Lomond to Market Place (via Mona, Red Butte
& Crystal) 500kV [phase shifter] (series comp)
Midpoint to Market Place (via Crystal) 500kV (series
comp)
Midpoint to Tesla (via Table Mtn) 500kv (series
comp)
Midpoint to Grizzly (series comp)
(300) – 300
+500
+500
+500
+1200
N/A
+1200
N/A
+1500
(400) – 1,500
+1000
(300) – 1,920
N/A
+500
N/A
Idaho to Las Vegas
4
Idaho to N.
California
Midpoint-Summer
Lake
IPP DC
Others
1, 2, 4
2&3
1-4
1-4
1-4
Add Converter Stations
LRS to Cheyenne Tap 345kV
Borah to Kinport 345kV
C.
Two Reference Cases
Recommendations 1 and 2 are predicated on the development of remote coal and wind resources to
meet the region’s load growth and to serve export markets, and they entail substantial new
investment in transmission. Two reference cases were created to compare economic benefits of the
remote generation/transmission intensive recommendations and alternatives that do not rely on new
transmission. These reference cases avoid or minimize new transmission investment primarily by
locating new generation near loads.
Chapter 3 Rocky Mtn. Area Transmission Study
3-7
The reference cases differ in the type and location of resource additions in the Rocky Mountain
region. The All-Gas Reference Case assumes that load growth is met through new gas-fired
generation. The IRP-Based Reference Case includes new gas-fired generation, but also new coal
generation, primarily at existing sites, and new wind resources. The reference cases are similar in
that both add the same overall resource capacity, and both use the same gas and coal fuel prices and
hydro condition assumptions. Both cases assume that generation additions outside the Rocky
Mountain states after 2008 will take the form of gas-fired generation located near loads. Both cases
also include no significant transmission investment other than for resource integration. As a result,
the reference cases bracket a range of potential outcomes that would occur if little new transmission
were built.
All-Gas Reference Case: This case assumes that load growth in the Rocky Mountain states for the
2008 to 2013 period will be met exclusively by adding gas-fired generation located close to load
centers. Capital investment in this case is limited to gas-fired generation additions and associated
interconnection costs.
The All-Gas Reference Case is representative of the recent past. In the 1990’s, nearly all load
growth in the West was met by building gas-fired plants. The All-Gas Reference Case assumes this
trend will continue, and it is akin to a “do-nothing” case from a transmission expansion perspective.
This case is useful for comparing the fuel and investment costs of alternative resources, and for
measuring the value of diversifying fuels. Indeed, annual west-wide production costs in
Recommendations 1 and 2 are $1.238 to $2.560 billion lower than the All-Gas Reference Case.
IRP-Based Reference Case: This case is based on resource additions in the integrated resource
plans of LSE’s in the Rocky Mountain states, where available. Where IRPs are not available, wind
capacity is assumed to fill the gap. The IRP-Based Reference Case presumes significant wind and
some coal resources are added. Because little transmission is added in the IRP-Based Reference
Case, wind generation additions are limited by transmission capacity and the physical ability of coal
plants to rapidly cycle to meet changes in the output of wind generators1. Consequently, production
costs are substantially lower than in the All-Gas Reference Case because of lower fuel costs. Capital
requirements are higher than in the All-Gas Reference case because of the higher up-front cost of
remote coal and wind units.
The IRP-based case is a compilation of existing IRPs, and as such, represents the current planning
path for major LSEs in the RMATS footprint; but they may, however, not include the transmission
investment that would be required to integrate the wind and other resources they propose. The
annual reduction in the West’s production costs between the IRP-based and All-Gas Reference
Cases ($972 million) indicates the value that may be created by capitalizing on the region’s lower cost
fuels. To the extent that transmission bottlenecks preclude the wind and coal generation in IRPs
from being developed, this reduction in production costs would not materialize as LSEs turn to gasfired plants to meet load growth.
The reduction in annual production costs between the IRP-based reference case and
Recommendation 1 ($266 million) reflects the value that could be created by moving from
company-specific resource planning to regionally integrated resource and transmission planning.
1
There may be new coal generation technologies that could minimize the problem of cycling coal plants to
accommodate more wind generation, such as Integrated Gasification/Combined Cycle (IGCC) coal plants coupled
with temporary gas storage capability that would enable the gasification process to operate continuously, but the
burning of the gas to generate electricity could better match periods of slack wind generation.
Chapter 3 Rocky Mtn. Area Transmission Study
3-8
The two reference cases represent a range of costs for meeting load growth in the Rocky Mountain
region if transmission expansions do not occur. The following is a comparison of costs and savings
between Recommendations 1 and 2 and the two reference cases.
D.
Economic Evaluation
The economic evaluation begins with a simulation of productions costs for 2013. Sensitivities on
certain key assumptions are included. Capital requirements and annualized fixed costs are then
calculated and combined with the production costs for an overall economic comparison. The
distribution of economic gains and losses associated with changes in production costs are also
determined.
Production Costs
The simulation logic seeks to minimize production costs for the Western Interconnection, including
fuel and other variable operating and maintenance (O&M) costs. Production costs for
Recommendations 1 and 2 and the two reference cases are illustrated in Figure 3-4. Production
costs are lower in Recommendations 1 and 2 than in the two Reference Cases because the addition
of transmission and large amounts of coal- and wind generation displace higher-cost natural gasfired generation. The production costs produced in the All-Gas and IRP-Based Reference Cases are
estimated to be $21.018 billion and $20.046 billion, respectively. Production costs for
Recommendation 1 are estimated to be $19.780 billion, a reduction of $1.238 billion and $266
million, respectively, when compared to the All-Gas and IRP-Based Reference Cases. Production
costs for Recommendation 2 are estimated to be $18.458 billion, a substantially greater reduction
from the All-Gas and IRP-Based reference cases of $2.56 billion and $1.588 billion, respectively.
Table 3- 5: Western Interconnection Production Costs (VOM) (millions of dollars)
Recommendation 2
Defference
reflects
benefit of
moving
from
companyspecific
IRPs to
regionally
integrated
resource
and transmission
Wind and coal exports displace gas
$18,458 generation because fuel costs are lower
$19,780
Recommendation 1
$20,046
IRP-Bas ed Reference Cas e
Higher, more
uncertain fuel
costs than coal
$21,018and wind
alternatives
A ll Gas Reference Cas e
$18,000
$18,500
$19,000
$19,500
$20,000
$20,500
$21,000
$ Millions
Chapter 3 Rocky Mtn. Area Transmission Study
3-9
$21,500
E.
Sensitivities
The production costs in Figure 3-4 are calculated with natural gas prices of $6.50 in 2013 dollars
($5.20 gas in 2004 dollars) and medium hydro conditions. See the Key Assumptions discussion in
Chapter 2. Production costs associated with Recommendations 1 and 2 are sensitive to natural gas
prices, and, to a lesser extent, hydro conditions. Simulations were performed using a reasonable
range of potential natural gas prices and hydro conditions. Other sensitivity analyses were
performed as well. Results from all the sensitivity analyses can be seen in Appendix B.7.
Under low natural gas prices, annual production costs are lower in all cases. Even in the low gas
sensitivity, the fuel costs for coal-fired and wind resources are lower than the fuel costs for gas-fired
resources. This causes already-constructed coal-fired and wind resources to continue to be
dispatched before existing gas-fired resources. To further test this, a high gas price sensitivity of
$8.50 was performed for the All Gas Reference Case. This sensitivity results in higher production
costs ($3.5 billion increase over the $6.50 gas price case). This increase is essentially due to the
higher gas price, not to a change in redispatch of resources.
Under low hydro conditions, production costs increase in all four cases. On a comparative basis, the
savings from Recommendations 1 and 2 increase during a low water year. Production costs are
shown to be much less sensitive to hydro conditions than to gas prices.
The comparative result of these sensitivities is summarized in Figure 3-5. Note that the production
costs are lower under Recommendations 1 and 2 than the reference cases even with low gas prices.
Figure 3- 4: Western Interconnection Production Costs
(Variable Operating and Maintenance Cost in millions of dollars)
(
)
$14,988
$18,458
Recommendation 2
$20,454
$15,923
$19,780
Recommendation 1
$21,862
$16,121
$20,046
IRP- Bas ed Reference Cas e
$22,143
$16,783
$21,018
A ll-Gas Reference Case
$23,118
$14,000
$16,000
$18,000
$20,000
$22,000
$24,000
$ Millions
$6.50 gas- low hydro
$6.50 gas- medium hydro
Chapter 3 Rocky Mtn. Area Transmission Study
$4.50 gas- medium hydro
3-10
Table 3- 6: Western Interconnection Production Cost Savings from Reference Cases
($ - Millions)
All-Gas Case
Recommendation 1
Base Case
($6.50 gas-median hydro)
Low Natural Gas Price
($4.50 gas-median hydro)
Low Hydro Condition
($6.50 gas-low hydro)
Recommendation 2
Base Case
($6.50 gas-median hydro)
Low Natural Gas Price
($4.50 gas-median hydro)
Low Hydro Condition
($6.50 gas-low hydro)
Reference Case
IRP-Based Case
(1,238)
(266)
(860)
(197)
(1,257)
(281)
(2,560)
(1,588)
(1,795)
(1,132)
(2,665)
(1,689)
The robustness of Recommendations 1 and 2 was tested by assuming a significant increase in
demand-side management (DSM) activities. To reflect more aggressive DSM programs, the energy
loads within the Rocky Mountain region are assumed to grow by 1.05% less per year than in the
reference cases and that energy loads outside the Rocky Mountain region would grow by 0.51% less
per year than in the reference cases. Peak load reductions are assumed to be 1.5 times the energy
reduction. Within a couple of years of phase-in and including the five-year period between 2008 and
2013, peak loads in the Rocky Mountain region in 2013 are assumed to be reduced by 12% and
energy by 8% while in the coastal states the reduction would be half that due to their already
existing, more aggressive DSM programs. See Appendix G for discussion of these assumptions.
Using these DSM assumptions, load growth in the Rocky Mountain region between 2008 and 2013
would be only 100 MW, thus negating the need for significant transmission additions to serve load
in the region. In this case, both Recommendations 1 and 2 can be viewed as export projects.
