6.6. ERMUSR 01-11-2005/j
Elk River -~-~
Municip al Utilitie s
13069 Orono Parkway
Elk River, MN 55330
January 3, 2005
To: Elk River Municipal Utilities Commission
Jerry Takle
,1im Tralle
John Dietz
From: Bryan Adams
Subject: Electric Utility Issues
phone: 763.441.2020
Fax: 763.441.8099
Enclosed are two articles that deserve your attention. The first is CapX 2020 Interim
Report, drafted by Great River Energy, Minnesota Power, Missouri River Energy
Services, Otter Tail Power Company, and Xcel Energy. This report addresses the
generation and transmission need and costs for the State of Minnesota to get us to the
year 2020.
The other article is APPA's paper titled, "Restructuring at the Crossroads.'' The regional
transmission organization (RTO) that have been established have spiraling costs,
unaccountable governance structures and using questionable market mechanisms. Our
RTO is Midwest Independent System Operation (MISO), which is a break off of Mid-
Continent Area Power Pool (MAPP). Great River Energy, who takes care of our
transmission needs, .just joined MISO. MISO tariff structure is due to be implemented
March I, 2005. Cost of the RTO is increased with no associated increase in benefit, just
another layer of bureaucracy. MISO's marginal pricing scheme is very complicated with
much room for gaming.
COX 2020
INTERIM REPORT'
DECEMBER 2004
INTERIM REPORT
IDENTIFYING MINNESOTA' S
ELECTRIC TRANSMISSION
INFRASTRUCTURE NEEDS
CAPX 2020
GREAT RIVER ENERGY
MINNESOTA POWER
MISSOURI RIVER ENERGY SERVICES
OTTER TAIL POWER COMPANY
XCEL ENERGY
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POWER COMPANY - ,
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CAPX 2020
INTERIM REPORT
DECEMBER 2004
TABLE OF CONTENTS PAGE
IDENTIFYING MINNESOTA'S ELECTRIC TRANSMISSION INFRASTRUCTURE 3
NEEDS: AN INTERIM REPORT
Future needs 3
Our current system 4
A changed market 4
The CapX 2020 planning effort 5
Preliminary results 6
Next steps 6
CapX 2020 Vision Team members ~
ATTACHMENT A: FORECASTED NEED g
ATTACHMENT B: OVERVIEW OF CURRENT TRANSMISSION SYSTEM 10
Current network I 0
Recent trends I 1
Current utility planning process 11
Current regulatory structure 12
ATTACHMENT C: OVERVIEW OF MARKET CHANCES 14
ATTACHMENT D: CAPX 2020 PLANNING EFFORT 16
Red River Valley Study 16
Vision Study 16
A. Base model development 1 ~
ATTACHMENT E: STATE PLANNING AND REGULATORY ISSUES 19
Industry structure 19
Cost recovery 19
Need certification 20
Planning 21
Timing 21
Regional issues 21
Jurisdictional issues 21
ATTACHMENT F: PRELIMINARY RESULTS 23
Study analysis 2~
Initial results 28
2
C.gPX 2020
INTERIM REPORT
DECEMBER 2004
IDENTIFYING MINNESOTA'S ELECTRIC TRANSMISSION INFRASTRUCTURE
NEEDS: AN INTERIM REPORT
Minnesota's electric transmission infrastructure-a network of high voltage transmission
lines of 230 kilovolts and higher-requires major upgrades and expansion over the next 15
years to support customers' growing demand for electricity. To ensure the backbone
transmission system is developed and available to serve these growing needs, the five largest
Minnesota transmission-owning utilities initiated the CapX 2020 project. CapX 2020 is short
for Capital Expenditures by the year 2020.
CapX 2020's mission is to:
^ Create a joint vision of required transmission infrastructure investments needed to meet
growing demand for electricity in Minnesota and the region; and
^ Work to create an environment that allows these projects to be developed in a timely,
efficient manner, consistent with the public interest.
Great River Energy, Minnesota Power, Otter Tail Power Company and Xcel Energy jointly
formed CapX 2020 in the summer of 2004; Missouri River Energy Services subsequently
joined this effort, and other investor-owned utilities, cooperatives, and municipal utilities
have been following the initiative.
This Interim Report presents our work to date. Its purpose is to create awareness of the
significant need for new transmission investment, to inform stakeholders of our study efforts
underway, and to begin a public dialogue on transmission issues. We present this report in
the following sections:
^ Our future needs, presenting forecasts of customer demand over the next 15 years.
^ Our current system, outlining the characteristics and capacity of our current backbone
transmission system.
^ A changed market, describing how management of the transmission network operates
under federal reforms.
^ The CapX 2020 planning effort, providing an overview of our CapX 2020 study.
^ Our preliminary results, presenting our findings to date.
^ Next steps, discussing the continued planning effort and inviting stakeholder dialogue.
FUTURE NEEDS
A robust bulk electric system supports our national and state economies. Data from the U.S.
Department of Energy's Energy Information Administration (EIA) show a parallel between
the nation's gross domestic product (GDP) and electricity sales.' As the GDP increases or
decreases, so does electricity demand.
~ (ht,tp_!/y~ww cia,dc~_egav/<~iai ac.g%e_lectricty_.html).
CaPX 2020
INTERIM REPORT
DECEMBER 2004
Utility resource planners foresee continuing growth in the state's population, economy and
demand for electricity. Through 2020, Minnesota electric utilities predict an annual average
growth in our customers' demand for electricity of 2.49 percent,2 far above the national
forecast of 1.8 percent per year. ~ Meeting this increased demand is expected to require an
additiona16,300 megawatts of generating capacity. To provide context for this amount, the
largest generating station in Minnesota -the Sherburne County (Sherco) plant near Becker -
provides a total of approximately 2,300 megawatts of generating capacity.
In addition to the projected increased need for electric generating capacity, customers'
demand for power quality has increased. Sophisticated electrical equipment and new
business customers, such ashigh-speed data processing centers, require highly reliable
electricity service. To meet these requirements, transmission and distribution infrastructure
must be designed to meet increasingly higher power quality standards.
CapX 2020 provides further background and detail regarding customer requirements and
projected demands in Attachment A.
DUR CURRENT SYSTEM
Designed and built in the 1960s and `70s, the high voltage transmission facilities (230
kilovolts and above) act as the supporting structure, or backbone, of the bulk electric system,
moving electricity from power plants to load centers. The system is designed to maintain
reliability even when faced with various contingencies that arise due to weather or other
factors that temporarily may remove a particular transmission facility from service. The
majority of these facilities were built in the 1970s, with the last of this class built in
connection with construction of Unit 3 at the Sherco power plant, which began operating in
1987.
Utility planners historically designed the regional transmission grid with sufficient capacity
and network capability to support the system and meet long-term growth requirements. The
grid has served Minnesota well; since 1987, only shorter, lower-voltage transmission lines
have been built, typically to meet local, load-serving needs.
Attachment B contains additional information regarding our current transmission system,
planning processes and regulatory structure.
A CHANCED MARKET
Thirty years ago, when the transmission backbone was designed and built, the region's
electric utilities jointly planned the addition of new generation and transmission facilities. In
1992, Congress deregulated the wholesale electric power supply industry, making generation
a competitive market while still regulating transmission facilities as the nation's electric
z Demand studies include information from the following utilities: Alliant Energy, Great River Energy,
Dairyland Power Cooperative, Minnesota Power, Missouri River Energy Services, Otter Tail Power Company,
Southern Minnesota Municipal Power Agency/Rochester Public Utilities and Xcel Energy.
s EIA, growth in electric sales for 2002-2025 (htt~://_w_ww_eia doc_gqv/oiaf/aeo/e_lectrici~_html)
4
CaPX 2020
INTERIM REPORT
DECEMBER 2004
highway system. A subsequent series of initiatives by the Federal Energy Regulatory
Commission (FERC) has provided further change to industry structure.
As a result, the way the electricity industry operates has changed considerably. A key
change is the functional separation of transmission from generation to ensure equal access to
the grid, which the FERC mandated in 1996. The upshot of this change is that generation
and transmission planning must now be performed separately and in a nondiscriminatory
manner; transmission planning and development must be prepared to meet the needs of all
regional market participants rather than just those of the individual utility or specific
generation resource type. Attachment C provides an overview of these changes, including
the transition to regional transmission organizations.
THE CAPX 2020 PLANNING EFFORT
It is clear that our current transmission network will be unable to accommodate the required
new generation and increased customer demand without significant upgrades and new
facilities. To identify projects needed to meet customer needs well into the future, CapX
2020 has undertaken two technical studies on major transmission facilities needs in
Minnesota: the Vision Study and the Red River Valley Study. We expect both to be
completed in May 2005.
The Vision Study will outline key infrastructure improvements needed to meet future needs
under a variety of possible scenarios. Our planners are considering various potential
scenarios of generation development to determine what system investments will be required
regardless of location of new power plants. With this study, we will identify projects that
will meet our customers' and the region's needs. Our goal is to identify the next major
transmission backbone investments required to ensure a robust network capable of
accommodating growth and providing continued reliable service well into the future.
Transmission investments of this magnitude take several years; therefore, the planning
process for meeting these needs has begun.
The Red River Valley Study focuses on near-term transmission needs to address known
transmission reliability issues in west-central Minnesota. CapX 2020 undertook the Red
River Valley Study to build on a recent study by utility transmission planners that revealed
this area to be the most immediately vulnerable. Studies show that within the next three
years, low voltages along with potential voltage collapse could occur during winter peak
conditions. Additionally, the study will address reliability issues in central Minnesota.
While more local in nature, this study will produce detailed information capable of
supporting a certificate of need for the projects found to be most appropriate.
Concurrent with these technical studies, CapX 2020 is reviewing state processes to determine
whether they are able to support development of the required transmission infrastructure in a
timely, efficient manner, consistent with the public interest. In particular, CapX 2020 is
reviewing current approaches to certification and cost recovery, while also evaluating
industry structure, routing and jurisdictional issues. CapX 2020 is committed to working to
create an environment that allows needed transmission infrastructure additions and
CAPX 2020
IN'7ERIM REPORT
DECEMBER 2004
improvements to be developed in a timely, efficient manner consistent with the public
interest.
Attachment D provides more detail on these technical studies, while Attachment E
summarizes our on-going review of state planning and regulatory issues.
PRELIMINARY RESULTS
Preliminary results from these studies show that the current transmission system will not
support the forecasted need for new generation facilities to meet projected customer demand.
Absent new investment in transmission facilities, our preliminary analysis anticipates
significant line and equipment overloads by 2020, assuming customer requirements develop
as projected. These overloads occur under even the most optimistic scenario that has all
major transmission lines and equipment in service. Many more overloads occur when other
facilities must be removed from service because of storm damage, for routine maintenance or
for any other reason.
Under the Vision Study, we are considering several possible scenarios of generation
development and the transmission additions needed to serve each. Comparing the resulting
plans will allow us to identify the projects needed to reinforce the grid regardless of how
generation develops. All told, the study is examining approximately 3,300 miles of
additional transmission facilities with an estimated cost of $2.7 billion. While all of these
facilities may not be needed to address the customer needs in 2020, CapX 2020 believes it is
important to identify for stakeholders the magnitude of investment and projects under review.
Preliminary findings from the Red River Valley study recommend short-term upgrades to
ensure reliability in the near future and along-term system solution. While work has already
begun on many of the short-term upgrades, the best long-term alternative includes a new 345
kilovolt line from Fargo, N.D., to St. Cloud, Minn., and a 230 kilovolt line from Bemidji,
Minn., to Grand Rapids, Minn. Our further study will confirm whether this project is still
the best long-term solution.
NEXT STEPS
CapX 2020 is committed to making the necessary investments to upgrade the grid that
delivers power to customers. We agree now is the time to strengthen the electricity system's
backbone, before new power plants are constructed and in time to meet customer needs.
Our next steps include:
^ Completion of the technical studies in May 2005.
^ Dialogue with policymakers and stakeholders regarding the CapX 2020 studies and state
process issues.
^ Outreach to other transmission providers to share information and collaborate on
solutions.
6
CAPX 2020
INTERIM REPORT
DECEMBER 2004
Minnesotans will require access to new generation facilities to meet projected growth. They
will need a robust transmission system, one that can provide service reliably into the future,
to support the new generation facilities. To meet these needs, significant transmission line
upgrades and new transmission construction will be required over the next 15 years. CapX
2020 understands these needs and believes planning and construction must be done wisely,
serving the public interest through a deliberate process that includes all stakeholders. We
look forward to working with stakeholders to ensure these objectives are met.
CAPX 2020 VISION TEAM MEMBERS
Will Kaul
Vice President, Transmission
Great River Energy
Elk River, Minnesota
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Tom Ferguson
Vice President, Power Delivery and Transmission
Minnesota Power
Duluth, Minnesota
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Raymond J. Wahle
Director, Power Supply and Operations
Missouri River Energy Services
Sioux Falls, South Dakota
www.mrencr~,-~~on~
Rod Scheel
Vice President, Asset Management
Otter Tail Power Company
Fergus Falls, Minnesota
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Doug Jaeger
Vice President, Transmission, Safety & Technical Training
and Don Jones
Director, Transmission Asset Management
Xcel Energy
Minneapolis, Minnesota
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CAPX 2020
INTERIM REPORT
DECEMBER 2004
Attachment A
FORECASTED NEED
Utilities constantly assess how much customer demand for electricity will grow each year
and what their generation and transmission capacity must be to ensure a reliable, low-cost,
adequate supply of electricity. Most Minnesota utilities calculate their future demand and
describe the ways they plan to meet that demand in the resource plans filed with and
reviewed by the Minnesota Public Utilities Commission (PUC) every two years.
