[Federal Register: May 8, 2003 (Volume 68, Number 89)]
[Proposed Rules]
[Page 24679-24689]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr08my03-20]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM01-12-000]
Remedying Undue Discrimination Through Open Access Transmission
Service and Standard Electricity Market Design
April 28, 2003.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Proposed rule; Notice of white paper and request for comments.
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SUMMARY: On July 31, 2002, the Commission issued a Notice of Proposed
Rulemaking (NOPR) in the above-captioned docket, proposing to amend its
regulations to remedy undue discrimination through open access
transmission service and standard electricity market design. See 67 FR
55452 (Aug. 29, 2002). The Commission has distributed a white paper to
set forth its assessment of how the electric industry should move
forward to achieve long-term benefits for electricity customers, and
how it intends to change the rule proposed in the above docket on July
31, 2002, to meet the concerns that have been raised in rulemaking
comments. The Commission welcomes public comment on this document.
DATES: Comments are welcome at any time.
ADDRESSES: Send comments to: Office of the Secretary, Federal Energy
Regulatory Commission, 888 First Street, NE., Washington, DC 20426.
FOR FURTHER INFORMATION CONTACT:
Alice Fernandez (Technical Information), Office of Markets, Tariffs and
Rates, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8284.
David Mead (Technical Information), Office of Markets, Tariffs and
Rates, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8028.
Mark Hegerle (Technical Information), Office of Markets, Tariffs and
Rates, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8287.
David Withnell (Legal Information), Office of General Counsel, Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426, (202) 502-8421.
[[Page 24680]]
SUPPLEMENTARY INFORMATION: In addition to publishing the full text of
this document in the Federal Register, the Commission provides all
interested persons an opportunity to view and/or print the contents of
this document via the Internet through FERC's Home Page (http://www.ferc.gov
) and in FERC's Public Reference Room during normal
business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street,
NE., Washington, DC 20426.
Today the Commission is publishing a White Paper to set forth its
assessment of how the electric utility industry should move forward to
achieve long-term benefits for electricity customers, and how it
intends to change the rule proposed in the above docket on July 31,
2002, to meet the concerns that have been raised in rulemaking
comments.
The White Paper is being placed in the record of this rulemaking
docket. It will also be available on the Commission's Web site at
http://www.ferc.gov/Electric/RTO/mrkt-strct-comments/discussion_paper.htm
.
The Commission welcomes public comment on this document. All
comments will be available for review at the Commission or may be
viewed on the Commission's Web site at http://www.ferc.gov, using the
``FERRIS'' link. Enter the docket number excluding the last three
digits in the docket number field to access the document. For
assistance, contact FERC Online Support at FERCOnlineSupport@ferc.gov
or toll-free at (866) 208-3676, or for TTY, contact (202) 502-8659.
Comments may be filed electronically via the Internet in lieu of paper;
see 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's
Web site under the ``e-Filing'' link. The Commission strongly
encourages electronic filings.
The Commission also intends to begin holding regional technical
conferences in the near future, to discuss with states and market
participants in each region reasonable timetables for addressing
wholesale market design issues discussed in the White Paper and ways to
tailor the Commission's final rule to benefit customers within the
region. We will issue notices of the conferences shortly.
By direction of the Commission.
Magalie R. Salas,
Secretary.
White Paper; Wholesale Power Market Platform
The Federal Energy Regulatory Commission's core mission under the
Federal Power Act is to achieve wholesale electricity markets that
produce just and reasonable prices and work for customers. The
Commission's July 2002 proposal to harmonize wholesale power markets
sought to advance this core mission in the context of the new realities
of regional electricity markets.\1\
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\1\ Notice of Proposed Rulemaking, Docket No. RM01-12-000,
issued July 31, 2002.
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The industry has been evolving toward a market-based approach for
well over a decade and active long-term wholesale bilateral markets
exist in all regions of the country. However, short-term wholesale
markets with transparent prices and market structures that will
reliably produce just and reasonable prices are not likely to develop
without strong Commission action. Wholesale electricity markets do not
automatically structure themselves with fair behavioral rules, provide
a level playing field for market participants, effectively monitor
themselves, check the influence of market power, mitigate prices that
are unlawful, or fix themselves when broken. These are the
responsibilities of the Commission under current law, and our proposal
was made with these responsibilities in mind.