To reflect potential carbon dioxide constraints, a sensitivity analysis was conducted assuming $5/ton
and $15/ton adders applied to CO2 emissions from new resource additions. This level of adder
does not impact the dispatch of plants that the model assumes are built, and this sensitivity showed
that the dispatch of these new resources was unaffected by these levels of adders.2
2
The impact of a CO2 adder on the decision of which existing plants to dispatch is much less than the
impact of the adder on the choice of generation plant to build. Just as the economics of choosing between driving a
car and riding a bus become dramatically different if you already own a car: All the fixed costs of owning the car
are no longer relevant and you you would compare the incremental cost of running the car to the cost of a bus ticket.
Thus, the greatest opportunity to reduce carbon emissions occurs in the choice of which resources to build. The
ABB Market Simulator focuses on the use of the transmission system and has limited abilities to analyze generation
resource choices. The models that utilities use in IRP efforts are better at evaluating resource addition options, but
these models typically have very limited capabilities to model the transmission system. A back-of-the-envelope
analysis using various assumptions (e.g., $6/MMBTU gas, 35% capacity availability for wind, 85% availability for
Chapter 3 Rocky Mtn. Area Transmission Study
3-11
F.
Capital Requirements
The west-wide reductions in annual production costs from Recommendations 1 and 2 appear large.
This conclusion is valid across a reasonable range of natural gas prices and hydro conditions, but
this potential benefit is only part of the story. Alternatives 1 and 2 contemplate substantially higher
levels of capital investment to build the needed transmission and to build coal and wind generation
resources that have higher up-front costs than gas-fired generation. The economic comparisons are
completed by combining fuel and other variable O&M costs with annualized capital and fixed O&M
costs. The total costs of Recommendations 1 and 2 are then compared to the total costs of the
reference cases for a more complete economic picture.
Table 3-7 compares the total costs of Recommendation 1 and 2 and the two reference cases.
Annualized costs associated with each scenario are shown in the column labeled “Representative
Year.” This column represents a snapshot of real levelized annual capital costs for each case. Fuel
and other variable O&M
(production costs) are combined with annualized fixed costs to give a full cost picture of each
scenario.
The annual production costs from Figure 3-6 are shown in lines 1 through 3.
Capital requirements for each case are shown in the column labeled “Initial Investment” and are
grouped into generation resource investment and transmission investment. The generation resource
investment numbers include wind, gas and coal capital investment as well as associated transmission
integration investment (lines 5 to 11). In the case of Recommendation 2, generation investment
outside the Rocky Mountain region is adjusted downward to the extent the Rocky Mountain region
builds resources for export (line 12). Transmission costs include capital investment associated with
transmission lines and any required customized equipment costs (lines 21 to 24).
Capital requirements for the All-Gas and IRP-Based Reference Cases are $2.257 and $6.012 billion,
respectively; and all of this investment is in generation with no transmission capital assumed.3
Generation capital for Recommendations 1 and 2 are $6.604 and $10.050 billion, respectively4.
Transmission capital requirements assumed for Recommendations 1 and 2 are $970 million and
$4.265 billion, respectively.
coal and gas, and assumptions on capital costs and carrying charges) indicates that even with a $5/ton CO2 adder,
coal is the lowest cost option. However, at $10/ton CO2 adder, wind becomes the lowest cost option.
3
Limited transmission investments to integrate local generation are included in the generation capital assumptions.
4
The capital requirements for Recommendation 2 include most of the capital requirements associated with
Recommendation 1.
Chapter 3 Rocky Mtn. Area Transmission Study
3-12
Wind
Gas thermal
Resource Costs:
RM Resource Additions Capex
Change from All Gas Case [Column A]
Change from IRP- Based Case [Column B]
Production Costs (Fuel & Other VOM)
Chapter 3 Rocky Mtn. Area Transmission Study
Annualized Costs
29
30
Total Initial Investment
33 Annual Net (Savings)/Cost from All Gas Case
34 Annual Net (Savings)/Cost from IRP- Based Case
31
32
Incremental Fixed O&M
Incremental Capital Charge @ 10%
RM Transmission Costs
26
27
28
25
Transmission Costs:
22 Incremental Line Capex
23 Customized Equipment Capex
24 RM Transmission Capex Sub Total
20
21
10
9
Coal thermal
Incremental Transmission Integration Capex
11 RM Resource Capex Sub Total
12 Adj. Outside RM Resource Additions Capex
13 Other RM Costs
Incremental Capital Charge @ 10%
14
Incremental Fixed O&M
15
Wind "wear and tear"
16
17 Subtotal Other RM Costs
Adj. Other Costs Outside RM
18
19 Total Resource Costs
8
7
6
5
4
3
2
1
(2004 Dollars in Millions)
2,257
2,257
53
2,257
2,204
470
254
226
28
254
254
972
21,018
6,012
6,012
3,453
159
6,012
1,957
444
Initial Investment
(470)
-
756
756
601
116
39
756
(972)
-
20,046
Representative
Year
Initial Investment
Representative
Year
B
IRP- Based Case
IRP resources and no new
transmission additions in Rocky
Mountain States (Suppressed
Wind)
Reference Cases
All Gas Case
Gas resources and no new
transmission additions in Rocky
Mountain States
A
7,574
970
777
193
970
6,604
3,985
175
6,604
2,246
198
(531)
(61)
961
19
97
116
845
660
128
56
845
(1,238)
(266)
19,780
Initial Investment Representative Year
D
14,315
4,265
3,872
393
4,265
10,050
(2,257)
7,857
311
12,306
3,766
373
Initial Investment
(986)
(516)
1,828
85
427
512
1,231
245
94
1,570
(254)
1,316
(2,560)
(1,588)
18,458
Representative
Year
Recommendation 2
Recommendations
Recommendation 1
C
Table 3- 7: Economic Comparisons
“Initial investment” amounts are translated into annualized capital charges in the column labeled
“Representative Year”. The annual capital charge reflects inflation adjusted (real) streams of
depreciation, return on capital, property and income taxes, interest, replacements and administrative
and general costs over the depreciable life of the asset. This charge is applied as a percentage of the
initial investment, and is shown on lines 14 and 27. Fixed O&M costs are then added. The sum of
the annualized capital charge and fixed O&M (line 30) is then compared to the annual production
cost savings (lines 2-3) to determine annual net savings from the two reference cases (lines 33-34).
See Appendix B.8 for a full explanation of the economic comparison table.
3-13
This analysis finds that Recommendation 1 would save $531 million annually on a west-wide basis
compared to the All-Gas Reference Case and $61 million annually compared to the IRP-Based
Reference Case.5 Recommendation 2 would save $986 million annually compared to the All-Gas
Reference Case and $516 million compared to the IRP-Based Reference Case. See Table 3-8, which
summarizes the data from lines 33-34 in Table 3-7. As noted in Chapter 2, capital investment
amounts for new gas-fired resources do not include the investment that may be required for pipeline
compression and expansion. If such investments were required, the savings for Recommendation 1
and 2 could be greater than shown.
Table 3- 8: Annual Savings Compared to Reference Cases
(Savings West-wide for a Representative Year, Millions of Dollars)
Reference Case
All-Gas Case
IRP-Based Case
Recommendation 1
(531)
(61)
Recommendation 2
(986)
(516)
An economic comparison of Recommendation 1 and 2 with the Reference Cases, using the low
natural gas price sensitivity, produces the results shown in Table 3-8. A persistent, relatively low
natural gas price assumption reduces the economic viability of Recommendations 1 and 2.
Compared to the IRP-Based Reference Case, the benefits of Recommendation 1 do not appear to
justify the required transmission investment. Compared to the All-Gas Case (which assumes heavy
reliance on gas-fired plants) the benefits of both Recommendations 1 and 2 remain economic.
Assuming high natural gas prices, the annual savings and net benefits of Recommendations 1 and 2
would be significantly higher than those shown in Table 3-8. Gas price hedging benefits provided
by new transmission and low fuel cost resources should be considered, but are not reflected in this
study. Strategies to hedge against uncertain – and potentially volatile – natural gas prices are
important in providing greater stability in electricity prices.
Table 3- 9: Annual Savings Compared to Reference CasesAssuming Low Natural Gas Prices (Savings West-wide for a Representative Year, Million of Dollars)
All-Gas Case
Reference Case
IRP-Based Case
Recommendation 1
(153)
7
Recommendation 2
(221)
(61)
5
The savings from the IRP-Based Reference Case may be understated because the IRPs may not include the
transmission investment needed to integrate the wind and coal resources they contemplate.
Chapter 3 Rocky Mtn. Area Transmission Study
3-14
G.
Distribution of Economic Gains and Losses
To advance the development of transmission expansion projects that show economic benefits on an
interconnection-wide basis, it is necessary to understand how the economic benefits and losses from
the projects are distributed within the West.
Table 3-10 shows the economic benefits (and losses) by region for Recommendations 1 and 2 in
comparison with the two reference cases. The benefits (and losses) are categorized as load benefits
and generation benefits. The numbers are derived from the production cost simulation and do not
include capital and other fixed costs (See Chapter 2 for a discussion of locational marginal prices
(LMPs) derived from the model.)
In the simulation, the Load Benefit is defined as the reduction in cost to serve regional load, and is
derived from the following: hourly demand (MWh) at each load node multiplied by the hourly LMP
($) and summed for the test year 2013.
The simulation defines Generation Benefit as the gross generator margin, and is derived from the
following: hourly generation (MWh) at each generation node multiplied by the hourly LMP ($) and
summed for 2013 (i.e., generator revenue) less annual fuel and other production costs.
The model-generated estimates of benefits and losses assume a real-time competitive market in
which pricing is on an hourly, LMP basis. Although California is moving in this direction, such
markets do not exist today in the West. For this reason, the actual distribution or sharing of the
benefits (and losses) among consumers (i.e., load) and owners of generation in each region will vary
from the distribution shown here.
Benefits will flow to consumers when reductions in the cost of serving the load are passed through
in retail rates. Benefits shown in the Generation Benefit column will mostly accrue to consumers in
retail rates if the generation is owned by a vertically-integrated utility. On the other hand, Generator
Benefits (and Losses) will accrue directly to independent power producers and merchant power
plant owners to the degree the investment is not imbedded in regulated (or public utility) rate base
pursuant to contracts between the generator and the load-serving entity. Depending on the terms of
the power purchase contract, Generator Losses may not be in the rate base of LSEs and thus would
not be borne by customers. In addition, as explained in Chapter 2, the system simulation includes
none of the rate pancaking inefficiencies of the current system. Thus, the benefits and losses shown
are in addition to benefits that would result from removing such inefficiencies. For example,
northwestern generators would probably benefit on the whole from the removal of rate pancaking,
but the losses shown in Table 3-9 do not take this benefit into account.