Resource plans include a utility's 15-year load forecast, its forecast for demand-side
management impacts-those load management and conservation programs used to reduce
peak demand, encourage energy conservation and improve energy efficiency-as well as
how they are meeting other regulatory and legislative requirements. Resource plans are
available to the public from the Minnesota PUC. Many utilities also make theirs available on
their Web sites.
In addition, Minnesota utilities annually submit reports of their estimated load and capability
-how much electricity their customers will demand in the future and what generation
facilities they will use to meet that demand - to the North American Electric Reliability
Council (NERC) through the Mid-Continent Area Power Pool (MAPP). Through this
submission, NERC assesses whether enough electricity is available to meet customer demand
during the next season. This report is available on the MAPP Web site at www.mapp.org.
Like resource and generation planning, transmission planning begins with a projection of
future customer needs. To this end, the CapX 2020 technical team chose the MAPP 2004
Series, 2009 summer peak model, as the base model to begin scaling loads to the anticipated
2020 load level. To accurately mode120201oads, the technical team used individual
company load growth from the 2004 MAPP Load and Capability Report for the following
company control areas: Alliant Energy (west), Xcel Energy (north), Southern Minnesota
Municipal Power Agency, Otter Tail Power Company (includes Minnkota Power
Cooperative and Missouri River Energy Services) and Dairyland Power Cooperative.
Minnesota Power and Great River Energy's loads were scaled based on their most recent
resource plan filings.
Table 1 shows the CapX 2020 technical team's projection of future customer needs.
8
COX 2020
INTERIM REPORT
DECEMBER 2004
Control area 2009 load level
(2004 MAPP Series)
me awatts Yearly
growth rate
% Calculated 2020
load level
me awatts
ALT (West) 3265.3 1.60% 3888.2
Xcel Energy (North) 9632.6 2.68% 12885.1
MP 1507.3 1.70% 1814.4
SMMPA/RPU 330.0 2.70% 442.4
GRE 2833.5 3.05% 3894.0
OTP/MPC/MRES 1677.2 2.70% 2248.3
DPC 954.7 2.60% 1266.2
Total 20200.6 Ave. = 2.49% 26487.8
Table 1
Thus, electricity use in Minnesota will continue to increase even with consistent investment
in energy conservation programs. As shown, Minnesota utilities' forecasts project an
average annual growth rate of approximately 2.5 percent through 2020. Based on this growth
rate, nearly 6,300 megawatts of new generation will be needed to serve Minnesota customers
by 2020.
9
CAPX 2020
INTERIM REPORT
DECEMBER 2004
ATTACHMENT B
OVERVIEW OF CURRENT TRANSMISSION SYSTEM
CURRENT NETWORK
Minnesota's electric transmission system is part of a regional transmission grid operated in
coordination with other interconnected transmission systems throughout the Upper Midwest
and the entire Eastern United States. The system is managed by regional organizations and
control centers that are staffed 24 hours a day, 365 days a year.
Although it originally was designed to reliably deliver power to major electric load centers,
such as the Twin Cities metropolitan area, Duluth, Mankato, Rochester, and St. Cloud -and
to interconnect utilities so they could back up each other during emergencies -the
transmission grid now must do much more. It acts as a regional "highway," providing the
physical link between sellers and buyers, facilitating an ever-increasing number of
transactions among an increasing number of market participants and over increasing
distances. At the same time, the grid continues to serve a critical reliability role.
Diagram 1 provides a simplified overview of the electric system.
The load-serving transmission system
delivers power from the bulk
transmission system to distribution
substations. 1
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T
t.
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~' ~~
The bulk transmission system
delivers power from power
plants to the load- serving
transmission system.
.~-
Local utilities
use distribution
power lines to
transport
electricity to
neighborhoods.
Diagram 1
10
C.4PX 2020
INTERIM REPORT
DECEMBER 2004
RECENT TRENDS
According to the May 2002 National Transmission Grid Study by the U.S. Department of
Energy (DOE), investment in new transmission facilities declined steadily nationwide for the
previous 25 years while growth in demand and additions of new generation have continued.
Further, the DOE study states that this disparity between the demand for electricity and the
capacity to transport it shows no sign of abating. According to the DOE study, "Construction
ofhigh-voltage transmission facilities is expected to increase by only 6 percent (in line miles)
during the next 10 years, in contrast to the expected 20 percent increase in electricity demand
and generating capacity."
Minnesota and the surrounding region are not exceptions to this trend. Since 1980, demand
for electricity in Minnesota has grown steadily at a rate of 2.64 percent annually. While the
current grid has accommodated this growth and generally is adequate to meet today's needs,
this increase in volume has used most of the system's spare capacity. Utilities have made
modest system improvements and investments to meet basic load serving and reliability
requirements and optimize the transmission capacity, but they have not been inclined to
undertake major transmission construction projects.
CURRENT UTILITY PLANNING PROCESS
Today, regional transmission planning is coordinated by the Mid-Continent Area Power Pool
(MAPP), a voluntary association of electric utilities and other electric industry participants,
and the Midwest Independent Transmission System Operator Inc. (MISO), a regional
transmission organization with functional control over all high-voltage transmission
facilities. While MAPP and MISO provide overarching regional processes for transmission
planning, plans still begin with the individual electric utilities that own and/or operate
transmission facilities.
Each utility employs transmission planners whose principal responsibility is to ensure the
safety and reliability of the transmission system for the benefit of all customers. The
planners prepare detailed studies, first assessing present and projected electricity demand and
then identifying areas on the transmission system that are increasingly inadequate to serve
current and future customers. The planning horizon is generally 10 years.
Individual utilities submit their plans to MAPP sub-regional planning groups (SPGs), made
up of transmission planners from MAPP member utilities and other stakeholders, including
state regulatory agencies and environmental advocacy groups. The SPG process allows
utilities to coordinate their plans and collaborate on how best to serve the region. The
process considers transmission expansion alternatives, new generation facilities that may be
planned for the region, and how additions to the regional transmission system may impact
neighboring regions.
SPGs invite public participation into the process, explain their findings to the public and
consider the public's input into the plan and the best route for the proposed transmission
lines. The results are sub-regional plans that are "rolled up" into a MAPP regional plan and
incorporated into MISO's overall regional and interregional plans.
CaPX 2020
INTERIM REPORT
DECEMBER 2004
Additionally, the state of Minnesota has a biennial transmission planning process. Minnesota
law requires each electric transmission-owning utility to file a biennial transmission planning
report. State rules prescribe the process of soliciting public input into biennial planning
reports, including a requirement for public planning meetings in different parts of the state.
CURRENT REGULATORY STRUCTURE
Regulatory oversight of transmission occurs at several levels and by different regulatory
bodies, including:
^ The Federal Energy Regulatory Commission (FERC), which has authority over interstate
transmission and wholesale transmission rates and regulates regional entities such as
MISO.
^ Regional transmission organizations (RTOs), such as MISO, which oversee and
coordinate regional transmission planning and services to facilitate fair and competitive
wholesale markets.
^ Regional reliability councils, such as MAPP, which set protocols for grid operations and
standards for reliability.
^ State public utilities commissions, which set retail rates for public utilities and often
decide whether new generation and transmission projects are needed.
^ State environmental agencies, which may oversee the new transmission routing.
A series of FERC orders during the past five years has dramatically changed the regulatory
landscape for electricity transmission. Continued change, such as the transition to MISO's
Day 2 Market with use of regional wholesale electricity markets and significantly different
pricing for transmission service, is forthcoming.
Here in Minnesota, state regulatory authority is vested in several agencies, including:
^ The Minnesota Public Utilities Commission (PUG), which oversees retail utility rates
including transmission investment recovery, transmission planning, and need
determinations for certain new transmission projects through the state's certificate of
need process.
^ The Environmental Quality Board (EQB), which oversees transmission line routing,
taking into consideration various environmental issues associated with proposed routes.
^ The Minnesota Department of Commerce (DOG), which is charged to be the primary
public advocate in proceedings before the PUG. As such, it investigates and evaluates
utility proposals and advances recommendations for the PUC to consider.
^ The state's Reliability Administrator, housed within the DOG, who is charged by law to
develop information regarding the need for transmission and work with stakeholders to
ensure the continued reliable provision of electric service within the state.
^ The Minnesota Office of Attorney General, which represents residential and small
business customers in proceedings before the PUC and also may advance
recommendations for the PUC to consider.
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CAPX 2020
INTERIM REPORT
DECEMBER 2004
State laws and rules govern the processes used by these agencies. In 2001, the Minnesota
Legislature adopted a number of changes to the governing statutes in an effort to streamline
the regulatory processes over transmission. Both the PUC and EQB undertook rulemaking to
implement these statutory changes, the last of which was just recently completed. To date,
these new processes have not been significantly used or tested.
13
CAPX 2020
INTERIM REPORT
DECEMBER 2004
ATTACHMENT C
OVERVIEW OF MARKET CHANGES
The federal policy changes of the early 1990s designed to open access to wholesale
electricity markets caused significant changes in operation of the transmission grid and led to
creation of regional transmission organizations (RTOs). In 1996, the Federal Energy
Regulatory Commission (FERC) mandated that electric utilities offer "open access" to their
transmission systems. Since 2000, the FERC has strongly encouraged all of its jurisdictional
utilities to join RTOs and to transfer to the RTO functional control of the utilities'
transmission assets. Non jurisdictional utilities -such as Minnkota Power Cooperative and
Great River Energy -have the option to join an RTO as well, and some have.
The Midwest Independent Transmission System Operator Inc. (MISO), which began
operations on Feb. 1, 2002, is the RTO for utilities in large parts of the Midwest and Upper
Midwest. MISO is developing rules and systems for users to follow in conducting grid
operations in accordance with North American Electric Reliability Council (NERC)
standards. It operates with stakeholder input and participation under the FERC's overall
direction. MISO controls access to and use of the grid for wholesale transactions for its
member companies. Most of Minnesota's transmission system now is operated under the
oversight of the MISO umbrella organization.
Placing functional control of jurisdictional utility transmission assets under MISO was a first
phase in FERC RTO policy implementation, which was designed to open up access to
wholesale electric energy markets. The second phase is to establish an energy transaction
market that allocates transmission access based on economic signals rather than physical
line-loading procedures. This second, market-based phase of MISO RTO implementation is
called the Day 2 Market.
MISO has announced its intention to begin operating a Day 2 market on March 1, 2005. This
market will allow MISO to manage congestion on the wholesale electric power system
through the use of locational marginal pricing (LMP), which will be the market-clearing
price for energy at the location to which the energy is delivered or from which it is received.
LMP varies by time and location, based on physical limitations, congestion and loss factors.
The Day 2 Market will consist of two key components:
^ Day-ahead energy transactions based on each market participant's forecasted needs and
resource availability.
^ Real-time transactions that true-up system-wide supply and demand.
Currently, no price signals exist to designate congested or less-congested power delivery
routes on the transmission grid. Price signals would encourage market participants to
consider the most efficient alternatives to deliver power. Wholesale energy purchase
decisions are less efficient than they could be at times under the current system. For
14
COX 2020
INTERIM REPORT
DECEMBER 2004
example, a utility may have to buy more energy than it needs to secure a certain transmission
route.
Another example is that the current system of allocating transmission access also may force
cuts to power delivery schedules for established purchases and force a utility to operate one
of its more expensive peaking units to meet customer need.
The centralized energy market resulting from MISO's operations is designed to allow for
more economically efficient use of existing transmission and generation assets. This, in turn,
is expected to produce wholesale and retail consumer savings.
For more information about MISO and the Day 2 Market, visit the MISO Web site at
www.midwestiso.ol~.
For more information about FERC initiatives to restructure the electricity industry, visit the
FERC Web site at www.ferc.gov.
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CAPX 2020
INTERIM REPORT
DECEMBER 2004
ATTACHMENT D
CAPX 2020 PLANNING EFFORT
The CapX 2020 technical team is working on two studies: one to address known reliability
issues in the Red River Valley and the other to identify adequate transmission additions to
meet the future load growth of the utilities that operate transmission within Minnesota.
RED RNER VALLEY STUDY
The Red River Valley study continues work started in 2001 to address load-serving reliability
concerns in northwestern Minnesota. Initial studies indicated that low voltages along with
potential voltage collapse could occur during winter peak conditions. These preliminary
studies identified short-term upgrades and long-term system solutions.
Work has begun on many of the short-terns upgrades, which include reconductoring,
transformer change outs and switched capacitor additions. The best long-term alternative in
the original study included a new 345 kilovolt line from Fargo, N.D., to St. Cloud, Minn.,
and a 230 kilovolt line from Bemidji, Minn., to Grand Rapids, Minn.