Our proposal was informed by the experiences of this country and
other countries in electric market design, including the effects of
supply shortages, demand that does not respond to high prices, lack of
price transparency in the marketplace, and the importance of market
monitoring and market power mitigation. Based on the extensive comments
we have received during the past nine months, we are issuing this White
Paper to set forth our assessment of how best to move forward in the
electric industry for the long-term benefit of electricity customers,
and how we intend to change our proposed rule to meet the concerns that
have been raised.
Our goals continue to be reliable, reasonably priced electric
service for all customers; sufficient electric infrastructure;
transparent markets with fair rules for all market participants;
stability and regulatory certainty for customers, the electric power
industry, and investors; technological innovation; and efficient use of
the nation's resources. Further, providing regulatory certainty for the
industry and investors in order to build needed infrastructure is a
critical need facing the energy industry and requires Commission
action.
Under the Final Rule, we intend to focus on the formation of
regional transmission organizations (RTOs) and on ensuring that all
RTOs and independent system operators (ISOs) have good wholesale market
rules in place.\2\ We will eliminate the proposed requirement that
public utilities create or join an Independent Transmission Provider.
Instead, in light of the fact that almost all public utilities already
have joined, or committed to join, an RTO or ISO, the Final Rule will
require public utilities to join an RTO or ISO.\3\ Further, we intend
to adopt a Final Rule that allows for phased-in implementation and
sequencing tailored to each region and that allows modifications to
benefit customers within each region. In addition, if for a specific
RTO or ISO it can be demonstrated to the Commission that the costs of
implementing any feature of the market platform outweigh its benefits,
the Commission will not require implementation of the feature for that
particular RTO or ISO.\4\
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\2\ For the purposes of the Final Rule, all of the
characteristics and functions for RTOs would apply to Independent
System Operators (ISOs), except for scope and regional
configuration.
\3\ The requirements of the Final Rule will not apply to
Commission-jurisdictional electric power cooperatives that serve
only retail load.
\4\ We intend to commence technical conferences in each region
and to work with states and market participants to develop
reasonable timetables for moving forward.
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For the basic wholesale market platform, we intend to build upon
the existing rules adopted in Order No. 2000 for RTOs by adding
features that we have learned are necessary for effective wholesale
power markets.\5\ For example, Order No. 2000 did not include market
power mitigation measures and does not prevent flawed market designs.
Wholesale electric markets will not be able to deliver full customer
benefits in the future without the oversight and transparency that
regional independent transmission organizations can provide. Healthy
and well-functioning wholesale power markets are central to the
national economy, and we believe that regional, independent operation
of the transmission system, with proven market rules in place, is the
critical platform for the future success of electric markets.
Divestiture is not required to achieve independent operation of the
transmission system. Companies may remain vertically integrated under
an RTO or ISO.
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\5\ Details of the wholesale power market platform and a
comparison of them to the requirements of Order No. 2000 are
included in Appendix A.
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In the years since Congress enacted the Energy Policy Act of 1992,
competition among power plants for wholesale customers' business has
largely replaced traditional cost-of-service regulation of wholesale
power sales. The Department of Energy found
[[Page 24681]]
that relying more on markets has saved customers $13 billion per year
over traditional regulation. It has stimulated innovation in generation
and transmission technologies. It has freed customers from being forced
to pay for the ``stranded costs'' of unwise investments. This
competitive market framework came about as a result of national
legislation and a series of Commission initiatives in both the
wholesale gas and electric industries. In particular, these actions
were intended to provide all wholesale power sellers with equal access
to the transmission grid. Equal, nondiscriminatory access is a
necessary prerequisite for fair competition among sellers, and,
together with regional operation of the grid, gives wholesale buyers
access to a much wider range of supply choices.
The transition to restructured markets has not been smooth or
uniform. In regions with an effective wholesale market platform, an ISO
or RTO provides effective market monitoring and has clear market rules
designed to protect customers. Some markets, however, clearly have not
been immune from market design flaws. Experiences in California have
shown the consequences of poorly designed markets and inadequate
generation, transmission and demand response. Moreover, they
demonstrate the need for before-the-fact market power mitigation and
ongoing market monitoring. Some areas also have experienced ``seams''
problems where differences in design between regions create artificial
barriers to trade which raise costs, limit customer supply choices, and
create opportunities for exploitation of differences between markets.