Chapter 3 Rocky Mtn. Area Transmission Study
3-15
Table 3- 10: Economic Benefits and Losses (Millions of Dollars)
Recommendation 1 Compared to IRP-Based Reference Case
Region
Load Benefit
Generator Benefit
Total Benefits
Rocky Mountain
Northwest
Canada
Mexico
California
Desert SW
Total
(5)
65
20
1
54
8
145
294
(78)
(20)
(1)
(110)
(9)
77
290
(13)
1
0
(56)
0
221
Recommendation 1 Compared to All-Gas Reference Case
Region
Load Benefit
Generator Benefit
Total Benefits
Rocky Mountain
Northwest
Canada
Mexico
California
Desert SW
Total
123
128
37
(1)
91
0
377
983
(161)
(35)
1
(76)
0
712
1,106
(32)
2
0
14
0
1,090
Recommendation 2 Compared to IRP-Based Reference Case
Region
Load Benefit
Generator Benefit
Total Benefits
Rocky Mountain
Northwest
Canada
Mexico
California
Desert SW
Total
750
517
207
20
646
286
2,427
176
(550)
(204)
(23)
(321)
(395)
(1,318)
926
(33)
3
(4)
326
(109)
1,109
Recommendation 2 Compared to All-Gas Reference Case
Region
Load Benefit
Generator Benefit
Total Benefits
Rocky Mountain
Northwest
Canada
Mexico
California
Desert SW
Total
878
581
224
18
683
277
2,660
864
(633)
(219)
(22)
(287)
(386)
(682)
1,742
(52)
4
(3)
396
(109)
1,978
Chapter 3 Rocky Mtn. Area Transmission Study
3-16
The distribution of gains and losses shows annual benefits to the Rocky Mountain region ranging
from $290 million to over $1.106 billion, compared to the two reference cases. These benefits come
with little net impact on western regions outside the Rocky Mountain States. This makes a
compelling case for entities in the Rocky Mountain States to work together to build this
transmission and capture the economic gain. Chapters 4 and 5 address some of the challenging
issues that will need to be addressed in Phase II to accomplish this.
The gains and losses comparisons for Recommendation 2 demonstrate that developing and
exporting coal and wind generation from the Rocky Mountain region will benefit consumers in the
Western Interconnection. Using the assumptions in this screening analysis, total west-wide
consumer benefits range from $2.427 to $2.66 billion annually. In many parts of the West, load (i.e.,
consumer) benefits are roughly offset by generator losses. Such generator loses may or may not be
passed on to consumers. The notable exception here is California. Even net of generation losses,
California stands to gain between $326 and $396 million per year if Recommendation 2 is built.
Benefits to the Rocky Mountain region also increase with Recommendation 2 by over $600 million
per year, compared to Recommendation 1, and range from $926 million to $1.742 billion annually.
The Rocky Mountain states should invite California to participate in future work pursuant to
Recommendation 2. This and other Phase II efforts are discussed further in Chapters 4 and 5.
H.
Conclusions
The economic screening study in RMATS Phase I finds that the transmission recommendations
provide economic benefits over a reasonable range of future natural gas prices and hydro conditions.
Significant benefits to the Rocky Mountain region appear attainable if the transmission projects in
Recommendation 1 are constructed, enabling the region to increase its reliance on low fuel cost coal
and wind resources rather than on new gas-fired generation. Recommendation 2 produces
significant consumer benefits throughout the West, with strong beneficiaries in the Rocky Mountain
region and in California.
Future natural gas prices are the largest driver of the production costs. If a relatively low natural gas
price future persists, Recommendation 1 does not appear to be economic. This conclusion ignores
the benefits of hedging against uncertain future natural gas prices, which these transmission
expansions would provide.
Several conclusions can be drawn from the economic analysis of the Recommendations 1 and 2:
• The Rocky Mountain region would benefit significantly if coal-fired and wind resource
development is given priority over gas-fired resource development to meet its load growth.
•
Substantial increases in natural gas demand – driven in large part to gas-fired electric
generators – has led to natural gas price escalation and volatility, making fuel diversification
an increasingly important priority for LSEs throughout the West.
•
Given its abundant reserves of low-cost fuels, the Rocky Mountain region is well positioned
to contribute to the West’s fuel diversification goals – if the West supports the necessary
transmission expansion.
•
Diversification into new Rocky Mountain coal and wind generation reduces production costs
throughout the West when compared to natural gas-fired generation. The Rocky Mountain
states and West Coast markets (California markets in particular) stand to benefit.
Chapter 3 Rocky Mtn. Area Transmission Study
3-17
EXHIBIT 5
NATIONAL ELECTRIC
TRANSMISSION CONGESTION
STUDY
AUGUST 2006
U.S. Department of Energy
NATIONAL ELECTRIC
TRANSMISSION CONGESTION
STUDY
AUGUST 2006
U.S. Department of Energy
Contents
Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii
Acronyms Used in This Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
xi
1. Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.1. Organization of This Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.2. Definitions of Key Terms and Concepts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.3. Consultation with States and Regional Entities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
2
3
6
2. Study Approach and Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.1. Review of Historical Transmission Studies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.2. Simulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.3. Scenario Analyses and Economic Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.4. Estimating and Evaluating Congestion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.5. The Eastern Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.6. The Western Interconnection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9
9
9
10
13
14
17
3. Congestion and Constraints in the Eastern Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.1. Historical Transmission Constraints and Congestion Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.2. Results from Simulations of the Eastern Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
4. Congestion and Constraints in the Western Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4.1. Historical Transmission Constraints in the Western Interconnection . . . . . . . . . . . . . . . . . . . . . . 31
4.2. Congestion Findings From Modeling for the Western Interconnection . . . . . . . . . . . . . . . . . . . . 34
5. Critical Congestion Areas, Congestion Areas of Concern, and Conditional Congestion Areas . . .
5.1. Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.2. Congestion Areas in the Eastern Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.3. Congestion Areas in the Western Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.4. Enabling New Resource Development: Conditional Constraint Areas. . . . . . . . . . . . . . . . . . . . .
5.5. Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
39
39
41
44
49
57
6. Request for Comments on Designation of National Corridors and on This Study . . . . . . . . . . . . . . 59
6.1. Request for Comments Concerning Designation of National Corridors. . . . . . . . . . . . . . . . . . . . 59
6.2. General Request for Comments on the Congestion Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62
7. Next Steps Regarding Congestion Areas and Considerations for Future Congestion Studies. . . . . 63
7.1. Next Steps Regarding Congestion Areas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
7.2. Considerations for Future Congestion Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
iii
Contents (continued)
Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
Appendixes
A. Sections 368 and 1221(a) and (b) of the Energy Policy Act of 2005. . . . . . . . . . . . . . . . . . . . . . . . . . .
B. Parties Responding to the Department of Energy’s February 2, 2006 Notice of Inquiry on
“Considerations for Transmission Congestion Study and Designation of National Interest
Electric Transmission Corridors” . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C. Agenda for DOE’s March 29, 2006 Technical Conference on National Interest
Electric Transmission Corridors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
D. On-Site Participants in DOE’s March 29, 2006 Technical Conference on National Interest
Electric Transmission Corridors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E. On-Line Participants in DOE’s March 29, 2006 Technical Conference on National Interest
Electric Transmission Corridors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F. Organizations Providing Formal Comments to DOE’s March 29, 2006 Technical Conference on
National Interest Electric Transmission Corridors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
G. Outreach Meetings Held Regarding the Congestion Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
H. General Documents or Data Reviewed for the Congestion Study . . . . . . . . . . . . . . . . . . . . . . . . . . . .
I. Documents or Data Reviewed for the Eastern Interconnection Analysis . . . . . . . . . . . . . . . . . . . . . . .
J. Documents or Data Reviewed for the Western Interconnection Analysis . . . . . . . . . . . . . . . . . . . . . .
K. List of WECC Paths. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
73
77
79
83
85
89
91
95
97
101
105
List of Tables
2-1. Crude Oil and Natural Gas Price Forecasts: Base Case, High Case, and Low Case . . . . . . . . . . . 10
2-2. Generation Assumptions for Western Interconnection Reference 2015 Cases . . . . . . . . . . . . . . . 12
List of Figures
ES-1. Map of North American Electric Reliability Council (NERC) Interconnections. . . . . . . . . . . . . .
ES-2. Critical Congestion Area and Congestion Area of Concern in the Eastern Interconnection . . . . .
ES-3. One Critical Congestion Area and Three Congestion Areas of Concern
in the Western Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ES-4. Conditional Constraint Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1-1. Map of North American Electric Reliability Council (NERC) Interconnections. . . . . . . . . . . . . .
2-1. Crude Oil Prices: History and Basis Forecast. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2-2. Natural Gas Spot Prices at Henry Hub: History and Basis Forecast . . . . . . . . . . . . . . . . . . . . . . .
2-3. Nodes in Congestion Study Simulation of the Eastern Interconnection. . . . . . . . . . . . . . . . . . . . .
3-1. Constraints in the New England Region (ISO-New England) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3-2. Constraints in the New York Region (New York ISO) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3-3. Constraints in the PJM Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3-4. Constraints in the Midwest ISO Region (MISO) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3-5. Constraints in the Southwest Power Pool Region (SPP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3-6. Constraints in the SERC Reliability Corporation Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3-7. Most Congested Paths in the Eastern Interconnection, 2008 Simulation . . . . . . . . . . . . . . . . . . . .
3-8. Time That Constraints Are Binding Relative to Level of Constrained Transmission Capacity. . .
3-9. Congestion Rent Versus Constrained Transmission Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3-10. Congestion Rent Versus Constrained Transmission Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . .
iv
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
vii
viii
ix
ix
2
10
10
18
22
22
23
23
24
24
27
28
28
28
List of Figures (continued)
4-1. Congestion on Western Transmission Paths. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4-2. Actual Transmission Congestion, 1999-2005. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4-3. Most Heavily Loaded Transmission Paths in 2004-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4-4. Projected Congestion on Western Transmission Paths, 2008. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4-5. Projected Congestion on Western Transmission Paths, 2015. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4-6. Comparison of Historical and Modeled Congestion on Western Paths . . . . . . . . . . . . . . . . . . . . .
4-7. Existing and Projected Major Transmission Constraints in the Western Interconnection . . . . . . .