The current study will determine whether these long-term solutions remain the best
alternatives to address the load-serving and reliability issues in northwestern and central
Minnesota in preparation for a certificate of need. The study will involve gathering present
load data for the region and performing asteady-state power flow analysis and voltage
stability analysis to determine how serious the problem is.
The timeline for completing the Red River Valley study is in Table 2.
Task Schedule
Model preparation 9/27/04 - 12/9/04
Power flow analysis 12/9/04 - 1/17/05
System improvement analysis 1/17/05 - 3/17/05
Misc. items (economic losses, etc.) 1/18/05 - 4/11/05
Stability analysis 3/17/05 - 4/27/05
Table 2
VISION STUDY
A parallel study will determine transmission needs in Minnesota and the surrounding area to
meet the anticipated load growth in the region and the corresponding new generation needed
to serve the load. This study will identify transmission solutions that address anticipated load
in the year 2020. It also will develop a transmission plan that can address a variety of
generation scenarios in the region.
16
CAPX 2020
INTERIM REPORT
DECEMBER 2004
A. BASE MODEL DEVELOPMENT
The CapX 2020 technical team chose the MAPP 2004 Series, 2009 summer peak model, as
the base model to begin scaling loads to the anticipated 20201oad level. To accurately model
2020 loads, the technical team used individual company load growth from the 2004 MAPP
Load and Capability Report for the following company control areas: Alliant Energy (west),
Xcel Energy (north), Southern Minnesota Municipal Power Agency, Otter Tail Power
Company (includes Minnkota Power Cooperative and Missouri River Energy Services) and
Dairyland Power Cooperative. Minnesota Power and Great River Energy's loads were scaled
based on their most recent resource plan filings. The results are in Table 3.
Control area 20091oad level
(2004 MAPP Series)
me awatts Yearly
growth rate
% Calculated 2020
load level
me awatts
ALT (West) 3265.3 1.60% 3888.2
Xcel Energy (North) 9632.6 2.68% 12885.1
MP 1507.3 1.70% 1814.4
SMMPA/RPU 330.0 2.70% 442.4
GRE 2833.5 3.05% 3894.0
OTP/MPC/MRES 1677.2 2.70% 2248.3
DPC 954.7 2.60% 1266.2
Total 20200.6 Ave. = 2.49% 26487.8
fable 3
17
CaPX 2020
INTERIM FEPORr
DECEMBER 2004
Diagram 3 shows the geographic boundaries of the load being scaled in the study.
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18
CAPX 2020
INTERIM REPORT
DECEMBER 2004
ATTACHMENT E
STATE PLANNING AND REGULATORY ISSUES
To determine whether current regulatory processes can facilitate the implementation of
needed transmission, CapX 2020 is undertaking a review of Minnesota statutes and rules.
This effort is intended to determine whether any change would be appropriate to these
processes to ensure:
^ Reliability.
^ That timely additions and upgrades to the transmission grid can be implemented to
deliver needed energy and capacity.
^ Compliance with state policies, such as a good faith effort to meet the Renewable Energy
Objective.
^ Access to generation and markets to lower the costs of electricity for customers.
^ Consistency with the current regulatory landscape, given significant changes at the
federal and regional level.
We present a brief summary of the various issues under review.
INDUSTRY STRUCTURE
As previously noted, significant changes in the industry are underway with the evolution and
implementation of regional transmission organizations (RTOs), and the need for significant
new transmission investment is great. It is appropriate to consider different approaches and
opportunities presented under the RTO structure that may help facilitate the significant
investments that will be required. It is possible that investment by individual utilities at the
levels anticipated to be required under this effort is not the most efficient or cost-effective
approach available and all reasonable possibilities should be explored.
COST RECOVERY
Utilities recover investment in transmission through retail and wholesale rates. Investor-
owned utilities' retail rates are regulated by the Minnesota Public Utilities Commission
(PUC), while rates of cooperative and municipal utilities are set by their local
regulatory/governing bodies. Rates for investor-owned utilities' transmission services to
small utilities, such as municipal utilities, are regulated by the Federal Energy Regulatory
Commission (FERC).
For investor-owned utilities, recovery of transmission investments generally requires the
utility to file with the PUC a general rate case after construction is completed and the
transmission lines are in service. General rate cases are 10-month, contested-case processes
where all utility costs are reviewed for appropriateness of cost recovery. Rates set in this
process would recover all prudent transmission investments, including those made since the
time of the last rate case. (The one statutory exception to this process applies to Xcel Energy
and allows direct recovery of transmission investments needed to accommodate mandated
renewable energy.)
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CAPX 2020
INTERIM REPORT
DECEMBER 2004
Some concerns with the current cost recovery process exist. They include:
Required investments not large enough to drive a general rate proceeding; cost recovery
can lag investment. Transmission investments account for approximately 7 percent of
total utility costs, so by themselves they do not justify the time and expense of a general
rate case proceeding. However, planning, certification and routing proceedings -and
ultimately construction and operation of new transmission projects -can require
significant investments prior to cost recovery. Until a general rate case is filed, the costs
of incremental transmission investments are incurred by the utility but not recovered in
rates. This "regulatory lag" provides a disincentive for significant transmission
investment.
Cost recovery at authorized returns may not be sufficient to encourage large-scale
undertakings with attendant risks ofnon-certification of facilities or lengthy, contentious
proceedings. The Federal Energy Regulatory Commission (FERC) considers returns to
appropriately compensate for investments in transmission, recognizing the nature of these
investments. In contrast, state regulation uses a single rate of return to compensate for all
electric utility investments -generation, transmission, distribution, customer service and
other costs. A single return may not appropriately compensate for the risks associated
with large-scale transmission investments, given their unique nature.
Current recovery mechanisms do not encourage appropriate decisions between
generation and transmission investments. To some extent, additional generation and
transmission are substitutes for each other. In some cases, transmission investments may
allow for acquisition of distant resources that can more cost effectively meet customer
needs, provide a robust grid, or otherwise strengthen access to markets that help with
effective functioning of the wholesale energy markets. Current regulatory and cost
recovery mechanisms, however, can favor investment in generation as opposed to
transmission, as costs are more likely to be promptly recovered for generation
investments.
NEED CERTIFICATION
The criteria for determining whether a proposed transmission facility qualifies for a
certificate of need address a variety of issues. These criteria were established by statute in
the 1970s, prior to the recent changes in the use and oversight of the transmission grid and do
not specify any particular weighting.
These criteria should be reviewed in light of today's environment, as reliability, access to
markets and the robust functioning of a wholesale market may be appropriate additional
criteria to consider. Such a review should consider whether to add regional considerations to
the state's decision-making, as some transmission investments may not be required to
specifically serve Minnesota load but rather are needed to address regional reliability issues.
Further, it may be appropriate to consider assigning weights to the various criteria to ensure
that reliability has priority consideration.
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COX 2020
INTERIM REPORT
DECEMBER 2004
PLANMNC
The biennial state transmission planning process established by statute in 2001 and governed
by the PUC provides increased and early public participation and is intended to promote
overall a more expeditious and less contentious need certification process. Certification as
part of the biennial process was intended as an expedited alternative to the certificate-of--need
process; however, this approach has not been used and may pose more risk and difficulty
than advantages.
The certificate-of--need process has been used for alarge-scale project only once, in 2003.
The new alternative biennial certification process authorized by the 2001 Legislature has not
been tested for smaller-scale projects. Nonetheless, given the anticipated significant need for
new transmission in the relatively near future, the question is whether current state processes
for permitting transmission facilities are properly designed to accommodate needed
infrastructure improvements.
TIMING
The Minnesota certificate-of--need process for transmission requires the PUC to approve or
deny a proposal within six months of application (Minn. Stat, 216B.243, subd. 5); the route
process requires the Environmental Quality Board (EQB) to decide within 12 months for full
process (Minn. Stat. 116C.57, subd. 1) and six months for alternative process (Minn. Stat.
116C.575, subd. 7).
Although both regulatory processes identify a time period in which they are to be completed,
as a practical matter the statutory deadlines frequently are inadequate to ensure the processes
move along to an expeditious conclusion. There are no consequences if the deadlines are
missed, and it is impractical for utilities to challenge missed deadlines. Further, some
deadlines may be unrealistic (too long or too short), depending on the nature of the project.
REGIONAL ISSUES
Transmission affects interstate commerce, which is why it is regulated in part by the FERC.
Unlike the interstate natural gas pipeline system, however, transmission need and routing
decisions are made entirely at the state level. State regulators often are presented with the
difficult task of balancing both regional and state needs, while being required to follow only
state law. This promotes the state's interest over regional interests. No single forum is
charged with looking out for the regional interest.
JURISDICTIONAL ISSUES
As noted above, two state agencies are involved in Minnesota's permitting processes:
^ The PUC has jurisdiction over certificates of need for any high-voltage transmission line
of 100 kilovolts or more and greater than 10 miles or that crosses a state line, and any
high-voltage transmission line greater than 200 kilovolts.
^ The EQB has jurisdiction over granting route permits to any high-voltage transmission
line greater than 100 kilovolts.
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CAPX 2020
INTERIM REPORT
DECEMBER 2004
State law (216B.243, subd. 4) allows the agencies to conduct joint hearings "when feasible,
more efficient, and may further the public interest." So far, joint hearings are used only on
non-controversial projects.
In addition, FERC rules now require that high-voltage transmission projects be approved
through the Midwest Independent Transmission System Operator's (MISO) regional
planning process. So the potential exists for conflicts between the MISO regional plan and
decisions of the PUC and EQB regarding facilities solely within Minnesota.
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CaPX 2020
INTERIM REPORT
DECEMBER 2004
ATTACHMENT F
PRELIMINARY RESULTS
The CapX 2020 technical team assumed that the generation modeled in the 2009 summer
model would exist in 2020 and would serve the load modeled in 2009. To address
anticipated load growth of 6,300 megawatts, the team solicited information from independent
power producers (including wind developers), resource planning entities within various
organizations, and the Midwest Independent Transmission System Operator's (MISO's)
generation interconnection queue. The team mapped the locations of these resources and
identified five generation regions: northern Minnesota, North Dakota and South Dakota,
southern Minnesota/northern Iowa, Wisconsin and the Twin Cities metropolitan area. These
are shown in Diagram 4.
Diagram 4
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CaPX 2020
INTERIM REPORT
DECEMBER 2004
Diagram 6 -Minnesota Kias
26
C.4PX2020
INTERIM REPORT
DECEMBER 2004
L,a~, au, i - r.as,ern nias
Transmission improvements identified in the 2003 Minnesota Biennial Transmission Plan are
included in the CapX 2020 base model. The plan is available at www.nlinnclccn•ans.co~li.
STUDY ANALYSIS
The technical team will test several transmission solutions for each generation scenario and
will perform steady-state power flow analysis (first contingency simulations) to determine
which transmission solution eliminates thermal overloads on transmission greater than 100
kilovolts in the region. The team also will perform voltage analysis for each of the
transmission solutions.
The technical team plans to incorporate transmission alternatives identified in on-going
studies in conjunction with transmission plans identified by various transmission
stakeholders. The goal is to identify transmission improvements that bring remote generation
to the load-serving centers in the region and develop an expanded transmission backbone that
supports continued load growth in the various load centers. The transmission improvements
will focus on high voltage solutions (345 kilovolt lines and 500 kilovolt lines) that best
address the various generation scenarios, as shown in Diagram 8.
27
C~sPX 2020
INTERIM REPORT
DECEMBER 2004
Diagram 8 -Conceptual transmission
INITIAL RESULTS
Preliminary analysis by the CapX 2020 technical team on the three generation scenarios has
identified a significant number of transmission overloads if no additional transmission is built
to serve the projected 6,300 megawatts in new generation needed by 2020 to meet growth in
customer demand. The team currently is simulating the loss of single transmission elements
to assist in the determination of transmission alternatives to address violations of North
American Electric Reliability Council (NERC) criteria (low voltages and overloaded
facilities) that would occur. Table 5 shows overloaded transmission facilities in Base 2020
models.
28
CAPX 2020
INTERIM REPORT
DECEMBER 2004
Scenario System Intact
Overloads Prior Outage
Conditions4 Voltage
Violations
North/West Bias _ 42 142 45
Minnesota Bias __ 42 __
187 14
Eastern Bias
42 _
_
197 ___
33
1-able 5
The schedule for completing CapX 2020 Vision study is shown in Table 6.
Task 2004-2005 Schedule
Model Preparation 9/27 - 10/29
Power Flow Analysis 11/1 - 12/17
System Improvement Analysis 1/17 - 3/17
Final Report May 2005
1 able b
a Outages of individual facilities greater than 150 kilovolts were simulated.
5 Includes the addition of a 345 kilovolt facility from Canada to Minnesota.
29
Restructuring at
the Crossroads
FERC Electric Policy Reconsidered
December 2004
w •~
.•
~~'' American Public Power Association
Contents
Page
.............................................................................
Executive Summary
Introduction .......................................................................................... 1
The Public Power Perspective .............................................................. 3
The Public Power Business Model:
Sticlcuig to the Basics ............................................................................. .I
Public Power Views on
Federal Restructuring Policies .............................................................. 6
federal Transmission Policy Must
Accommodate Regional Diversity ............................................................ . G
Needed "Mid-Course Corrections" in
Those Regions with Existing RTOs ......................................................... . 7
1 Loa.d-Serving Z,'tilities Nlusl Be Able
to Retain/Obtain Lozzg-Tel°rn "Fzrm"
l ransrnission at Known and Reasonable Rates ............................... . 7
1 There 11'lust 13e ~ti7eanin~ul l~~fech.anisms to Get Adecjuate
1 rarisrraission Infrastructure Ijuilt iaz. a Timely Fashion ................... 10
1 RTOs 11-Test 13e Accountable for l~heir Costs ................................... 14
1 RTO Governance Must fie ll~ade Accountable
to Electric Consumers' Interests .................................................... 17
1 RTO I~e~~ions Should 119ak~e Sense from a
Corrtrnerci~al and Reliability Perspective ......................................... ] S
1 The Botto~nz Line.: RTOs .Should 13e a Eoon
to Electric Consumers, Nol a Drag on. Them ................................... 18
~1'a~~s to Advance Transmission Policy
Goals in Regions Without RTOs ............................................................. 19
1 Regional Practices and Institutions that 117ee1 the
Needs of Particular Regions Should Be Encouraged ........................ 20
1 Opera Regional Ti~azzsmission Planning Ls Critical
artd Can Be Accomplished I~'itho~,tt an RTO ................................. 20
1 Joint Ou,~nership of Generation and Transmission
Reduces the Need for RTOs anal Should Be Enrouraged .................. 21
Restructuring at the Crossroads: FERC Electric Policy Reconsidered i
Pape
Public Power Views on Federal
Restructuring Policies (coneinued)
1 IERCF~~joys Si,~~~ficant Authority to
.Address fiema.inin~Discrim.ination under
the Cu~rre~zt Order 1~'0. 88f~ UriTT Reozone ..................................... ~3
1 FFRC Should Address the Concerns
of ~Vetwnrk Service Custome~s ....................................................... 24
1 Generatio~~. !Market Power Must I3e Addressed
Tlzrou~h a NerU /l~Tarket-Based Date Policy ..................................... 2~
Conclusion ...........................................................................................26
ii Restructuring at the Crossroads: FERC Electric Policy Reconsidered
Executive Summary
t is time to take stock of the Federal Energy Regulatory Commission's
("FERC") electric restnicturing policies. APPA believes substantial
"mid-course corrections" to FERC's policies are needed to fix existing
Regional Transmission Organizations (`RTOs") and to encourage non-
RTO alternatives in those regions where RTOs are not likely to Corm.
To protect electric consumers, as the Federal Power Act ("FPA") requires,
FF;RC should reorient its policies to make sure electric consumers in fact-
not just in economic theory-benefit from elects°ic restructuring.
FERC should:
1 Ensure appropriate investment in transmission and
generation infrastructure;
1 Kecognize and respect regional industry differences and preferences;
1 Encourage cost effective and not overly complex regional solutions;
1 Support rational long-term generation resource arrangements that
are in turn supported by long-term transmission service provided at
just and reasonable rates;
1 Foster ~~eell-functioning wholesale electric markets; and
1 Ensure that public utility sellers of power at market-based rates
charge `just and reasonable" prices.
APPA members in RTO regions report substantial, across-the-board
problems with spiraling RTO costs, unaccountable RTO governance, and
ever-increasing provision of RTO ser~~ces through questionable market
mechanisms. These APPA members are unable to obtain or even retain
long-term firm transmission service atjust and reasonable rates. This is
impairing their ability to enter into the long-term generation resource
arrangements thev need to provide reliable and affordable electric
sf:rvice to their end-use customers.
Because of regional differences and the largely negative experience of
APPA members now served by RTOs, many APPA members in non-RTO
regions oppose RTO expansion to their own regions. These APPA
members believe there are more cost-effective means to provide open
access transmission service and to promote market efficiency, including:
joint development of regional Open Access Sarne-time Information
Restructuring at the Crossroads: FERC Electric Policy Reconsidered iii
Systems; regional provision of market monitoring; and development of
inclusive regional transmission planning- and expansion processes. Joint
ownership of transmission facilities b~- all load-serving utilities in a region
can also address many of the transmission access issues RTOs were
intended to address. FLKC should also deal with residual discrimination
in the provision of transmission sen~ice by clarifying and more vigorously
enforcing its Order No. 888 open access transmission regime.
Finally, FL- RC must address generation market po~~'cr through a "bottom
t.ip" review and update of its~n~arket-based rate police, for both RTO and
non-RTO regions. The ability of public utility sellers to charge rnarket-
based rates is a privilege conferred under the FP.1, not a right. ~1"here
regional wholesale generation markets arc not a~mpetitive, FF:RC must
adopt enforceable protective conditions on the market-based rate
authorisations of specific public utility sellers, to ensure that rates
remain just and reasonable.
iv Restructuring at the Crossroads: FERC Electric Policy Reconsidered
Restructuring at the Crossroads:
FERC Electric Policy Reconsidered
Introduction
t has been n~,~elve years since Congress passed the Energy Policy Act
of 1992. It has been more than eight years since the Federal Energy
Regulator}' Commission ("FERC") issued Order No. 888, which
fuse encouraged the development of Independent System Operators
("ISOs"). It has been live years since FERC issued Order h'o. 2000
(its rule governing the voluntary formation of `7:egional Transmission
Organizations" ("R'TOs") ), and more than two years since it launched
its now-moribund "Standard ~~larket. llesign" ("S~~ID") initiative.
During that time, h~ERG's policti~ emphasis has changed from ensuring
non-discriminatory transmission access to advocacy of RTO-run wholesale
electric markets.
Electric restructuring has turned out to he a more complex, difficult
and uncertain undertaking than moss people imagined when FERC
issued Order No. 888. The Western market debacle of 2000-2001, the
spectacular flame-out of Enron and the subsequent revelation of its
cynical and duplicitous business practices, the massive Northeast-Midwest
blackout of August 14, 2003, the increasing and often unstable cost of
natural gas used to fuel most new electric generation, the related run-up
in long-term power supply pries (often without regard to actual
production costs), the ever-increasing costs of RTOs in those regions
where they exist, the severe financial distress of so many competiti~'e
electric ,generators/marketers, and the resulting entrance of financial
institutions and lenders into the generation and po~~-er trading sectors,
all illustrate tl~e phenomenon of unintended consequences.
There arc currently five up-and-running FEKC jurisdictional ISOs.t With
the possible exception of the Southwest Power Pool ("SI'P") region, it is
The five arc ISO New England ("'ISO NF."),the Newyork ISO ("N'y'ISO"), the
PJ~'I Interconnection ("PJ~'["), the hlid~,~est ISO (";~IISO"),and the California ISO
("CAISO").The ERCO"F ISO in Texas is not FERC jurisdictional, and hence is
not included in this discussion. y~Vhile these five entities are organized as ISOs,
and FERC has only Iinall~~ approved foi-u~ of their as Order No. 2000-compliant
R~I`Os, ~~~e ~~~ill use the term RTOs to refer to all five, both for simplicity's sake
and because this is common indusu~y usage.
not likely that RTOs will form in the rest of the country in the foreseeable
fuuare. The American Public Power Association (".APPA") believes that
RTOs are not the only-and in many regions not the best-strucun-e for
providing non-discriminatory transmission access. Thus, regional diversity
must be acknowledged, and more pragmatic and flexible federal
transmission policies i~nplernented to deal vv~th the. reality "on the ground."
It is time to take stock of FERC's electric restructuring policies-some of
~~~hicl~t AI'P:~ and its members initially endorsed-and to make badly needed
"mid-course corrections" to fix existing RTOs and to encourage non-I2"hO
alternatives in those regions ~~here they are not likely to form. A "bottom
up" evaluation is needed to ensure [he long-term adequacy of both
generation and transmission facilities, in both RTC) and non-RTO regions.
Pe~~~ "~ould say that FERC's policies }gave been an unqualified success; many
APPA members view them as a failure. APPA fears that a continuation of
the "IZTO or nothing" a~~proach and inadequate supervision of existing
RTOs will harm consumers and threaten the adequacy of our Nation's
<aectric system.
FFIZC is charged under the Federal Poker Act ("FPA") ~,~ith ensuring
that rates, terms and conditions of service for ~~~holesale electric po~~~er
and transmission service are just and reasonable" and not °unduly
discriminatorti~." FF,RC needs to examine whether its policies satisfy
these statutory requirements and benefit electric consumers-not the
independent power producing sector, the existing IZTOs; ISOs, investor-
o~~~ned utilities ("IOlis") and their shareholders, or financial institutions.
In this paper, _AYP.~~ outlines fundamental policies intended to ensure
that electric consumers in tact-not just in economic theory-benelit
from 1`ERC's initia[ivcs. It suggests that FIRC reorient its policies to:
1 Ensure appropriate investment in long-lived transmission and
generation infrastructure;
1 Recognize and respect regional differences and preferences in
the industry;
Encourage cost-effective and not overly complex regional solutions
that both fulfill FERC's statutory obligations and meet the needs of
a region's diverse stakeholders;
2 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
1 Support rational long-term resource arrangements-arrangements that
are in turn supported b~~ long-term transmission service obtainable ~~-ith
acceptable risk and at just and reasonable rates;
1 Foster well-Functioning wholesale: electric markets that prrn~ide load-
serving utilities with cost-effective supply alternatives; and
1 Ensure that sellers ol~ short-term and long-term power supplies charge
market-based rates only if the resulting prices are `just and reasonable."
The Public Power Perspective
Public power utilities were created by state or local governments tp serve
t}te public interest. They are not-For-profit entities controlled locally by
the people they serve. ~hheir purpose and obligation is to provide reliable
and low-cost electric power to their retail and wholesale reduirernents
customers, consistent ~~-ith good environmental stewardship, and to do
so consistently year after year.
Rather than focusing on
improving transmission
availability through long-
term planning and timely
investments in transmission
facilities, RTOs have..
morphed into vehicles for
implementing. centralized
markets-for day-ahead
and real-time power and
ancillary services, and the
use of Locational Marginal.
Pricing ("LMP") to deal with
APYAwas an important part of the coalition that convinced
Congress in 1992 to start the process oC opening the transmission
network to promote wholesale competition. It was an early and
strong supporter of FERC's non-discriminator}' open access
transmission policies. APPA also supported the formation of
properly structured, cost-effective RTOs, with their promise
of independent and non-discriminatory transmission service
provided under Open Access "Transmission Tariffs ("OATTs"),
regional non-paruaked transmission rates, and regional
collaborative transmission planning and constrt.iction
processes. APPA did so because it thought. these RTO goals
woi.ild benefit consumers.
APPA's early optimism, however, has dirnrned, as FERC's RTO
policies have increasingly lost sight of these shared goals.
tran$missiun COngestlon: Ratlicr than focusing on improving transmission availability
through long-term planning and timely investments in
transmission facilities, RTOs have morphed into vehicles for implementing
centralized markets for day ahead and real-time power and ancillary
services, and the use of Locational Marginal Pricing ("LIV'IP") to deal
with transmission congestion.
Restructuring at the Crossroads' FERC Electric Policy Reconsidered 3
~toreoyer, :~PP.~ has vie~~~ed ~,vith increasing alarm the busincas strategies
that some of our early allies in the open access u-ansmission debates, as
well as many of our competitors and wholesale power suppliers, have
adopted to rake pecuniary advantage of FERC's policies. "Competition,"
"restructuring," acid creation of a multitude of "markets" for their o~~~n
sake seem to have become the way to higher profits, not the means to
lower costs and improve services to coast-irners.
New markets and protocols have been implemented without a clear
understanding of ~~~hether these measures would in fact. provide real
benefits to electric consumers-benefits commensurate ~~~ith the costs
and risks that FERC and the industry have asked consumers to bear-or
whether they lead to exorbitant profits for some and unstable prices for
all. These increased costs and risks have made it. more difficult for public
po~ti~er systems to serve their own customers ~,~ith reasonably priced and
reliable po~1•er. They have also resulted in substantially higher poorer
prices in long-term bilateral markets, prices that seem to bear little
relationship to sellers' actual costs.
The Public Power Business
Model: Sticking to the Basics
Because they are locally owned and controlled, the interests of public
power systems are necessarily aligned with the long-term interests
of their respective customers and cornrnunities. Public power utilities
embrace their obligation to serve their local communities, and have
pursued vertical integration (accomplished in a variety of ways) as the
most efficient and effective means to do so.
Some systems, particularly tl~~e larger ones, are Cully integrated. They own
and operate the facilities necessary to provide electric service to retail
customers. Many others arc "virtually° vertically integrated-they have
conu-act and tariff arrangements under which they buy transmission
service fi-om others and join together through municipal joint action
agencies to o~~~n or procure generation. Still others are distribution
utilities that purchase full requirements-type encrgry and u~ansmission
service from larger utilities. Collectively, public power s}'stems are net
buyers oCwholesale power. A wholesale power market that „corks is thus
critically important to them.