5-1. Critical Congestion Area and Congestion Area of Concern in the Eastern Interconnection . . . . .
5-2. One Critical Congestion Area and Three Congestion Areas of Concern
in the Western Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5-3. Southern California: Major Transmission into SP26 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5-4. Congested Paths and Seasonal Power Flows in the Pacific Northwest . . . . . . . . . . . . . . . . . . . . .
5-5. Conditional Constraint Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5-6. Potential Corridors on Federal Lands in the West . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5-7. CDEAC 2015 High Coal Generation and Associated New Transmission Lines . . . . . . . . . . . . . .
5-8. CDEAC 2015 High Renewables Generation and Associated New Transmission Lines . . . . . . . .
5-9. Potential Wind Development and Associated Transmission Requirements
in Northern Great Plains Area. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5-10. Potential Wind Development and Associated Transmission Requirements
in Central Great Plains Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5-11. Locations of Proposed New Nuclear Generation Capacity in the Southeastern United States . . .
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
32
33
34
34
36
35
37
40
45
46
47
50
52
53
54
55
56
58
v
4. Congestion and Constraints in the
Western Interconnection
Chapter 4 has the same structure as Chapter 3—first
it reviews the historical transmission constraints in
the Western Interconnection, and then it presents
the results of congestion simulation modeling. The
logic and process of comparing the historical and
modeled congestion results in the West was essentially parallel to that described in Chapter 3 for the
Eastern Interconnection, so that process is not
re-described here.
4.1. Historical Transmission
Constraints in the Western
Interconnection
The transmission constraints described below were
identified by reviewing recent transmission studies,
expansion plans and reliability assessments conducted by subregional groups of western utilities,
the Western Electricity Coordinating Council
(WECC), the Seams Steering Group – Western Interconnection (SSG-WI), and the California Independent System Operator (CAISO). The studies
covered in this review are listed in Appendix J.
Figure 4-1 shows some of the Western Interconnection’s principal catalogued transmission paths and
indicates those paths that were identified as congested in the historical studies.25 A transmission
constraint (or constraints) inhibiting flows on a
transmission path is represented by a red bar across
the path. The bar also crosses or touches all lines
comprising the path.
The western analysis used significantly larger
nodes (covering wider geographical spans with
much larger generation and load weightings) than
those used in the eastern modeling. The western
path catalog includes 67 WECC paths, plus other
monitored lines, as well as specific unscheduled
flow paths, operating transfer capability group
paths, and nomograms26 that reflect the effect of
other lines (including smaller lines) upon the modeled paths. Some of these paths are internal to
nodes, and so were not identified by the modeling
described here, although they are well-known and
studied in sub-regional analyses.
In addition to reviewing existing studies by others,
the western analysis team also examined data on actual transmission usage for the six-year period between 1999 and 2005. Below, Figure 4-2 shows the
western transmission paths that were most heavily
used. The usage metric shown is U75, the metric
that reflects how many hours in a year the path was
loaded at or above 75% of Operating Transfer Capability (OTC), the coordinated maximum flow
limit set on actual path transfers reflecting system
operating conditions at the time.27 Consistent with
other congestion results, this shows that the most
heavily loaded lines include the Bridger West
line, the Southwest of Four Corners-to-Cholla-toPinnacle Peak lines (built to deliver power from
baseload plants to loads), Western Colorado to
Utah, the lines from Wyoming to Colorado, and the
southern New Mexico path to El Paso.
Figure 4-3 shows how heavily various paths within
the West have been used over a recent 18-month period. Based on the U90 metric (which is the percentage of time a path is loaded at or above 90% of its
limit), this figure shows that only five lines were at
U90 or above for more than 10% of the hours in this
time period. Of the most heavily loaded lines, note
that the Bridger West line is dedicated to delivering
electricity from the Bridger coal-fired power plants
to loads in Utah and Oregon; this is one-way flow
25
Appendix K lists WECC’s 67 paths.
A “nomogram” is a graphic representation that depicts operating relationships between generation, load, voltage, or system stability in a
defined network. (See Glossary.)
27
WECC, Operating Transfer Capability Policy Committee Handbook, May 2006 (http://www.wecc.biz/documents/library/OTC/OTCPC_
HANDBOOK_05-19-06.pdf).
26
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
31
Figure 4-1. Congestion on Western Transmission Paths
Based on historical and existing modeling studies. Not all of WECC's 67 catalogued paths are shown.
32
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
Figure 4-2. Actual Transmission Congestion, 1999-2005
Based on most heavily loaded season for each path during the 6-year period.
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
33
on a line designed specifically for delivery of the
plants’ output to loads, so high loading for this line
demonstrates desirable asset utilization, not undesirably high congestion. Many of the most heavily
loaded lines in this period were other major tie-lines
similarly designed to facilitate high-volume bulk
power trades (Northwest to Canada northbound, Alberta west to British Columbia, the Pacific Direct
Current Intertie, the California-Oregon AC Intertie,
and the westbound line from Four Corners.
4.2. Congestion Findings From
Modeling for the Western
Interconnection
Figure 4-4 shows how projected relative congestion
patterns vary as a function of fuel prices. This graph
orders the most heavily used transmission paths (as
measured by U90, the number of hours when usage
equals or exceeds 90% of the line’s limit), at the
base case price for gas ($7/mmBtu). For each path,
the graph also shows projected U90 hours for lowand high-case fuel prices as well. The shifts in usage
between paths as fuel prices change reflects how
electricity flows change with fuel prices—when gas
prices are low, long-distance coal-by-wire imports
are somewhat less competitive, but when gas prices
rise, load-serving entities buy more coal, nuclear
and hydropower (to the degree that they are available) and reduce purchases from gas-fired power
plants. The shifts in relative congestion associated
with fuel price changes would be even more pronounced in a low-hydro scenario.
In its modeling, the western analysis sorted the congested paths by a number of methods to identify
those that were most congested. Using an averaging
method that combined both usage and economic
impact, they found the following paths were the
Figure 4-3. Most Heavily Loaded Transmission
Paths in 2004-2005
Based on values for U90.
Figure 4-4. Projected Congestion on Western Transmission Paths, 2008
U90 values at alternative natural gas prices.
34
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
most likely to be the most heavily congested in
2008:
• Arizona to Southern Nevada and Southern
California
• North and Eastern Arizona
• In the Rocky Mountains, the Bridger West line
from Wyoming to Utah
• Montana to Washington and Oregon
• Colorado to Utah
• Colorado to New Mexico
• Utah to Northern and Central Nevada
• The Pacific Northwest south to California
• Pacific Northwest flows northward to Canada
• In Southern California, from the Imperial Irrigation District to Southern California Edison.
deliver that production to load; without that
transmission, the new generation would be trapped
behind the constraints imposed by today’s transmission grid, and very likely the new generation itself
would not be built.28 Beyond these specific transmission additions, however, the 2015 case deliberately does not add significant new transmission, so
as to expose remaining transmission problems and
identify where congestion will occur. As a result,
the 2015 case finds that during many time periods,
the full output of low-cost generators will not be deliverable to loads without further transmission expansion beyond that assumed in the scenario. It also
shows transmission congestion as continuing in
many of the same areas where it exists today.
These findings match well with the results from
other recent studies (compare to Figure 4-1).
This case illustrates the importance of planning new
generation and transmission jointly when seeking to
develop new generation capacity distant from
loads; without such joint planning and coordination
between generation and transmission developers,
needed new generation is not likely to be built when
needed or in the most suitable locations.
Figure 4-5 (next page) shows congestion on western
transmission paths for the 2015 case. The resource
assumptions in this case reflect utilities’ integrated
resource plans and state renewable portfolio standards, as well as certain planned transmission lines
that would support those developments. Thus the
resource case for 2015 includes both new generation and the transmission that would be required to
Figure 4-6 compares historical congestion patterns
on western paths against modeled congestion for
2008 and 2015, using U75 (the percentage of time
Figure 4-6. Comparison of Historical and Modeled Congestion on Western Paths
28
For details on the new transmission capacity assumed in the 2015 case, see WCATF’s report, posted on the WECC website, http://www.
wecc.biz/index.php?module=pagesetter&func=viewpub&tid=5&pid=42.
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
35
Figure 4-5. Projected Congestion on Western Transmission Paths, 2015
Based on most heavily loaded season for each path during the 6-year period.
36
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
Figure 4-7. Existing and Projected Major Transmission Constraints in the Western Interconnection
Based on existing studies, usage data, and projections for 2008 and 2015.
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
37
when path loading is at or above 75% of the path’s
reliability limit). For the paths that exist today
(shown in Figure 4-6 with both blue and red bars, as
distinguished from the lines that were created to
connect new generation in 2015, with a blue bar
only), there is a high correlation between current
and projected transmission congestion. It is important to note, however, that more paths are heavily
loaded in the 2015 case because the case assumes
higher loads and higher generation outputs but did
not increase transmission capacity correspondingly
38
across the interconnection. Thus, path usage levels
increase broadly across the grid, not just on the new
facilities built into the 2015 case specifically to
serve associated new generating capacity.
Figure 4-7 (previous page) displays the principal results of the western analysis in a single graphic. It
shows the principal existing and projected constraints in the Western Interconnection, based on
existing studies, usage data, and projections for
2008 and 2015.