4 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
Public power systems ha~'e long planning horizons and a low tolerance
for risk and price volatility. In order to scree their customers reliably
and economically, they are required to make long-teen investments and
contractual commitments. Public power s}-stems look for policies that
respect long-term contractual arrangements and keep the cost of capital
low by reducing the risk incurred as a result of such commitments.
This "stick to the basics" business model has served public power and its
customers well during the past few years, as was ver}~ apparent during the
California energry crisis. Public power entities in California and throughout
the country avoided making business decisions like those that triggered
the credit deterioration and ratings downgrades affecting the independent
power sector and many IOUs.2 Ironically, those public power
PubIIC pOWer entltl6S utilities that have suffered the most financially in recent }'Fars
COntlOUe t0 belleVe tha# got caught up in regional market blow-ups not of their making,
their Way Of Serving the or entered into transactions with counterparties that later
proved to be bad credit risks, unscrupulous, or both,
public works well. Federal
necessitating in some cases painful rate increases.3
policies should. support
their ability tOCOntlnue t0 ~ Pt.rblic power entities continue to believe that their way of
_prOYlde SUCK SerVICe. serving the public works well. Federal poticies should support
their ability to continue to provide such service. By reorienting
FERC's policies to support long-term planning and investmf°nt in u~ansmission
and generation facilities, public power systems can continue to pro~'ide the
high-qualit}' electric ser-~~~ce that our consumer-owners have come to expect.
~ See, e. g., "Public finance Report Card: Public Power," Standard & Poor's,
published September 13, 2004, at 1 ("Since our last report card, published
Jan. 2], 2004, the sector has continued to experience overall credit stability,
and even slight improvement, with 10 upgrades and t~~o do~ti~ngrades. This is
in contrast with the experience of the investor-owned and merchant sectors,
which, despite seeing a moderation in the pace and severity of downgrades,
have 40% ~~f ratings carrying negati~t~ outlooks.").According to Standard
Poor's, only Live out of 246 public power s}'stems rated were below im-esrrnent
grade (and of these, four were California irrigation districts holding contracts
with Pacific Gas and Electric Company). Id.
~~ See, e.g. "Assessing Wholesale 1\larket Risk in Pacific Northwest Public Power
Ratings," Standard & Poor's, pi.iblished august 26, 2004, at 1 ("... (The Pacific
Northwest contributed a significant fi~action of the public power rating
downgrades in these }'ears. The vast majority oC these actions can he traced
directly to the increased risks oC wholesale po~~~er markets that defined the
western U.S. power crisis.").
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 5
Public Power Views on
Federal Restructuring Policies
Federal Transmission Policy Must
Accommodate Regional Diversity
As previously noted, the country has live up-and-running FERC jurisdictional
RTOs. It does nor appear likely that RTOs ~~~ill form in the rest of the country
(with the possible exception of the SPP region). Lven if it were politicall>~
possible to export nc~ current IZIO model to those regions that do nor have
P."hOs now (~~~hic}1 iris not), the experience ro date of those
~~PP~~ mcmhers located in RTO regions does nor support such a
Even if it were politically .
course. In fact, given the considerable differences that exist in
possible t0 export the the various regions of the country, it should nor be assumed that
current RTO model t0 those RTOs arc tl~le only, or even the preferred, mechanism available
regions that d0 not have to ensure competitive wholesale po~,~er markets.
RTOs now (which it is not),
the experience t0 date ~~PPA rnembcrs located ill RTO regions report substantial,
Of those APPA members across-the-board problems ~,~it1i spiraling KZ'O costs,
located In RTO regions does rznaccountablc governance, lack of understanding of
not Support SUCK a COUI'Se. transmission customer and end-user needs and less-than-
satisfactory service options. They see more and more RTC)
services being provided through duestionable market
mechan isms, and RTO resistance to any tluestioning of the economic
theories underpinning these actions.
The rcrnaining non-RTO regions are vet}~ different both from each other
and from the regions ~~~hcre RTOs have already been created. Some
regions have a history of using contractual an-angements and regional
institutions or practices to capture mama of the benef7ts claimed for RTOs
at less risk and cost, and have sho~~~n a wil-ingness to pursue alternatives
to enhance transmission access and the efficiency of existing markets.
Othier differences include the prevalence oljointl}' o~~'ned generation and
transmission, the radial nature of transmission s}stems connecting remote
generation to loads, the predominance of hydropower in the generation
rnix, differences in population density, the extent to which open region-wide
planning processes arc used, the existence of a frame~~~ork for enforcement
of reliability standards by contract, the extent to ~,hich a standard Dorm
of contracting is used for bilateral transactions, the existence of active
~n,holesale market hubs accessible to many market participants, the presence
or absence of a few large dominant IOU transmission providers, existence of
6 Restructuring at the Crossroads' FERC Electric Policy Reconsidered
substantial transmission constraints, and the relati~-~ irnpor~lancc of
point-to-point transmission versus net~~-ork service.
APPA therefore believes that regional diversity in the prop°ision of
transmission service must be acknowledged, and a pragmatic and flexiblf:
federal transmission policy implemented to deal with the reality "on
the ground." In both cases, ho~~~ever, the same principles should govern
policymaking: fostering the development of cost-effective transmission
and generation infrastructure; supporting long-term power supply and
u-ansmission arrangements at just and reasonable rates, including the
capacity rights to deliver power supplies to loads; developing cost-
effective and responsive regional solutions that meet regional needs;
promoting market transparency; and preventing the exercise of
generation market power. The ultimate goal sl~rould be supporting
delivcrv of reliable, low-cost electric power to consumers.
Needed "Mid-Course Corrections" in
Those Regions with Existing RTOs
,1PPA members in RTO regions report substantial problems that irnp<rir
their ability to provide reasonably priced and reliable long-term service to
their own electric consumers. 'This is not to say that all RTOs
APPA membeCS In RTO are without valve and should simply be dismantled. They have
reglotlS report Substantial eliminated pancaked transmission rates (allowing transactions
problems that Impair their to take place over a broader geographic area, provided that
the necessary transmission infrastnacture is available) and
ability to provide reasonably
developed transparent spot markets in which APIA members
priced and reliable long-
can purchase needed incremental power and lay off excess
term service to thelrOWn short-term power. But APPA is alarmed acrd dismavcd by
electric consumers. the level of discontent among its members regarding RTO
performance, and the common concerns many members
express across mt.dtiple RTO regions. Clearly, corrective actions are
needed. The concerns of APPA members in RTO regions include:
Load-Serving Utilities Must Be Able to Retain/Obtain Long-Term
"Firm" Transmission at Known and Reasonable Rates
Under the LNIP rcgirnes all fire RTOs use (or intend to implement),
transmission congestion is included in the price of transmission service
and is set by reference to nodal power supply prices in the RTO's
day-ahead market at the relevant points of generation <.rnd delivery.
l~he primary tool provided to transmission customers to offset such
congestion charges is the "Financial Transmission Right" ("FTR").
Restructuring at the Crossroads' FERC Electric Policy Reconsidered 7
An FTR provides under certain circumstances a revenue stream to the
holder, which can be used to offset the congestion charges a holder
incurs as a transm~ss~on customer.
These rights, however, are limited in number, transmission path
and direction because they are tied to the physical capability of the
transmission system under specil`ied conditions. Thus, in mane cases
there are insufficient FTRs available even to hedge existing firm
transmission service arrangements. As a result, mane APPA members
have P"hR portfolios that are insufficient to hedge fully their ctn-rent power
supple and transmission arrangements, due to the "proration" of FTIls.
This Iias happened despite the assurances FERC provided in its April 2003
White Paper, where it said it would "ensure that existing customers
retain their existing transmission rights and retain rights for future load
growth."~ In I~~.tct, FERC has failed to protect fully the existing transmission
rights of utilities with an obligation t.o serve in its ne~re KTO markets. Major
generation investments and power purchases have been made for the
heneTit of consumers in reliance on transmission o~~~~ned or contracted
for on a long-term basis. It is essential that the existing transmission rights
of load-serving utilities arising out of ownership of transmission, existing
contracts (including "grandfathered" contracts) or service agreements
entered into under an individual FERC-regulaud transmission provider's
GATT, he preserved under any market design approved by FERC. The
holders of such rights should be granted the right to elect to continue to
tzse their physical transmission rights to meet their service obligations at
the prices specified in those contracts or agreements, or if they wish, to
convert to equivalent tradable rights or FTRs that will hold them harmless
under any new wholesale market design.
The use of FTRs also creates additional levels of complexity and uncertainty,
as ~a~ell as opportunities for gaming. These problems threaten the
economics of public po~,~er systems' cw-rent power supply arrangements,
man}' oCwhich are eery long term in nauzre.
:~'Iorco~°er, because FTRs are generally shorter term in duration, they
do not address public power entities' long-term needs, including load
growth. APPA members are deep]}' concerned about their inability to
hedge full}' their transmission congestion costs, and thus to assure their
Pederal Lnergy Regt.ilatory Commission, "\tihite Paper-~ti'holesale 1\[arket
Platform," issued April 28, 2003, in Docket No. ILti101-12-000, rrtiyr~eo. at Vii.
8 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
ability to obtain transmission service at a known and reasonable rate
over a long time horizon (often measured in decades, not. years).
The LIVID/FTR s}'stem has deprived thorn of their ability to plan with
any certainty for new long-term generation resources that
APPA members are deeply would require transmission service, e.g., development, of
Concerned abOUt their` or participation in a new generation resource (including
Inability t0 hedge fully their erl~ironmentally desirable resources such as wind generation),
transmission congestion or execution of long-term power supply contracts with
COStS, and thUS. t0 aSSUre suppliers that require the buyer to assume the risk of
their ability t0 Obtain transmission service.
transmission S@rViceat a ~ Under an L~9P congestion pricing regime, the "all-in" price of
known and reasonable rate any new resource is subject to price fluctuations, not only due
Over a IOng tlmehOriZOn to increases in Fuel prices, {fixed transmission costs, and other
(Often meaSUred In decades, such "traditional" factors, but. due to congestion caused by
ItOt years). shifts in transmission system usage and prices in the RTO's
spot power markets (which can be extremely volatile). This is
true even whew the tetility is not purchasing power in that market. If suppliers
agree to assume this additional price risk at all, they do so only in return
for hefty premiums that come out of electric consumers' pockets. 'T'his
increased uncertainty and risk could lead to lower credit ratings and
increased capital costs when public power systems commit to nee-v long-
term arrangements and the accompanying financing.' Since many public
po~ti•er systems are physically or ~~irtuall}' ~'erticall~° integrated acrd all retain
the obligation to serve their loads, they see this as an extremely serious
shortcoming in FERC's preferred RTO model.
Such ashort-term focused regime is not good for the industr~~ in the long
run: not good for utilities that need long-term po~ti~er supplies; not good
for generation project. developers that need long-term commitments to
support their projects; not good for financial institutions lending the
5 A Special Comment by Moody's Investors Service issued in September 2004,
en[itled "Credit Issues Kesurface as New Electric Generation Projects by Public
Poceer Utilities Take Center Stage," cites several Cactors that could contribute
ro increased credit risk for public power utilities building new generation
facilities. Prominent among thorn are transmission and pricing practices:
"Aloody's believes there is potential risk in the short-term marginal pricing
model being used in various regional energti~ markets in the U.S. VVithuut
long-term contracts for transmission rights and pricE: certainty for the
transmission of energy from new generation facilities, cost recovery in
the long term may not be assured." Id. at 4.
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 9
mime}' fot~ such projects (~,~ho ~ti-ill not. lend in the fuuzre without. long-
term commitments); not good for the econornv; and certainly' not good
for electric consumers.
Wall Street has made it abundantly clear that financial institutions ~~~ill
not again lend to generation project developers without assurances that
such developers have long-term commitments oCsome sort. to support.
their projccts.~' RTO features that impair the ability of utilities [o make
such commiUnents must therefore be revisited and revamped. Physical
transmission rights may be required to support conunitmenis to build or
The AChllleS buy from long-lived generation resources requiring substantial advance
heel Of the cornmitrnents. A~~hen L~~1P-based congestion pacing is used, it is imperative
LMP/FTR
that F1Rs of a term sufficient to hedge long-term supply and transmission
Systerll IS that arrangements be provided to those entering into such comrnitinents.
it, taken alone,
does not ensure There Must Be Meaningful Mechanisms to Get Adequate
construction Transmission Infrastructure Built in a Timely Fashion
of adequate The ~cltilles heel oC the I.'~ll'iFTP~ system described above is that it,
tranSnllSSion taken alone, does not ensure construction of adequate transmission
Infrastructure. ~nfrastructurc. [t does nothing to ensure that entities serving load in a
region have access to a robust transmission svstern, and hence competing
power supple options. ;ill the LMP/FTR system does is s1~rnv ~~'hich
source/sink pairings create transmission congestion. While the tl~eorv
is that this information will be sufficient for "the market" to spring into
action, developing economically efficient solutions to such congestion,
the reality can be much different.'
See, e. g., Transcript of FFRC technical Conference i^ Docket Nn. PL042-000,
February `2, 2004, at 8 (Statement of Lehman Brothers representative regarding
the strength of long-term conu~acts as evidence of credit~,~orthiness); Project
Finance '\e~~~s ~h'ire, :1ugt.ist 2004 issue at 5-13 report of proceedings of a
Chadbourne and Parke conference on the distressed generation project
market and the changed em~ironment for merchant generation, at which a
representative of Standard & Poor's stated: "The basic problem is ice have
in the po~~~er business a commodity business that requires large amoi.mts
of capital. It is a particularly tough commodity that. we all kno~+ cannot be
stored. The transmission and regulatory issues and lumpiness oFcapital are
particularly tough. That means long-term credit is absolutel~~ paramount.").
' David Bodek and S„ami ~'entakaraman, "hlakcover for California's Power
1v4arkets," Standa~zl f~'Poor's Ulrli.tzes ~~Pe~s/~edir~es,]ulp 5, 2004, Vol. I3, ~~o. 27,
at !~ (authors question whether C~~ISO's ~1D02 market redesign will in fact
spur nc~~- transmission incestrnent: "If MD02's ultimate aim is to ensure that
10 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
RTOs themselves do not have the ability to construct transmission
facilities, so they must rely on their member transmission owners
("TOs"). These TUs have in some cases challenged their RT'O's ability
to require thorn to build. Thee have manv reasons of their o~~~n to be
unenthusiastic about constructing the transmission facilities needed ro
alleviate congestion, including pricing structures that impact the cost.
of serving their own loads, and, in some instances, protecting their
own generation from wholesale competition.8
Sorne RTO transmission-planning regimes separately identify
Rather than pigeon-holing _ those transmission facilities needed for "reliabilit}'" purposes and
newtrallsmissionrtaeilities those needed for "economic" purposes. "Reliability" is defined
8S needed forelther _ such that so long as sufficient generation (no matter how high
reliability Or economic the price) is a.°ailable to keep the lights on, new transmission
purposes, the foCUS facilities are not deemed w be needed. This means that all
Should be On hoW t11UCh additional transmission facilities are deemed t~,~ be "economic"
in nature. Labeling specific transmission facilities upgrades as
transmission is required
both to keep the lights "economic" can in turn lead to controversies as to who should
pay for their construction.
on and. to keep rates to
COnSUmerS at just and Rather than pigeon-holing new transmission facilities as needed
reaSOnable IeYeIS. for either reliability or economic purposes, the focus should be
ou how much transmission is required both to keep the lights
on and to keep rates to consumers at just and reasonable levels. Instead
of leaving most transmission construction to the vagaries of the "market,"~
(~ootnote corati~2zeed from previous ~iage)
sufficient generation and transmission are built in California, what seems
to be lacking is a formal mechanism to plough back `congestion revenues'
earned under the nodal pricing scheme back into the system as new generation
or transmission. In its absence, itwould require a regtilatory fiat to build assets
at the right location. Many stakeholders argue that if a regulatory fiat is to be
used, there may be no need for nodal pricing and CRI2s in the first place.").
8 To be sure, the process for siting and constructing transmission facilities can
be both daunting and uncertain. The necessary approvals must be obtained
from state or local authorities, and landowners and residents located near a
proposed line corridor oaten vigorously oppose such approvals or demand
expensive alterations (including undergrounding). Siting of interstate
facilities continues to be a contentious issue in some regions.
`~ :~PP.~ notes that PJb'I, as instructed by FERC in its orders in Docket Nos.
RTO1-2-00(l, et seg., has modified its transmission planning regime to add a
new procedure to enable the construction of new transmission facilities
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 11
an RTO must develop a rigorous regional transmission planning and
constructiot~i process that ensures the region has a robust (but. not gold-
plated) transmission s~~stem.10 Each affected RTO region sltouk3 hay°e
the flexibility to develop through a collaborative process an associated
transmission facilities cost-allocation method that works bust for its
stakeholders and for electric consumers.
Transmission construction has also been relegated to second-place
status iii a number of RTOs, because "economic" transmission facilities
must "compete" with generation projects and demand-side
The value that a more rnanagcment mecl~,anisms in RTO planning processes. But
robust transmission adding individual generation units in load pockets or at weak
InfrastrUCtUre Wlll bring points on the transmission system, in lieu of constnzcting
needed transmission facilities. often only creates a ne~~~
to electric consumers-
generator with local market poorer, lower fuel elliciency, and
access to additional
only minimal benefits to consumers. Few merchant generators
sources of generation,
(entities without an obligation to serve) would build such new
support for generation
units (at ]east without along-term commitment for the power) if
fuel diversity, and r~ley thought they could not charge prices to electric consumers
strongerreliablllty- that reflect the value their location confers. The value that a
mUSt be reCOgnlZed In snore robust Lrausmission infrastructure will bring to elecU~ic
the RTO planning and consume°rs-access to additional sources of generation, support
COnstrllCtlOn proCeSS. for generation fuel diversity, and stronger rcliabilit~~-must be
recognized in the RTO planning and construction process.
,~1n important. ~~~av to address TOs' reluctance to construct needed new
transmission facilities would be to encourage joint participation by
other utilities serving load in regional transmission systems and in ne~,~
transmission construction projects. IOLT TOs in RTO regions still arc the
primary (if not exclusive) owners and builders of transmission facilities
in their respective service territories. IOUs have fold FEhC that they need
substantial transmission rate incentives to construct. new transmission
(foot~zole rnntinued fi~onz ~~r~ious ~~age)
needed for "economic" purposes, if no market solution is forthcoming in
a specified tune windo~ti~.
1o It is not economically or politically feasible to construct a transmission grid
sufficient to support all potential commercial demands of all market participants,
regardless of the associated transmission construction costs. Hence, the regional
planning process must balance the competing interests of the various market
participants, and support the construction of those transmission facilities
found to benefit the region because thev are cost-effective.
12 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
facilities, due to the risks involved.t t I'et such IOUs have ofeen overlooked
potential partners in transmission construction projects right in their own
back yards-public power systems that could join wish them in financing,
constructing, and jointly owning transmission facilities, both existing and
new. Sucfijoint projects could reduce the financial burden and spread
the perceived transmission-investment risks for the incwnben[ IOUs.
Public power participation could also assist in siting and permitting of
new transmission facilities, by sending the signal to communities that all
of the local utilities (including those that are publicly owned and not.-for-
profit) concur in the need for the project.t~
Such a regime will not work, ho~,~ever, if all that contributing public
power systems receive in return is an inadequate allocation of FTRs.
Investment in the transmission system must carry with it future long-term
certainty of transmission service at a just and reasonable cost and, for
contributing public power systems, rights that reflect their long-
For RTO r@g1011S, a term contributions to the fixed costs of the underlying system
tlmelyand effective as well as their investment in new facilities.
transmission planning
For RTO regions, a timely and effective transmission planning
and ConStrUCtlon' and construction regime is absolutely essential, especially iI~ an
regime IS abS0lUtely LI\1P/FTR regime is to remain in place. without it, an LNIY/FTR
~SSentlai, espBClally scheme will merely "price" ever-escalating transmission congestion
If an LMP/FTR i'eglme and leave intact. the illusory promise that the "market" will build
IStO remain 111 place. new t.ransrnission, increasing the resulting price of electric service
to consumers. ~b'hile some progress is being made in certain RTOs
towards reinforcement of inadequate transmission infrastructure, timely
construction of needed new regional transmission projects necessary to
~ t APPA does not concede this point, given that transmission facilities are
generally certificated prior to construction and the associated costs (including a
rate of rea.trn) are recovered in regulated rates. APPA does, however, agree that
certainty of cost recovery during the initial phases of a transmission facilities
construction project (planning, permitting, siting and initial construction)
is an issue of legitimate concern for TOs, and that in appropriate instances,
extraordinary measures may be needed to address these issues.
~~ An alternative joint transmission ownership model is that of the American
Transmission Company ("ATC") in Wisconsin. Numerous load-serving
entities in the state, including IOUs, municipal systems, and cooperatives,
own shares in A"TC, which in turn owns the higher voltage transmission
facilities in the state. ATC is responsible for planning and constructing
new transmission facilities.
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 13
ensure a sUOng regional transmission system must be made a top priority
for all R"hOs.
RTOs Must Be Accountable for Their Costs
APP: men~ibers are also increasingly alarmed by the spiralin devcloprncnt
APPA members and operational costs of RTOs.t~ It seems that persons. ~1, administrative,
are increasingly hard care and software costs arc running out oI~ control, ~yitl~tout sufficient
alarmed by appreciation of the impact of these costs on electric consumers. De~~elopment
the Splraling of corrtplex °Day Two" L1~IP markets over large geographic regions spawns
deYelOpment huge software budgcts.t~
and 0peratlODal ~1'oi-se yet, K'EO members, including .APP. members, must ramp up their o~y~n
COStS Of RTOS. internal operations, adding staff, 1-~ardware and sofr~~~•are, simply to cope ~yith
these new markets, protocols and requirement_s.~' Public po~yer systcins have
i3 Tt~e Public Po~~~er Council ("PPC") has estimated that since `?000, fora] U.S.
RTO operating expenses have increased by 143 percent., and arc: growing
at an annualized rate oI~ 2U percent per year, largely due to lack of cost
control and increases in operational size and scope. In 2004, PPC estimates
that b1.04 billion kill be. spent funding the operation of the. five FERC
jm isdiuional ISOs and the ERGOT ISO. "C:ornparatiye :~~nalysis of RTO/ISO
Operating Costs, ,august 1 i, 2004," Public Power Council, available at:
htt ~: '~~~~~a.~cndx.org/(~omparativcrlnalvsisl~~O.FINAL.ndf. Sec also, Final
Keport, "Study of Costs, Benefits and Alternatives to C:rid tl-cst," prepared for
Snohomish County Public Utility District by I Ienwood Energy Services, dated
October I~, 2004, at ES-l.
~~ On October 6, 2004, FERC released a report b~~ its Staff comparing the Day
One costs c,f Iuur RTOs (excluding the California, ;~'ew Fork and New England
ISOs and including the not-yet-operational SPP). According to Staff, initial
establishment of a Day One RTO should, after taking into account "lessons
learned," cost approximately S~0-i0 million-about half t}ie acuial cost of [he
most expensive R'FO analyzed-with annual revenue requirements of between
570 and X70 million. But Day One R"CO costs arc oily the tip of the iceberg.
FERC has made it quits clear that it expects all KTOs to develop full Dav "Itvo
markets, ~~hich FERC's own Staff calculates to be a much more expensive
proposition (in the neighborhood of y~100 to .`5250 million in initial investment
costs, wish annual operating expenses in the range of ~12d million to °5240
million), °Staff Report on Cost Ranges Cor the llcvelopment and Operation
of a Day One Regional Transmission Organization," DockeC No. PL04-1 fr000,
prepared by the Staff of the Federal Energy Regulatory Commission,
October 2004, and available at: http:'/~~~ww.fcrcgov/EycntCalendar/
Files! 20041006149 34-rto-cost-re~ort_~f.
t' For example, FERC conditionally approved rre~.ttment as a "regulatory asset"
the X29 million in internal cosGS that Dominion is spending to join PJ~I and an
14 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
to dedicate scarce personnel resources to unraveling incomprehensible (and
often erroneous) billings and settlement statements received from their
RTOs.~6 Corrected statements can come months, if not years, after the
period in duestion, disturbing accounting periods that have already been
closed and upsetting the economics of deals ah~eady done. Outside counsel
and consultants must be retained at considerable expense, simply to keep
track of RTO collaborative processes and tariff rnodifications.t~
Even APPA members not participating in KTOs are finding that 1~ZT0
cost adders are being lad-erect on top of their existing transmission see vice
agreements with TOs that do participate in KTOs. These costs can be
substantial.is Difficult "scams" issues can also arise, when RTO operating
protocols do not conform to the uniform operating practices used by
neighboring control areas within the region that have not. established RTOs.
APPA members are also concerned that RTO market mitigation and
monitoring regimes are insufficient to prevent the exercise of generation
market powf:r and thus to asst re just and reasonable poi-rer prices. The
theory underpinning LIy7P markets calls for sellers into the R~),O's
(footnote rontznucd from ~~~~evious pcrgE;i
additional X14.4 million (plus carrying charges) that Dominion spent on the
defunct Alliance RTO proposal Dominion also expects to incur X241 million
in PJI\i adrninistr;ttive charges on behalf of its retail customers during the first
five years of membership. See, Pf~'I1lralerronnection, L.I.G. and Virg nia ~~lerhic
a7ad Pozuer Co., 109 FERC ~[ 61,012 at P 47, n. 4G, issued October 5, 2001,
available at: htt %w~~~~.ferc.g_ov; EvcntCalendar/Files/20041005132245-
I-:R04-829-OOO.pol.
~~' For example, the CAISO has over 100 charge u~pes, ~~~~hich greatly add to the
conrplexiry and costs of administering billings and settlements. See, CAISO
Settlernent_Charge Matrix 17.x1s, Effecti~~e: Trade Date 10/1/2004.
17 See, Letter dated September 9, 2004, from Marc S. Gerken, President
and CEO of A~1P-Ohio, Inc., to FI?RC Chairman Pat y~'ood, available at:
htt /ferris.ferc.gov:0/idmws/file list.asp?docurrient id=4238777 (describing
increased costs A1~iP-Ohio has incurred due to implementation of RTOs,
including payTnent of $j5.9 million annually in RTO administrative costs); Letter
Response of FERC Chairman Pat ~~1'ood to :Marc S. Gerken, dated October 14,
2004, and filed in FERC Docket No. R~IO~k-12-000 (Document Accession No.