U.S. Department of Energy / National Electric Transmission Congestion Study / 2006
EXHIBIT 6
Western Interconnection
2006 Congestion Assessment
Study
Prepared by the
Western Congestion Analysis Task Force
May 08, 2006
1
2008 - Modeled Path Usage
U75, U90 and U(Limit) - - $5, $7 and $9 HH Gas Price - Med Hydro, Average Losses
Ordered by $7 U90
$5 Gas
Page 1 of 2
Path Name
Nav - Crystl
Bonz - Mona
ALB BC
Cry - McC
Pea - Mead
HA RB PS
TOT 2C
PAC PG&E
BR West
IID - SCE
MT NW
INT GOND
SW 4C
COR SK KY
EOR
Ship San J
PDCI
INYO CONT
Malin - RM
IPP DC LINE
COI
LUGO - VIC
ALTURAS
TOT 2A
W BROAD
El Dor Lugo
BONZ W
CH PPK
Hasy N Gila
SDG&E to CFE
PVINTR GOND
Z2-WOR
PATH C
TOT 1A
MARKETPLACE - ADELANTO
U(Limit)
Congestion
Hours (Hrs)
7,428
7,198
7,650
7,180
7,006
7,460
6,653
3,633
2,620
3,761
4,821
1,194
1,383
1,395
2,945
3,585
2,645
2,164
841
92
509
1,190
702
609
707
80
U90 Hours
(Hrs)
8,231
7,880
7,769
7,494
7,109
7,581
7,522
6,660
6,240
4,666
5,787
5,375
4,249
5,244
5,868
4,571
4,090
3,803
3,806
3,600
3,335
3,468
2,848
1,722
3,158
2,716
2,252
1,585
2,975
1,097
1,063
1,125
907
873
839
A dash in the table = 0 hours
$7 gas
U(Limit)
U75 Hours Congestion
(Hrs)
Hours (Hrs)
8,760
6,997
8,513
7,045
7,938
7,493
7,916
7,366
7,338
7,072
7,728
6,912
7,678
6,704
6,605
7,884
3,763
6,905
3,725
7,718
3,624
6,255
4,348
7,541
1,860
7,030
1,234
8,192
949
6,804
3,018
4,612
3,592
4,717
5,258
2,389
5,486
2,365
4,945
6,104
3,822
3,330
1,925
7,710
7
6,048
479
7,982
6,917
6,547
588
1,895
794
5,157
5,091
1,515
652
4,234
709
4,154
82
U90 Hours
(Hrs)
8,091
7,793
7,633
7,601
7,152
7,046
6,970
6,618
6,341
5,734
5,678
5,015
4,923
4,610
4,593
4,572
4,097
3,705
3,550
3,539
3,093
3,006
2,984
2,851
2,807
2,476
2,178
1,893
1,862
1,091
974
968
959
904
808
$9 Gas
U(Limit)
U75 Hours Congestion
(Hrs)
Hours (Hrs)
8,680
6,461
8,504
7,018
7,801
7,277
7,882
7,069
7,411
6936
7,216
6,546
7,159
6,684
6,418
7,905
3,967
7,390
4,861
7,688
4,029
6,073
4,315
7,555
2,308
7,009
1,130
8,058
356
6,652
2945
4,696
3,608
4,616
5,072
2203
5,285
2,519
4,773
5,509
4,009
4,144
2,530
7,486
86
5,794
317
7,904
6,830
5,195
177
1,641
1,005
4,778
4,725
1,587
639
4,296
700
3,964
44
U90 Hours U75 Hours
(Hrs)
(Hrs)
7,815
8,382
7,765
8,493
7,414
7,613
7,310
7,577
7054
7388
6,673
6,873
6,616
6,821
6,433
6,498
6,397
7,921
6,585
7,735
6,002
7,984
5,070
6,058
5,046
7,473
4,218
6,979
2,835
7,639
4510
6553
4,172
4,814
3,361
4,361
3275
4836
3,678
5,316
2,859
4,513
2,526
4,935
2,777
3,879
3,375
4,631
3,101
7,847
2,051
5,259
2,183
7,898
2,037
6,684
945
3838
1,270
1,842
815
4,848
587
4,093
972
1,566
877
4,251
664
3,516
17
$5 Gas
page 2 of 2
Path Name
IDAHO - SIERRA
FOUR CORNERS 345_500
BILLINGS - YELLOWTAIL
NORTH OF SAN ONOFRE
MIDPOINT - SUMMER LAKE
Moenkopi - El Dorado (EOR)
TOT 4B
WEST OF CROSSOVER
N. Gila - Imperial Valley WOR)
NORTHWEST - CANADA
SOUTHERN NEW MEXICO (NM1)
BORAH WEST
PG&E - SPP
PV to Devers (EOR)
INTERMOUNTAIN - MONA 345 KV
TOT 4A
BROWNLEE EAST
Mohave - Lugo (WOR)
TOT 2B2
IDAHO - NORTHWEST
TOT 3
WEST OF COLSTRIP
SILVER PEAK - CONTROL 55 KV
PERKINS - MEAD - MARKETPLACE 500
NORTHERN NEW MEXICO (NM2)
TOT 7
ALBERTA - SASKATCHEWAN
CENTENNIAL
EAGLE MTN 230_161 KV - BLYTHE 16
ELDORADO - MCCULLOUGH 500 KV
ELDORADO - MEAD 230 KV LINES
IDAHO - MONTANA
NORTH OF JOHN DAY
SOUTH OF SAN ONOFRE
SYLMAR - SCE
TOT 2B1
TOT 5
WEST OF CASCADES - NORTH
WEST OF CASCADES - SOUTH
WEST OF HATWAI
U(Limit)
Congestion
Hours (Hrs)
338
624
27
38
87
19
42
6
1
3
-
U90 Hours
(Hrs)
908
626
386
469
491
675
385
313
564
320
256
185
303
194
77
62
73
15
6
26
-
$7 gas
U75 Hours
(Hrs)
2,046
2,710
1,558
2,255
1,863
7,855
1,517
7,498
4,110
689
1,670
3,655
4,365
2,419
426
258
467
4,106
359
520
318
6,600
4,081
1,495
71
9
-
U(Limit)
Congestion
Hours (Hrs)
286
624
33
58
169
35
21
5
-
U90 Hours
(Hrs)
690
624
623
613
587
459
459
447
415
399
364
230
215
98
89
66
64
19
7
6
3
-
$9 Gas
U(Limit)
U75 Hours Congestion
(Hrs)
Hours (Hrs)
1,679
342
3,175
624
1,868
2,973
40
2,181
7,674
1,817
40
7,483
2,915
775
221
2,184
44
3,813
4,160
26
2,034
510
258
8
416
3,833
752
596
219
6,600
4,249
1,108
85
6
-
U90 Hours
(Hrs)
802
624
468
499
573
216
429
289
165
461
608
246
187
31
111
97
63
4
5
7
-
U75 Hours
(Hrs)
1,804
3,224
1,633
3,089
2,128
7,248
1,530
7,477
1,872
906
3,046
3,760
4,294
1,567
518
285
408
3,187
1,030
586
200
6,600
4,326
537
99
2
-
18
2008 - Modeled Path Usage Metric Ranking
U75, U90 and U(Limit) - - $5, $7 and $9 HH Gas Price - Med. Hydro, Average Losses
Ordered by $7 U90
Page 1 of 2
Path Name
Navajo - Crystal (EOR)
Bonanza - Mona (Bonanza West)
ALBERTA - BRITISH COLUMBIA
Crystal - McCullough (EOR)
Peacock - Mead (EOR)
HA PS - Red Butte (TOT 2C)
TOT 2C
PACIFICORP_PG&E 115 KV INTERCON.
BRIDGER WEST
IID - SCE
MONTANA - NORTHWEST
INTERMOUNTAIN - GONDER 230 KV
SOUTHWEST OF FOUR CORNERS
CORONADO - SILVER KING - KYRENE
EOR
Shiprock - San Juan
PACIFIC DC INTERTIE (PDCI)
INYO - CONTROL 115 KV TIE
Malin - RM 1 & 2 (COI)
IPP DC LINE
COI
LUGO - VICTORVILLE 500 KV LINE
ALTURAS PROJECT
TOT 2A
WEST OF BROADVIEW
El Dor to Lugo (WOR)
BONANZA WEST
CHOLLA - PINNACLE PEAK
Hassy - N. Gila (EOR)
SDG&E to CFE
PAVANT INTRMTN - GONDER 230 KV
Z2-WOR
PATH C
TOT 1A
MARKETPLACE - ADELANTO
U(Limit)
Congestion
Hours
Ranking
3
4
1
5
6
2
7
10
15
9
8
19
18
17
12
11
13
16
21
28
26
20
23
25
22
30
A dash in the table indicates the path was unranked since the Hours = 0
$5 Gas
$7 gas
U90 Hours
Ranking
1
2
3
6
7
4
5
8
9
14
11
12
17
13
10
15
18
20
19
21
23
22
26
29
24
27
28
30
25
32
33
31
35
36
37
U75 Hours
Ranking
1
2
5
6
15
9
12
20
7
18
10
24
13
16
3
19
33
32
28
27
31
25
40
42
11
26
4
17
23
47
29
30
52
35
36
U(Limit)
Congestion
Hours
Ranking
5
4
1
2
3
6
7
9
10
11
8
18
19
20
13
12
14
15
17
34
26
25
21
23
22
29
U90 Hours
Ranking
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
U(Limit)
Congestion
Hours
U75 Hours
Ranking
Ranking
1
6
2
3
7
1
6
2
13
4
15
5
16
19
7
4
11
14
8
8
10
23
9
10
16
17
19
3
24
20
13
32
12
33
28
17
26
15
30
25
38
37
14
11
29
24
26
5
18
27
28
51
20
29
31
52
22
34
21
39
30
$9 Gas
U90 Hours U75 Hours
Ranking
Ranking
1
2
2
1
3
9
4
10
5
13
6
16
7
17
9
21
10
4
8
7
11
3
12
22
13
12
15
15
24
8
14
20
16
29
19
32
20
28
17
24
23
31
26
26
25
37
18
30
22
6
28
25
27
5
29
18
32
38
30
47
34
27
39
36
31
51
33
35
36
40
19
$5 Gas
Page 2 of 2
Path Name
IDAHO - SIERRA
FOUR CORNERS 345_500
BILLINGS - YELLOWTAIL
NORTH OF SAN ONOFRE
MIDPOINT - SUMMER LAKE
TOT 4B
Moenkopi - El Dorado (EOR)
WEST OF CROSSOVER
N. Gila - Imperial Valley WOR)
NORTHWEST - CANADA
SOUTHERN NEW MEXICO (NM1)
BORAH WEST
PG&E - SPP
PV to Devers (EOR)
INTERMOUNTAIN - MONA 345 KV
TOT 4A
BROWNLEE EAST
Mohave - Lugo (WOR)
TOT 2B2
IDAHO - NORTHWEST
TOT 3
WEST OF COLSTRIP
SILVER PEAK - CONTROL 55 KV
PERKINS - MEAD - MARKETPLACE 500
NORTHERN NEW MEXICO (NM2)
TOT 7
ALBERTA - SASKATCHEWAN
CENTENNIAL
EAGLE MTN 230_161 KV - BLYTHE 16
ELDORADO - MCCULLOUGH 500 KV
ELDORADO - MEAD 230 KV LINES
IDAHO - MONTANA
NORTH OF JOHN DAY