20041022-0037) .
1H For example, the Los Angeles Department oC~~Vater and Power estimates that
it is being charged approximately ~b12 million per year in GAISO-related pass-
through charges for sen~ice under its existing transmission agreements within
the CAISO control area.
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 15
organized markets to bid their marginal costs of production. In fact, bids
into the market. at tunes can be quite inconsistent with that theor}~, instead
being based on a more practical consideration of what. the market will
bear. APPA members believe that the resulting prices, even with market
price mitigation schemes in place, are oRen substantially higher than
marginal costs ~~~ould produce. 'I he resulting higher prices not only affect
hovers in the RTO's organized markets (and in longer term bilateral
rnarketsj, but all transmission customers, because these prices are used to
derive the Li~IPs that are then used to price transmission congestion.
These cosl_s might be easier to bear if RTOs ~~~ere generating overall savings
to APPA members located in RfOs and their electric consumers. APPA
members, ho~~ever, are not seeing such savings. This results from a
dumber of factors, including the implementation of the LIMP/FIR regime
for pricing congestion, ~~~hich renders their current bilateral long-
The bottom illle IS that term contract arrangements more difFicult and expensive. It is also
RTOs have not resulted difficult or impossible to avoid participating in the RTO's spot
IIl r8teredUCtI011S t0 markets, if only to clear supph~/demand imbalances, ~~~hich exposes
APPA members to the ~°olatile pricing in those markets. Of course,
the electric consumers
some price increases in the last few years have been dt.~e to factors
APPA members serve,
beyond any R'f0's control, e.g., increases in fuel paces for nauzral
8nd the aSSOClated gas, coal and rail transportation. But the bottom line is that R~I'Os
COStS keep rlSlltg. have not resulted in rate reductions to the electric consumers APPA
members serve, and the associated costs keep rising. 'hhe very fact
that RTOs must employ extensive mitigation measures and overall price
caps in their markets calls into question the existence of efI~ective wholesale
competition. All in all, it is not a pretty picture.
R"I~Os must review their operations with both aline-tooth comb and a
consumer orientation. ~~'hat RTO functions actually benefit consumers,
and can they be carried out in a more cost-effective manners Do the costs
of creating markets for every last possible product exceed the benefits that
would accrue to end-use consumers from creating those markets? Would
it be better to allow certain products to be contracted for bilaterally or to
maintain cost-based pricing for those products, especially if the associated
market power concerns are so severe that elaborate mitigation and
monitoring schemes would he required These are the types of questions
that an en tit~~ with accountability to customers would ask. RTOs must
address all of these subjects to rein in their costs, and FF.I:C must
make RTOs accountable Cor their costs to their customers and elecU°ic
consumers. The Commission's September 1G, 2004, Notice of Inquiry
in llockct No. R~104-12-000 is a tentative first step in this direction, but
16 Restructuring at the Crossroad: FERC Electric Policy Reconsidered
much more needs to be done. The Commission needs to vie~ti~ RTOs for
what they are-regional monopolies that it must vigorously regulate, not
regional extensions of the Commission itself. The FYA does not exempt
from regulation public utilities simply because they are I~fOs.
RTO Governance Must Be Made Accountable
To Electric Consumers' Interests
Four of the fi.-e current RTOs have independent and, in some cases, sell=
perpetuating boards. FERC's reason for requiring independent boards was
a good one: to avoid RTO governance structures that could be "captured"
by one or a few industry sectors, leading to bias in RTO operations and
transmission service provision. But AY PA members' experience with
independent RTO boards shows that there is a significant dog-onside as Drell.
First, independent RTO boards can lack direct accountabilit}' to the
industry participants in the KTO's region and to the electric consumers
the RTO ultimately serves. APPA members have seen RTO boards vote
to take actions that a eery substantial majority of industry stakeholders
in their own regions vehemently opposed. When such events occur
repeatedly, there is a loss of confidence in-and "buy in" to-
APPA nlenlbe~S have RTO actions b}' industry participants. This can be very damaging
..Sean RTC bOardS Vot@ t0 for the RTO itself in the long run. RTOs will only be able to
tak88ct100S that a Very operate effectively iF they are accountable and have the respect
SUbStantlal majority.Of `' of all industry participants that must deal with the RTC). "hhat
IndUStry~StakeholderS respect has to be gained and maintained through RTO board
10 their OWn re910nS and management accountability.
Vehemently Opposed. Second, some independent boards seem to rely to a very significant
degree upon RTO management and staff (who can also be
inexperienced). 'This can lead to insufficient oversight (in the cost area
discussed above, for example). Recent corporate governance scandals in
this and other industries point out the need to avoid boards that are too
dependent on management and staff, without independent knowledge
of what is happening "on the ground," both within their own RTO
organization and in the RTO's region.
This lack of RTO accountability to customers and stakeholders creates the
~~~idely held view that RTOs have only one dominant stakeholder-.FERC.
This perception is damaging to the credibility of both FERC and the
respective RTOs. To allay this problem, FERC and the RTOs must take
steps to promote an atmosphere of mutual respect and constructive
relations between RTOs and the industry participants that must deal
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 17
with [here. RTO management and boards cannot be subsen~ient to
industry particip~mts, but the}' should not be. able to simply- ignore
them. FEKC must also take steps to vigorously regulate RTOs as the
regional monopolies they have become, to ensure that they meet their
responsibilities to industry' participants and electric consumers.
RTO Regions Should Make Sense from a
Commercial and Reliability Perspective
PERC should reject choices by TOs to join RTOs when such choices arc
likely to increase costs to public po~~~er systems and other market participants
or decrease reliability in the region. Iy~Iany r~PPA members have been
dismayed by the "crazy quilt" geographic configurations PP.RC has
approved for their RTOs. Rather than joining t}ie RTO that makes
Rather than joining the
RTO that makes the
mosf sense from a
market and reliability
perspective, some FERC-
jurisdictional TOs have
t d th
tl~~e most sense from a market. and reliability perspective, some
PERCjurisdicrional TOs hay°e insisted on joining those RTOs that
fit best ~~-ith their own corporate goals and philosophies, creating
jagged RTO-to-RTO "learns." These learns raise the costs of affected
RTOs and market participants, as they-~ have to make additional
business judgments and investments to compensate for less-than-
opti~nal regional configurations.
msis a on ~ammg ose
RTOS that fit best with worse }'et, such decisions can have a "ripple effect." For example,
their OWn Corporate Borne IOU transmission providers are no~~~ proposing to reform the
goals and phllOSOphIBS, horde°rs of their current Regional Reliability Councils to better tit
Creating jagged RTO-to- ~~ith the RTO membership decisions their various subsidiaries have
RTO "Seams." made. Reliability concerns should trump the corporate inter°ests of
individual R7'O members, not rice versa.
The Bottom .Line: RTOs Should Be a Boon to
Electric Consumers, Not a Drag on Them
Pot residential electric consumers, RTOs arc a pocketbook issue,
although rite vast majority of them do not realize it. Pot industrial and
commercial customers, RTO polio- is a vital economic issue that could
make the difference bet~~,een being profitable (thus staying in business),
and shutting do~ti~n operations or leaving the community. Reliable,
reasonably priced electric service is a national economic development
and jobs issue. APPt~ members in KTO regions are deeply concerned
about RTO cost and service issues because they directly impact the
economies of their local communities.
18 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
Somewhere along the RTO-development road, the original business
purposes oCR"I'Os that FI?RC envisioned (to provide non-discriminatory
transmission service, eliminate transmission rate pancaking,
It iS tIInB t0 reOrlentRTOS ~ and provide a vehicle for joint planning and construction
towards their original miSSion• of transmission facilities-a11 for the benefit of electric
.providing adequate;. reliable.. consumers) morphed into a different mission and agenda.
Today, the "business" of RTOs appears to be to develop
and reasonably`priced regional
markets for every possible product, whether or not such
tranSRIISSion Service t0 bring markets are necessary, competitive and cost-effective, and
COSt SBVIngS tOCOnSllmerS. to serve the needs and desires of regulators and preferred
classes of stakeholders, rather than electric consumers. It is
time to reorient R"TOs towards their original mission: pro~nding adequate,
reliable and reasonably priced regional transmission service to bring cost
savings to consumers.
Ways to Advance Transmission Policv
Goals in Regions Without RTOs T
Because of regional differences, and the largely negative experiences
of their counterparts in RTO regions, many r1PPA members oppose
thc° expansion of RTOs to their own regions. The problems created by
the formation of RTOs have proven to be more significant than Ilrst
anticipated and the benefits have proven to be more elusive. These APPA
members believe there are more cost-effective means to provide open
access transmission and promote market efficiency in their regions.
F>/RC should abandon its "RTO-or nothing" approach to transmission
policy. Regional initiatives that enhance the efficiency of markets with
minimal added cost and risk should be encouraged and supported,
not discarded as inconsistent with FERC's SAID template. Regional
differences are real and have to be respected. Solutions tailored to
the needs of each region should be pursued that meet the goals set
forth in the Introduction to this ~~'IIITE I'.1PER.
FF.RC must also fully appreciate the deep and abiding concerns that
public power systems, especially those in the West, have about electric.
restructuring and RTO formation in the wake of the meltdown of
~~~'estern power markets in 2000. Many public po~~~er s}~stems are
skeptical that FLRC has the ability or the will to move quickly and
effectively to address abuses of market power, and protect consumers
froru paying unjust and unreasonable rates (or even to make them
whole later). Until these past problems are meaningfully resolved,
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 19
and FERC sho~ti~s that it will in the ft.it_ttre act aggressiveh~ to fulfill its
FPA responsibilities, it will be ver~~ dif{icul~ to "mope fast the past.."
!Many public po~~~~er systems in tl~e West feel like tltcv have lived in a
restructuring Puri dish for the ~>ast sc~°eral years, and they have little
appetite for nc~~~ experiments.
Regional Practices and Institutions that Meet the
Needs of Particular Regions Should Be Encouraged
In some regions without R~I~Os, cost-effective improvements have been
made to f~3cilitate the reservation and scheduling of transmission and to
encourage a more active secondary marker. For example, under public
power leadership, t~~~enty public power and investor-owned entities in the
West have jointlti~ developed the wesT~I'rans.net Open Access Same-time
Information System ("0:1SIS") site. Prospective transmission customers
can submit one electronic query to this OASIS for transmission service
o~°er multiple U-ansmission s~~stems. Innovations such as these enjoy
widespread support, not onh~ among non-jurisdictional utilities but also
among man}' rnerchanrs and IOUs doing business in the region. i\larket
monitoring is another function that entities are exploring for provision on
a regional bads, even without an RTO. If such practical, least-cost
Many APPA members initiatives can replicate benefits that an RTO is supposed to
belleVe that emphasis provide at substantially less cost than a "traditional° RTO, then
these outcomes may well be superior for that region. Rather
on regional transmission
than condemning such regional efforts as "inferior" to the
planning and expansion,
outcomes under a full-0edged RTO reg~irne, these efforts should
Without the COmpllCatlOnS be fostered, and similar efforts in other areas encouraged.
introduced by RTOs, is
a preferable strategy for Open Regional Transmission Planning Is Critical
making cost-effective And Can Be Accomplished Without an RTO
improvements In the h1an~~ APPA members believe that emphasis on regional
adequacy and reliability transmission planning and expansion, without the complications
Of t~anSI111SSlon. introduced by RTOs, is a preferable strategy I~or maki~ig cost-
effective improvements in the adequacy and reliability of
transmission. In non-RTO regions, AYPA members (as well as many
jurisdictional utilities) retain the obligation to serge, ~1hich provides
a strong incentive to plan for and ingest in transmission necessary to rnect
t}ieir needs. This planning must be inclusive and meet the needs of all
utilities serving load on a comparable basis.
The y~1'estern Interconnection provides an example of an approach to
transmission planning that pre-dates RTOs, transcends RTO boundaries
20 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
and encourages participation by jurisdictional and non jurisdictional
entities alike. Four sub-regional planning efforts,~`~ each with participation
by both jurisdictional and non-jurisdictional entities, have been established
to address the transmission expansion needs of the Interconnection.
Recently, the bylaws of the ~~Vestcrn Electricity Coordinating Council
("~YT.CC') have been amended to permit it to coordinate planning efforts
~~ithin the entire interconnection. In addition, the ~1~estern Governors'
Association has sponsored an assessment of transmission needs, and the
member Governors, along with several federal agencies, have executed
an interstate siting memorandum of understanding.20
The longer term goal must be an inclusive regional transmission planning
and construction process, in which all affected ~-cholesale market. participants
and state authorities participate. In the absence of an R"I'O, a regional
platform or forum must carry out this function, as t1%ECC is now
If the responSlblllty for. tmdertaking for the ~~'est. These regional planning processes should
bUllding and OWDIng bc= tailored to the needs, preferences and characteristics of each
the tranSrgISS1011 grid region, so that those in the region have confidence in both the
process and its results.
is spread more broadly
among entities serving
loads in a region, then Joint Ownership of Generation and Transmission
Reduces the Need for RTOs and Should Be Encouraged
joint transmission
plannlpg WIII likely be J°int ownership of transmission addresses many of the issues that
RTOs were intended to address. Proportional ownership is an
facilitated, simply . .
effective means to rnrtrgate the transmission market po~~~er of
because there are incumbent FL,RC jurisdiction~:tl utilities ~~•here this is a pressing
morepartlclpantS at policy concern. If the responsibility for building and owning the
the planning table. transmission grid is spread more broadly among entities serving
loads in a region, then joint transmission planning will likely be
facilitated, simply because there are more participants at the planning
table. If °`nettivork integration transmission service" ("nets-vork") customers
are encouraged to "bu~~ in" to their load ratio share of the transmission
system, transmission usage and ownership will be more closely aligned,
and the historical frictions between transmission-dependent utilities and
19 'These groups include the Southwest 'Ii~ansmission Expansion Planning Group,
the Southwest Arizona "Iransmission Study Grc,up, the Northwest TranSITLISSIOI]
Assessment Committee, and the Rocky 1~lountain Area "Transmission Study.
~~ Zb underscore the importance of regional differences, federal land ownership
is a greater barrier ro interstate transmission projects in the ~ti'est than is
rejection oCa project by an individual state siting authority.
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 21
their TOs can be o~°ercome. f Dint o~~~ncrship would also better promote
the policy goal of adequate transmission infrastructure to support long-
term power supplies needed Co assure adequate and reasonable priced
electric sere-ice to all consumers, regardless of what type oCk~ad-serving
utility supplies chem.
Joint generation ownership also helps limit market powcr.21 If, For
example, five different owners hold an interest in a major generating
facility and have transmission rights terminating at a commercially
significant market hub, the market poi,°er of each party at chat hub is
reduced. A party ~~~ishing to reserve. long-term transmission capacity then
has the option of dealing with five counterparties, rather than being
req~,~ired [o live tcith ~1~hatever 1'TFLs it can obtain from an KTO. If coupled
~~-ith a regional Or1SlS in ~~~~hich all the interest holders participate (such
as the wes7"IYans.net OASIti), and a regional Cransmission planning regime,
such a decentralized svsten~ could provide many of the benefits of RTOs,
at much less cost.
Another advantage of ajoint-ownership model compared to the RTO
rnodcl is that it preserves the link between the ol~>ligation to serve and the
responsibility to invest.. ~~1~hen a retail service provider has die responsibilit~~
for securing sufficient resources to serve its load, it also takes on the
responsibility for assuring that the resot_u~ces can be delivered. Fulfilling
this responsibility could involve participation in a transmission system
expansion or entering into a transmission contract .with a term that
matches the resource commitment.
There arc many examples in RTC) and non-RTO regions of joint
transmission expansion efforts and groups established to jointly own
transmission facilities nn behalf of several smaller retail ser~~ce providers. `'2
21 ryI'P~~ notes that puI>]ic power joint generation projects in the ~ti'est have a
long history of success, e.g., the Intermountain Power Project. Public poker
systems are joint owners of over 20,000 '~1~ti' of coal, h}'dro-electric, nuclear
and gas-fired poker capacity throughout the United States. Our co-owners
include over 40 different investor-o"ned utilities, cooperatives, and
independent poker producers, as well as nurrierous other public power
systems. Specific examples include the Palo Verde (A'7,), IVlillstone 2 (CT),
and Crystal River 3 (FL) nude°ar plants, the Rodemacher 2 (l.A) and Trimble
County 1 (Ky~ coal plants, and the: i~4cClain (Oh) and South Fond du Lac
(\1%1) gas-Tired plants.
22 Joint o~cnership of specific transmission lines by public power utilities and
other parties is widespread in the weste°rn United States. In addition, public
22 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
In addition, some entities are discussing "buy in" to existing regional
transmission networks. Such responsible and innovative approaches to
securing adequate transfer capability should be supported arrd encouraged
as viable alternatives to RTOs.
FERC Enjoys Significant Authority to Address Remaining
Discrimination under the Current Order No. 888 GATT Regime
Under Order No. 838's GATT regime, FERC jurisdictional TOs are
obligated to provide transmission service on anon-discriminatory basis.
There are undoubtedly some instances where residual discrimination
still exists. Such discrimination can be addressed effectively, without
the complications that RTOs introduce, by focusing on clarifying and
enforcing open access rules.
With its shift in emphasis away from the Order No. 888 OAT'T
FERC Should undertake ~ regime in favor of RTO activities, FERC has relegated improvements
a ComprehenSlVe look to ir^s open access rules to case-by-case adjudication. FERC should
at Ways ItS Open undertake a comprehensive look at wa)s its open access regime
aCC@SS regime COUId could be improved through clearer Hiles or changes to improve
be ImprOVed through efficiency.2~ For example, lack of clarity or specificity with respect
to calculation and posting of A~°ailable Transmission Capacity
ClearerruleSOrChangBS ("ATC') has led to concerns by some APPA members about
t0 Improve efflClency. manipulation of ATC calculations. To date, FERC has chosen to
address these issues primarily on a case-by-case basis, rather than
making and enforcing rule changes to assure that calculations are
auditable and transparent. Similarly, protocols for processing transmission
reservation queues and procedures regarding the exercise of rollover
rights could use a fresh look.
(~oolnote continued fror7a ~ireaious gage)
power utilities jointly o~~n u-ansmission networks in states such as Georgia,
?Llichigan, Indiana, and iVlinnesota. Iu Vermont, the bulk transmission
system is jointly owned b}' rrr~rnicipal, cooperative, and investor-owned
utilities through Vermont F..lectric Transmission Company. In Wisconsin,
public power systems are permitted to invest up to their load ratio share
in ATC. See n. 1? above.
23 FERC Cornrnissioner Joseph Kelliher has suggested that Fl?KC consider
strengthening its Order No. 888 transmission rule, and that it review claims
of discrimination under that regime. "With RTO llevelopment Stalled, FERC
Shorild Beef Up Order 888, Kelliher Suggests," I~resideFERC, August 23, 2004,
at 1; "Kelliher: Eliminate Flaws in Open-Access Rule," Electric PouierDail~~,
Septernbcr 29, 2004, at 3.
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 23
FERC Should Address the Concerns
Of Network Service Customers
The O ~T~IS of FERC jurisdictional TOs require them Lo plan for the
transmission needs of their net~~~~rk customers. Some O_~'I~"h net~~cork
customers, however, belie~~e that. their loads and resources have not been
treated equitably or °comparat~rl}~" to those of their TOs in transmission
panning and facilities construction. y~1`hile net~~~ork customers pay their
load ratio st-rare of u-ansrnission system costs, they can be put. on the
"margin" by their FERC:-jurisdictional TOs ~~-hen it comes to transmission
planning. Some have been told thtiy must pay the Iirll cost of all additional
transmission facilities nc°edcd to connect their new resources or to serve
their increased loads, even when they believe that the TO's own loads ~~~~ould
very likely benefit. from such facilities as well The joint transmission
planning that network customers had hoped would carne Keith the Ordc°r
No. 888 0.~1TT has not materialized. Similarly, generation developers have
had difficulty gaining access to the u,ansrnission system in some
regions, and in traving their generation projects designated as
FERC Could do much to assure ntit~~~ork resources.
adequate transmission infra-
structure development in non- FERC could do mach w assrirc adequate transmission
RTU reJI011S Of the COUntry infrastructure development in non-R"I'O regions of the
merely byvlgorouSly enforcing country n~~erely by eigorousle enforcing the joint planning
the joint planning and and transmission constrt.iction obligations FERC-jurisdictional
transmi$sion ConstruCt1011 `IOs have under their o~an existing OATTs. In so doing,
obligations FERC-jurisdictional FF,RC could promote the concept of joint participation in
TOS have under thelrOwn transmission systems and construction projects by both 'I'Os
eXlSting OATTS. and their net~~~ork service custorncrs on a proportional basis,
to reduce the capital outlays required by FERC-jurisdictional
TOs, and to make transmission o~,~nersl-rip more broadly
available to load-stirring utilities in these regions. Such joint. participation
in transmission system and facilities ownership is a logical extension of
FERC's current transmission system cost-allocation method, under which
neu~-ark service customers ah-tiadl' pay their load ratio share of their TO's
fixed transmission system costs, day after day, year after year.
24 Restructuring at the Crossroads: FERC Electric Policy Reconsidered
Generation Market Power Must Be Addressed
Through a New Market-Based Rate Policy
1~1any small AP PA members are facing very serious threats to their viability-
because of lack of availability of long-term Grm transmission and increasing
generation consolidation. These systems get few if any bids from suppliers,
are often unable to obtain transmission to reach alternative
Many Small APPA IrIe111herS ~ sources of power, and are Laced with dramatic increases from
are facing very serious local suppliers ~~~ith significant market power.
threats to their viability
~'PA member experience demonstrates that merely imposing
beCause~Of IaCk Of "global" generic conditions (st.ich as RTO participation)
avallablllty Of long-term on market-based rate authorizations may have substantial
firm tranSmlSSlonand unintended consequences. require years to put in place,
IncreaSing generatlon and may or may not address the underlying problems (e.g.,
COnS011dat10n, generation market dominance compounded by a dearth of
long-term firm transmission capacity to obtain access to
competitive suppliers). Lack of competitive conditions must be addressed
through a nc~~- market-based rate policy that ensuresjust and reasonable
wholesale rates at all times.`"i
FF.RC's KTO policy, as well as its market-based rate policy, assumes that
competitive markets (supplemented in KTO regions by RTO market
monitoring and mitigation regimes) will produccjust and reasonable
rates. In man}~ real-world instances, this has proven not Co be the case.
On a purely practical level, if the prices for power in "competitive"
rnarkcts (either RTO-run or bilateral) exceed for sustained periods the
costs E~or po~~~er that tivould have resulted under a traditional cost-of-
service regime, this disparity will eventually bring calls for a return to
traditional cost-of~-service regulation Ior electric generation. For these
reasons, FERC must undertake a "bottom up" review and update of its
market-based rate policy, as it applies both in RIO and non-KTO regions.
I-fowever, this "bottom up" re~~iew must not bccorne a pretext t.o delay FLRC
actions needed to address generation and transmission market power
problems on a local or company-specific basis. Public power utilities
participate in many different local and regional energy markets, most of
which are flawed at best. ~~~'here these wholesale markets arc not competitive,
2~ Stale of Cc~lijornirc, ex reG Bill Lnckyerv. FLPC, 383 F.3d 100G (9'° Cir. 200-0
(rehearing and rehearing en bane sought October 2~, 2004) (FERC has
continuing obligation under its market-based rate regime to ensure that.
rates remain just and reasonable).
Restructuring at the Crossroads: FERC Electric Policy Reconsidered 25
Fh:RC must adopt enforceable protective conditions on the market-based rare
authorizations of specific public unlit}' sellers. Such conditions should include
the imposition oh cost-based rates and conditions circumscribing the conduct
of individual market participants, if such conditions are needed to ensure that
~rholesale rates are just and reasonable and nor unduly discriminator~~ or
preferential. Reliance on cost-based rates ensures that ~~~holesale rates will
remain ~~~ithin a zone of reasonableness. ~~lternativc conditions can also be
crafted, but above a11, conditions must be targeted at the specific market
po~~~er problems identified in the local area or region, be achievable within
a reasonable period oI~ time, and be enforceable by both
The abilityof FERC-[egulated FERC and the affected entities.
public utilities t0 sell power 8t 'hhe ability of FERGregulated public utilities ro sell po~ti~er at
market-based rates under the market-based rates under the FY.-~ is a privilege, not a right.
FPA is a privilege, not a right. Iris not [~ ERC's mission to ensure that its market-based rare
mgime benefits the sellers (and the Fnancial institutions that
ha~~e lent money to them). Instead, FERCs marker-based rare policies must
benefit consumers and their cormnunities by ensuring they are charged on1~~
`just and reasonable" rates, as Congress intended ~~~hen it enacted the FY,a.
Conclusion
PP~1 and its members arc not advocating the dismantling of each of
Attie FERGjurisdictional RTOs now in place.:~or are they advocating
the formation of additional KTOs. Rather, they seek to reform the
existing R~I~Os, so char they operate to benefit elecu-ic consumers (rather
than particular industry participants), and employ market mechanisms
only as a means to an end (serving electric consumers), and not an end
in themselves. In regions without R"1'Os, ~1PPr1 and its members urge
polic~~nzakers to recognize important regional differences and to support.
initiatives that promise to deliver substantial regional benefits in areas
Stich as transmission planning and construction, market monitoring, and
O:~SIS administration. FI/RC should also take steps in regions ~~~ithout
RTOs to clarify and enforce open access transmission ntles to ensure that
FERCjurisdictional transmission providers are indeed carrying out their
obligations to transmission custorncrs. Finally, FhRC must revamp its rnarker-
based rate polio' to ensure that electric consumers in both RTO and non-
RTO regions pay only just and reasonable rates for electric generation.
26 Restructuring at the Crossroads: FERC Electric Policy Reconsidered