SOUTH OF SAN ONOFRE
SYLMAR - SCE
TOT 2B1
TOT 5
WEST OF CASCADES - NORTH
WEST OF CASCADES - SOUTH
WEST OF HATWAI
U(Limit)
Congestion
Hours
Ranking
27
24
33
32
29
34
31
35
37
36
-
U90 Hours
Ranking
34
39
43
42
41
44
38
46
40
45
48
50
47
49
51
53
52
55
56
54
-
$7 gas
U75 Hours
Ranking
46
43
50
45
48
51
8
14
37
54
49
41
34
44
57
60
56
38
58
55
59
22
39
53
61
62
-
U(Limit)
Congestion
Hours
Ranking
27
24
32
30
28
31
33
35
-
U90 Hours
Ranking
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
58
58
58
58
-
$9 Gas
U75 Hours
Ranking
50
42
48
43
46
49
9
12
44
54
45
41
36
47
58
60
59
40
56
57
61
21
35
53
62
63
-
U(Limit)
Congestion
Hours
Ranking
25
23
32
33
27
31
34
35
-
U90 Hours
Ranking
35
37
42
41
40
44
47
45
49
43
38
46
48
53
50
51
52
56
55
54
-
U75 Hours
Ranking
48
41
49
43
45
52
14
11
46
54
44
39
34
50
57
59
58
42
53
55
60
19
33
56
61
62
-
20
-
Path Name
TOT 1A
PATH C
Z2-WOR
PVINTR GOND
SDG&E to CFE
Hasy N Gila
CH PPK
BONZ W
El Dor Lugo
W BROAD
TOT 2A
ALTURAS
LUGO - VIC
COI
IPP DC LINE
Malin - RM
INYO CONT
PDCI
Ship San J
EOR
COR SK KY
SW 4C
INT GOND
MT NW
IID - SCE
BR West
PAC PG&E
TOT 2C
HA RB PS
Pea - Mead
Cry - McC
ALB BC
Bonz - Mona
Nav - Crystl
Hours
2008 Model Study
U90, U75 and U(Limit) - $7 HH Gas, Medium Hydro, Ave. Losses
Ordered by U90, $7 Gas
10,000
9,000
8,000
7,000
6,000
5,000
U90
U75
4,000
U(Lim)
3,000
2,000
1,000
21
-
Path Name
TOT 1A
PATH C
Z2-WOR
PVINTR GOND
SDG&E to CFE
Hasy N Gila
CH PPK
BONZ W
El Dor Lugo
W BROAD
TOT 2A
ALTURAS
LUGO - VIC
COI
IPP DC LINE
Malin - RM
INYO CONT
PDCI
Ship San J
EOR
COR SK KY
SW 4C
INT GOND
MT NW
IID - SCE
BR West
PAC PG&E
TOT 2C
HA RB PS
Pea - Mead
Cry - McC
ALB BC
Bonz - Mona
Nav - Crystl
Hours
2008 Modeling Study
U90 at $5, $7 and $9 HH Gas, Medium Hydro, Average Losses
Ordered by U90 $7 Gas
10,000
9,000
8,000
7,000
6,000
5,000
$7 Gas
$5 Gas
4,000
$9 Gas
3,000
2,000
1,000
22
-
Path Name
TOT 1A
PATH C
Z2-WOR
PVINTR GOND
SDG&E to CFE
Hasy N Gila
CH PPK
BONZ W
El Dor Lugo
W BROAD
TOT 2A
ALTURAS
LUGO - VIC
COI
IPP DC LINE
Malin - RM
INYO CONT
PDCI
Ship San J
EOR
COR SK KY
SW 4C
INT GOND
MT NW
IID - SCE
BR West
PAC PG&E
TOT 2C
HA RB PS
Pea - Mead
Cry - McC
ALB BC
Bonz - Mona
Nav - Crystl
Hours
10,000
2008 Modeling Study
U(Limit) - $5, $7 and $9 Gas, Medium Hydro, Ave. Losses
Ordered by U90 $7 Gas
9,000
8,000
7,000
6,000
5,000
$7 Gas
$5 Gas
4,000
$9 Gas
3,000
2,000
1,000
23
-
Path Name
TOT 1A
PATH C
Z2-WOR
PVINTR GOND
SDG&E to CFE
Hasy N Gila
CH PPK
BONZ W
El Dor Lugo
W BROAD
TOT 2A
ALTURAS
LUGO - VIC
COI
IPP DC LINE
Malin - RM
INYO CONT
PDCI
Ship San J
EOR
COR SK KY
SW 4C
INT GOND
MT NW
IID - SCE
BR West
PAC PG&E
TOT 2C
HA RB PS
Pea - Mead
Cry - McC
ALB BC
Bonz - Mona
Nav - Crystl
Hours
2008 Modeling Study
U75 - $5, $7 and $9 Gas, Medium Hydro, Ave. Losses
Ordered by U90, $7 Gas
10,000
9,000
8,000
7,000
6,000
5,000
$7 Gas
$5 Gas
4,000
$9 Gas
3,000
2,000
1,000
24
TOT 2A
PG&E - SPP
SILPK - CON
TOT 1A
INYO CONT
PDCI
Z2-WOR
COI
PVINTR GOND
Malin - RM
Hasy N Gila
IPP DC LINE
LUGO - VIC
El Dor Lugo
INT GOND
W OF COLS
Ship San J
PAC PG&E
CH PPK
COR SK KY
TOT 2C
HA RB PS
IID - SCE
Pea - Mead
W OF CROSS
W BROAD
SW 4C
Moen - El D
MT NW
ALB BC
Cry - McC
BONZ W
BR West
EOR
Bonz - Mona
Nav - Crystl
Hours
2008 Model Study
U75 - $5, $7 and $9 Gas - - Medium Hydro, Ave Losses
Ordered by U75, $7 Gas
10,000
9,000
8,000
7,000
6,000
5,000
$7 Gas
$5 Gas
4,000
$9 Gas
3,000
2,000
1,000
Path Name
25
2008
Path Shadow Prices
Results
26
2008 - Modeled Path Shadow Prices
Congestion Rent, Average Shadow Price and Binding Hours Average Shadow Price
for $5, $7 and $9 HH gas - Med. Hydro, Ave Losses - - Ordered by $7 Gas Binding Average Shadow Price - - A dash in the table = 0 value
$5 Gas
Path Name
Shiprock - San Juan
Bonanze - Mona (Bonanza West)
4C Trans
BRIDGER WEST
Cor - Sking - Kyrene
TOT 1A
Navajo - Crystal (EOR)
SW of 4C
Malin - RM 1 & 2 (COI)
PATH C
TOT 4B
Mont - NW
W of Broad
AL - BC
TOT 2A
Inter- Gonder
IPP DC LINE
PDCI
TOT 4A
Lugo - Victorville (WOR)
NW - Canada
Peacock - Mead (EOR)
HA PS - Red Butte (TOT 2C)
S NM
Crystal - McCullough (EOR)
SDG&E to CFE
IDAHO - SIERRA
PAC- PG&E 115
MKT - Adelanto
El Dor to Lugo (WOR)
EOR
IID - SCE
Hassy - N. Gila (EOR)
N of San Ono
PG&E - SPP
ID - NW
TOT 3
ALBERTA - SASKATCHEWAN
ALTURAS PROJECT
BILLINGS - YELLOWTAIL
BONANZA WEST
Congestion
Rent (k$/yr)
76,189.97
107,145.85
9,064.17
96,626.08
13,949.27
5,530.90
140,908.70
22,402.87
35,022.26
3,324.91
155.17
53,230.99
1,095.70
34,070.17
2,065.56
4,083.24
14,878.02
29,356.02
11.18
12,364.42
419.66
8,397.42
3,332.36
26.99
24,786.21
1,109.89
252.04
760.87
110.59
1,325.02
15,432.41
1,297.60
2,232.26
23.46
2.52
3.73
2.03
-
Binding
Average
Average
Shadow
Shadow
Price ($/MW) Price ($/MW)
12.7
38.0
19.8
24.1
1.2
17.3
5.0
12.1
1.4
9.2
1.0
12.0
11.4
13.4
1.1
8.1
2.7
8.9
0.5
6.9
0.0
6.0
2.8
6.4
0.0
4.6
5.5
6.4
0.3
3.6
2.1
3.8
0.9
3.6
1.1
2.7
0.0
2.3
0.6
2.1
0.0
2.4
2.0
2.5
1.3
1.6
0.0
1.4
1.6
2.0
0.2
2.1
0.1
1.5
1.1
1.4
0.0
1.2
0.1
0.9
0.2
1.5
0.2
0.8
0.1
1.0
0.0
0.4
0.0
0.4
0.0
3.1
0.0
0.5
-
$7 Gas
Congestion
Rent (k$/yr)
129,963.36
131,555.28
10,898.85
134,152.81
21,445.63
7,019.06
116,844.42
43,389.05
31,846.99
4,518.17
323.17
63,815.86
123.56
35,227.22
7,848.89
4,676.19
18,623.10
30,951.55
10.13
12,160.90
722.96
7,255.19
4,002.12
72.86
20,737.79
482.24
192.87
701.47
126.78
1,325.43
6,095.96
1,809.29
637.24
29.54
0.84
-
Binding
Average
Average
Shadow
Shadow Price
Price ($/MW)
($/MW)
21.7
63.2
24.3
30.2
1.5
20.8
6.9
16.2
2.2
15.8
1.2
15.2
9.4
11.8
2.1
10.0
2.4
9.0
0.6
8.8
0.1
8.2
3.3
8.0
0.0
6.9
5.7
6.7
1.3
5.9
2.4
4.9
1.1
4.1
1.2
2.9
0.0
2.5
0.6
2.3
0.0
2.1
1.7
2.1
1.6
2.0
0.0
2.0
1.4
1.6
0.1
1.4
0.0
1.3
1.0
1.3
0.0
1.3
0.1
1.0
0.1
0.9
0.3
0.8
0.6
0.0
0.4
0.0
0.2
-
$9 Gas
Congestion
Rent (k$/yr)
175,350.41
159,709.73
11,105.78
156,967.43
31,425.74
8,444.83
89,182.88
70,111.43
29,295.25
5,074.11
233.55
89,353.26
2,030.99
36,591.23
17,524.90
5,369.55
21,670.00
33,589.62
28.32
10,465.25
1,239.27
5,782.45
4,554.29
122.17
15,974.52
2,411.61
215.12
664.51
56.71
672.14
1,123.50
2,812.40
141.51
56.24
1.03
-
Average
Binding
Shadow
Average
Price
Shadow Price
($/MW)
($/MW)
29.3
87.4
29.4
36.9
1.5
21.2
8.1
18.0
3.3
25.3
1.5
18.6
7.2
9.8
3.4
13.1
2.3
9.0
0.7
10.0
0.0
8.6
4.6
10.1
0.1
9.2
6.0
7.2
2.9
10.0
2.8
5.7
1.3
4.5
1.3
3.1
0.0
4.4
0.5
2.4
0.1
2.8
1.4
1.7
1.8
2.4
0.0
2.6
1.1
1.3
0.5
3.9
0.0
1.3
0.9
1.3
0.0
1.1
0.0
0.8
0.0
0.4
0.5
1.0
0.4
0.0
0.6
0.0
0.2
-
27
2008 - Modeled Shadow Price Metric Ranking
Congestion Rent, Average Shadow Price and Binding Hours Average Shadow Price
for $5, $7 and $9 HH gas - Med Hyrdo, Ave Losses - - Ordered by $7 Gas Binding Average Shadow Price
$5 Gas
Path Name
Shiprock - San Juan
Bonanza - Mona (Bonanza West)
4C Trans
BRIDGER WEST
Cor - SKing - Kyrene
TOT 1A
Navajo - Crystal (EOR)
SW of 4C
Malin - RM 1 & 2 (COI)
PATH C
TOT 4B
Mont - NW
W of Broad
AL - BC
TOT 2A
Inter- Gonder
IPP DC LINE
PDCI
TOT 4A
Lugo - Victorville (WOR)
NW - Canada
Peacock - Mead (EOR)
HA PS - Red Butte (TOT 2C)
S NM
Crystal - McCullough (EOR)
SDG&E to CFE
IDAHO - SIERRA
PAC- PG&E 115
MKT - Adelanto
El Dor to Lugo (WOR)
EOR
IID - SCE
Hassy - N. Gila (EOR)
N of San Ono
PG&E - SPP
ID - NW
TOT 3
ALBERTA - SASKATCHEWAN
ALTURAS PROJECT
BILLINGS - YELLOWTAIL
BONANZA WEST
BORAH WEST
Average
Congestion Rent Shadow Price
Ranking
Ranking
4
2
2
1
15
13
3
5
13
11
17
17
1
3
10
15
6
7
20
20
30
29
5
6
26
28
7
4
22
21
18
8
12
18
8
14
34
33
14
19
28
30
16
9
19
12
32
32
9
10
25
24
29
26
27
16
31
31
23
27
11
23
24
22
21
25
33
33
36
33
35
33
37
33
$7 Gas
$9 Gas
Binding
Binding
Binding
Average
Average
Average
Average
Average
Shadow Price Congestion
Shadow Price Shadow Price Congestion Rent Shadow Price Shadow Price
Ranking
Rent Ranking
Ranking
Ranking
Ranking
Ranking
Ranking
1
3
2
1
1
2
1
2
2
1
2
2
1
2
3
14
13
3
14
13
4
5
1
4
4
3
3
6
7
10
9
5
9
8
3
6
17
16
6
16
14
5
4
4
3
7
5
4
11
9
6
10
8
6
7
7
8
8
8
9
10
11
13
10
20
20
10
19
20
10
13
28
26
11
28
26
14
11
5
6
12
4
6
8
14
31
31
13
23
24
12
12
7
5
14
7
5
15
17
15
15
15
12
9
9
15
19
7
16
18
10
16
16
12
18
17
11
16
17
19
9
17
18
8
17
20
22
34
31
19
34
26
18
24
13
21
20
15
22
24
21
24
28
21
24
25
21
20
16
11
22
17
15
25
26
21
12
23
20
12
23
30
32
30
24
31
26
22
25
11
14
25
13
18
26
23
27
23
26
22
23
19
27
29
27
27
29
26
28
29
25
19
28
27
19
27
31
30
29
29
32
26
29
33
23
25
30
26
26
31
28
18
24
31
25
26
33
34
22
22
32
21
21
30
32
26
31
33
30
26
34
37
33
31
34
33
26
32
36
35
31
35
35
26
35
18
36
31
36
36
26
36
35
36
31
36
36
26
36
28
NW - Canada
Lugo Vict
IID - SCE
EOR
El Dor to Lugo
MKT - Adelanto
PAC- PG&E
ID Sierra
SDG&E to CFE
Cryst McC
S NM
HA RB PS
Peacock Mead
Path Name
TOT 4A
PDCI
IPP DC LINE
Inter- Gonder
TOT 2A
AL - BC
W of Broad
Mont - NW
TOT 4B
PATH C
Malin RM
SW of 4C
Nav Cryst
TOT 1A
Cor SK Ky
BRIDGER W
4C Trans
Bonz Mona
Ship San Juan
Shadow Price - $/MW
2008 Model Study
Binding Average Hours Shadow Price and Average Shadow Price
$7 gas, Medium Hydro, Average Losses
40.0
35.0
$63
30.0
25.0
20.0
B SP
Ave SP
15.0
10.0
5.0
29
Path Name
IID - SCE
EOR
El Dor to Lugo
MKT - Adelanto
PAC- PG&E
ID Sierra
SDG&E to CFE
Cryst McC
S NM
HA RB PS
Peacock Mead
NW - Canada
Lugo Vict
TOT 4A
PDCI
IPP DC LINE
Inter- Gonder
TOT 2A
AL - BC
W of Broad
Mont - NW
TOT 4B
PATH C
Malin RM
SW of 4C
Nav Cryst
TOT 1A
Cor SK Ky
30.0
BRIDGER W
4C Trans
Bonz Mona
Ship San Juan
Shadow Price - $ / MW
2008 Modeling Study
Binding Hours Shadow Price - $5, $7 and $9 Gas
Medium Hydro and Average Losses
40.0
$88
35.0
$63
25.0
20.0
$7 Gas
$5 Gas
15.0
$9 Gas
10.0
5.0
-
30
EXHIBIT 7
Western Governors’ Association
Clean and Diversified Energy Initiative
Transmission Task Force Members
Chair – Jim Wilcox, Xcel Energy
Grace Anderson, California Energy Commission
Frank Barbera, Imperial Irrigation District
Jim Caldwell, PPM
Steve Dayney, Xcel Energy
Mike DeWolf, PacifiCorp
Allan Edwards, Basin Electric
Steve Ellenbecker, Wyoming Governor’s Office
Robert Gough, Intertribal Council on Utility Policy
Roger Hamilton, Wind on the Wires (West)
Bill Hose, TransCanada
Robert Kondziolka, Salt River Project
Hal LaFlash, Pacific Gas & Electric
Marv Landauer, Bonneville Power Administration
Ron Lehr, American Wind Energy Association
Iain Kinnis and Stephen Burnage, National Grid
Craig O’Hare, New Mexico Department of Energy
Lee Otteni and Ray Brady, Bureau of Land Management
Bill Pascoe, Great Northern
Dean Perry, SSG-WI
Holly Propst, Western Business Roundtable
Chris Reese, Puget Sound Energy
Robert Smith, Peter Krzykos, and Yvonne Hunter, Arizona Public Service
Jerry Vaninetti, Trans-Elect
John Woody and Judi Greenwald, Pew Center for Global Climate Change
Support Staff:
Doug Larson, Western Interstate Energy Board
Thomas Carr, Western Interstate Energy Board
Bill Moye, Star Consulting Group, LLC
May 30, 2006
This document is intended as background information for the Clean and Diversified Energy Advisory Committee. It does
not represent the adopted policies and views of the Western Governors’ Association.
CDEAC Transmission
Task Force Report (05-30-06)
Table of Contents
Executive Summary
1
I. Transmission Opportunities to Support CDEAC Generation
A. Transmission in the Eastern Interconnection and ERCOT
B. Transmission in the Western Interconnection
C. Long-Term Outlook
1. Transmission Adequacy Beyond 2015
2. Non-Wires Alternatives
3. Technological Innovation for Transmission
5
6
7
10
10
10
11
II. Encouraging Efficient Use and Expansion of the Western Transmission
Infrastructure: Policy Recommendations
A. Background
B. Challenges and Policy Options
1. Efficient Use of the Existing Transmission System
Background
a. FERC’s Open Access Transmission Policies
b. Emerging Issues Under Order 888
i. Historical Flows
ii. Conditional Firm, Priority Non-firm and
Other Transmission Service
iii. Evaluation of ATC
iv. Rate Pancaking
v. Control Area Consolidation
vi. Economic Dispatch of Transmission
vii. Common Oasis
Recommendations 1-6
2. Transmission Expansion
a. Transmission Planning
Background
i. Western Transmission Planning Efforts
ii. FERC Generation Interconnection Policies
(1) Order 2003 and the Interconnection Queue
(2) Small Generator Interconnection
(3) Codes of Conduct
iii. Interaction of Transmission Planning and
ii
15
15
20
20
20
20
21
21
23
23
24
24
25
27
27
30
30
30
30
32
32
34
34
May 30, 2006
This document is intended as background information for the Clean and Diversified Energy Advisory Committee. It does
not represent the adopted policies and views of the Western Governors’ Association.
Generation Interconnection Rules
(1) Open Season
(2) EPACT Congestion Study
Recommendations 7-10
35
36
36
37
b. Cost Allocation and Cost Recovery
Background
i. FERC Policy
ii. State Cost Allocation Policies
iii. Transmission for Location-Constrained,
Modular Development Generation
iv. Infrastructure Authorities
v. Western Area Power Administration
vi. EPAct Incentives
Recommendations 11-17
39
39
39
40
c. Transmission Siting and Permitting
Background
Recommendations 18-19
49
49
51
Appendices
A. Results of Transmission Analysis in the Western Interconnection
B. Results of Transmission Analysis in the Eastern Interconnection
and ERCOT
iii
41
43
44
44
45
53
67
May 30, 2006
This document is intended as background information for the Clean and Diversified Energy Advisory Committee. It does
not represent the adopted policies and views of the Western Governors’ Association.
identify current beneficiaries of transmission investments. Over time, the level and
distribution of benefits from transmission becomes even more diffuse since incremental
transmission investments improve overall reliability to the system, and interactions of
additions of new generation and other transmission projects alter the flow of electricity
over the grid in complex and unanticipated ways.
Transmission for Location-Constrained, Modular Development Generation.
Policy rules governing transmission expansion has developed over time in parallel with
conventional generating fossil resources and hydro power. The prevailing transmission
expansion rules are problematic for a class of emerging generation technologies with the
following characteristics: 1) generation that is location-constrained given the nature of
the resource; and 2) development that occurs in a disaggregated and modular fashion by
multiple entities.
Location-constrained-type resources such as wind, geothermal and centralized solar
plants must be sited close to where the resource can be harnessed. Wind generators need
to be placed where the wind blows and geothermal generators must be located at specific
geological sites. The best sites for centralized solar power are located in the desert. In
contrast, natural gas generation can be located very close to loads. Coal plants have
geographic flexibility given the ability to transport coal by railroads.
The second factor concerns the disaggregated and modular development of generation
resources. Certain emerging resources like wind, geothermal and biomass are best suited
for development in geographic concentrated areas. Development for these resources
generally occurs not by a single centralized entity, but by many different small
development projects in a disaggregated fashion. Over time, development can expand in
a modular and sequential fashion with the addition of new projects in the region. The key
challenge for generation development in these areas is to build new transmission capacity
in a synchronized manner. Under current transmission policy, however, the burden of
building new transmission falls on the first projects making generation interconnection
requests. The initial project developers are not able to provide the financing and assume
the risk to build transmission for the region. This approach does not encourage or
facilitate a coordinated, planned, modular development of the resource. As a result,
current policy for new transmission does not address a fundamental chicken and egg
timing problem between potential generation projects and corresponding potential
transmission projects.
New approaches are needed to provide transmission for location-constrained, modular
development resource areas. Several recent initiatives in Texas, Minnesota and
California provide potential models to address this problem.
Texas and Minnesota recently enacted legislation to provide legal and regulatory
incentives to build transmission in support of and prior to building of renewable
41
May 30, 2006
This document is intended as background information for the Clean and Diversified Energy Advisory Committee. It does
not represent the adopted policies and views of the Western Governors’ Association.
generation. In Texas, SB 2075 authorized the public utility commission to require electric
utilities to construct or enlarge transmission facilities to meet Texas RPS goals. The
Texas public utility commission must designate renewable energy zones and develop a
plan to construct transmission to those zones. SB 20 requires the public utility
commission to issue a final order within 181 days of the filing of an application for
certificate of public convenience and necessity to build transmission to meet RPS goals.
Applications are automatically approved if the commission fails to act after 181 days.
Additionally, SB 20 provides cost recovery incentives. Transmission projects supporting
RPS goals shall be deemed used and useful, and prudent and includable in the rate base,
regardless of the utility’s actual use of the facilities.
In Minnesota, SF 136876 contains transmission provisions to support renewable energy
development and to meet the Minnesota RPS goal. SF 1368 requires utilities to identify
future transmission inadequacies in the transmission system, identify alternative means to
address such inadequacies and submit transmission reports to the public utility
commission. Utilities must determine necessary transmission upgrades to support
development of renewable energy to meet the RPS conditions. Transmission projects
determined to be necessary to support a utility’s plan to meet RPS requirements would be
deemed a priority electric transmission project and serve to satisfy a certificate of need.
SF 1368 grants public utility commission authority to approve transmission cost
adjustments for new transmission facilities deemed a priority transmission project. Such
transmission tariffs would allow utilities to recover costs on a timely basis, allow a return
on investment at a level most recently approved or another rate consistent with the public
interest, and for a current return on construction work in progress.
In California, Southern California Edison (SCE) proposed the “renewable trunk
line” concept for its Tehachapi/Antelope transmission project. This proposal envisioned
transmission expansion in advance of generator requests based on predictable growth of
many independent wind generation projects in a designated concentrated area. The
proposal avoids the pitfall of inefficient piecemeal studies required under current
interconnection rules. Specific elements of the SCE proposal are summarized below:
•
•
Rolled-in rate treatment for high-voltage (220kV or higher) trunk-line
transmission project costs necessary to integrate large concentrations of
renewable generation resources located a reasonable distance from the existing
grid. To be eligible for this treatment, large concentrations of renewable
resources should be located in a limited geographic area.
Permit rolled-in rate treatment and cost recovery for prudent costs for
transmission facilities described above regardless of whether the full increment of
forecast generation that would justify the upgrades commences commercial
operations.
75
Texas Legislature SB 20, Legislative Session 79(1), signed by Governor Rick Perry on August 2, 2005,
and effective on Sept. 1, 2005. Section 3 of SB 20 raised the Texas RPS goal to 5,880 MW of cumulative
installed renewable capacity by 2015, and a target of 10,000 MW by 2025 (http://www.capitol.state.tx.us/ ).
76
Minnesota State Legislature, SF 1368, Legislative Session 84, signed by Governor Tim Pawlently on
May 25, 2005 (http://www.leg.state.mn.us/leg/legis.asp).
42
May 30, 2006
This document is intended as background information for the Clean and Diversified Energy Advisory Committee. It does
not represent the adopted policies and views of the Western Governors’ Association.
•
Grant 100% cost recovery for prudent costs even if the transmission project is
cancelled or abandoned either because there is insufficient generation
development in the region or necessary regulatory approvals for project
construction are not granted. Under current policy, FERC limits recovery from
ratepayers to only 50% of the utility’s prudently-incurred investment in
abandoned or cancelled FERC-jurisdictional plant (facilities not completed and
placed into operation).77
On July 1, 2005, FERC issued a split decision that rejected the renewable trunk-line
features of the SCE proposal but accepted cost recovery features of 2 of the 3 proposed
transmission system upgrades. The majority rejected the trunk-line feature on grounds
that it was contrary to FERC policy on generation interconnection policies and that SCE
did not establish system-wide benefits to all consumers of the transmission system.
Infrastructure Authorities. The Wyoming Infrastructure Authority (WIA) was
created June 10th, 2004, by the state legislature, tasked with diversifying and growing the
state's economy through the development of Wyoming's electric transmission
infrastructure. The WIA is also responsible for planning, financing, building,
maintaining, and operating electric transmission and related facilities. Specific
responsibilities of the WIA include the following:
•
•
•
•
•
Issuing up to $1 billion in bonds to finance new transmission lines to support new
generation facilities in the state;
Owning and operating lines in instances where private investment is not offered;
Entering into partnerships with public or private entities to build and upgrade
transmission lines;
Investigating, planning, prioritizing, and establishing corridors for electric
transmission; and
Establishing and charging fees and rates for use of its facilities in consultation
with the public service commission and other related government entities.
The WIA is a new institution that will become involved in transmission planning
and expansion. This creates opportunities to collaborate on transmission investments, to
pursue partnerships with public and private entities, to begin to address siting and rightsof-way issues, and to explore creative financing and contracting.78 Following the
Wind Task Force, p. 65-66.
78
Rocky Mountain Area Transmission Study (RMATS), September 2004, p. 4-11. There is no statutory
limit on this bonding authority for projects the WIA might own. The WIA also has the capability, within
an outstanding bond cap of $1 billion, to issue bonds to build transmission facilities owned by other
entities. All WIA-issued bonds would be exempt from state taxation. Tax-exempt bond financing may
reduce the cost of transmission projects compared to private-sector equity and debt financing. The WIA is
constitutionally barred from issuing revenue bonds backed by the faith and credit of the State of Wyoming.
This means for any WIA bond issuance to be successfully received by the financial community, the bonds
will likely need to be secured by an expected revenue stream from the transmission investment. This
security could take the form of subscription-type contracts with entities expected to use the transmission, a
lease agreement with one or more utilities agreeing to take transmission capacity, or other means.
43
EXHIBIT 8
National Transmission Grid Study
The Honorable Spencer Abraham
Secretary of Energy
U.S. Department
of Energy
May 2002
2
Major Western Transmission Bottlenecks
Electricity trading patterns and transmission
over long distances. Several large power plants
congestion are somewhat different in the West
in the West were intentionally built in remote
than in the East for several reasons. First, the
locations; along with these plants, owners con-
transmission system in the West, unlike the one
structed high-voltage transmission lines to ship
in the East, was built primarily to carry power
power to densely populated load centers.14
Size of Transmission Paths
Fig. 2.2
Map of
Congested
Paths in the
Western
Interconnection
56
< 1 GW
>=1 and <3 GW
>=3 GW
51
53
52
48
Percentage of Hours Congested
55
50% and greater
40% to 49%
47
30% to 39%
d
20% to 29%
54
10% to 19%
49
58
57
50
67
61
65
62
66
59
69
68
64
63
60
14
For example, the Palo Verde nuclear plant was built in southern Arizona in part to serve load in southern California. Similarly, the Intermountain
Power Project, a 1,640-megawatt coal plant in Utah, was built to serve a number of municipalities in Utah and in California, including Los Angeles.
A 490-mile transmission line connects the plant to southern California.
15
National Transmission Grid Study
Transmission Constraints in Contiguous U.S.
Pacific DC Intertie
ISO-NE
CA/OR Interface
Southwest MI
NWPA
WY/ID Interface
East NY
MAPP
NYISO
PJM
ECAR
Central IA
CA/MX
MAIN
East KS/MO Interface
Central CA
East Boston
SW CT Interface
Southeast PA
Central MO
RMPA
West VA/PJM Interface
SPP
Southeast West VA
Northeast AZ
Southern CA
SERC
AZ/NM/SNV
FRCC
: Constraint and constrained flow direction
FERC found that the costs of individual con-
conditions in the eastern portion of New York
straints for these months generally ranged
during the summer of 2000, FERC estimated a
from less than $5 million to more than $50
cost of more than $700 million.
million. However, for one particular set of
Source: FERC. 2001. Electric Transmission Constraint Study. Division of Market Development. Download from http://www.ferc.gov
Finally, POEMS does not analyze relia-
The POEMS analysis offers minimum
bility benefits. Increased transmission
estimates of the benefits of vibrant whole-
capacity will generally improve the overall
sale markets to the consumer. However,
reliability of the grid and allows regions to
the trend is clear: transmission bottle-
share capacity reserves. Although the risk
necks today compromise important nation-
of blackouts is generally small, blackouts
al interests in efficient regional wholesale
usually entail very high economic costs. As
electricity markets and reliable transmis-
such, even a small reduction in the risk of
sion systems.
a blackout will have substantial benefits.
The National Interest in Relieving Transmission Bottlenecks
18