In other areas of the country, where markets do not have
independent or regional grid operation, the lack of price transparency
in the marketplace can mask problems and transmission operators can use
their ability to control the transmission system to favor their own
power sales. New competitors may be blocked or delayed because the
transmission operator can favor its affiliated suppliers both in
interconnecting to the grid and in allocating the costs of
interconnection. The result of these problems is higher customer costs,
making independence a critical element for protecting native load.
Dealing with these issues and concerns on a case-by-case basis takes
significant time and effort for both the Commission and market
participants to resolve.
In the proposed rule, the Commission identified the building blocks
for a healthy wholesale market to address the problems we have
experienced in both competitive and non-competitive markets. In moving
forward on a Final Rule, we believe it is critical to retain certain
fundamental building blocks for healthy electric markets, and we agree
with commenters that regional economic differences and regional timing
constraints must be recognized. Below we identify market issues that
lend themselves to regional solutions without compromising the
integrity of a solid market platform.
The Commission is aware that the success of our RTO-based
initiative is more likely in a region where the bulk of the
transmission grid is in the hands of jurisdictional public utilities.
But in the Pacific Northwest, roughly 80 percent of the grid assets are
controlled by the Bonneville Power Administration, which is not a
public utility under the Federal Power Act. Bonneville's participation
in RTO West is essential for RTO West to succeed. Thus, we encourage
Bonneville's continued voluntary participation in RTO West. We are also
aware that Bonneville will continue to participate only if RTO West has
the flexibility to meet the unique needs of the Pacific Northwest. We
clarify what may be obvious. Any decision of Bonneville to meet its
obligations and operational responsibilities with respect to such
matters as irrigation, flood control, treaties, environmental rules and
the like is solely Bonneville's to make and is not jurisdictional to
the Commission. While the Commission has limited jurisdiction over
Bonneville's rates under the Pacific Northwest Electric Power Planning
and Conservation Act, the contracts between Bonneville and its
customers do not require Commission review or approval. We have heard
the concerns expressed about the merits of locational pricing and a day
ahead market in a region dominated by interdependent hydroelectric
resources. With respect to these concerns, our commitment is to work
with interested parties, including state commissions, to find solutions
that are appropriate to the unique needs of the Pacific Northwest.
The Commission will consider all comments received on this White
Paper, as well as any pending electricity legislation being considered
in the U.S. Congress, prior to issuing a Final Rule.
Comments on the Proposed Rule
A number of concerns have been raised about various aspects of the
proposed rule. We have received approximately 1,000 sets of formal
comments on our proposed rule. The most extensive concerns involved the
following issues. We state these concerns and our responses below:
[sbull] The Commission proposed to assert jurisdiction over
transmission used to provide retail service to native load customers.
Pursuant to Order No. 888, the Commission currently asserts
jurisdiction over wholesale transmission service and unbundled retail
transmission service by public utilities. In the Final Rule, with
respect to bundled retail service, we will continue our existing
practice for RTOs and ISOs of distinguishing between the non-price
terms and conditions of transmission service and the rates for
transmission service. As discussed in Appendix A, the non-price terms
and conditions of the RTO or ISO tariff will apply equally to all
users, including those taking service to meet their obligation to serve
bundled retail customers. However, the Commission will not assert
jurisdiction over the transmission rate component of bundled retail
service, thereby avoiding unintended issues raised by a new assertion
of jurisdiction.
[sbull] Specific features of the proposed rule, particularly the
resource adequacy requirement and the regional transmission planning
requirement, infringe on state jurisdiction.
The Commission clarifies that nothing in the Final Rule will change
state authority over these matters. We will not include a minimum level
of resource adequacy. The RTO or ISO may implement a resource adequacy
program only where a state (or states) asks it to do so, or where a
state does not act. The Final Rule will direct RTOs and ISOs to develop
a periodic regional transmission plan for submission to relevant state
and local siting authorities and to assist the states in whatever
manner they desire, including evaluating the impact of new generation,
transmission, energy efficiency, and demand response on regional
reliability and resource adequacy.
[sbull] The transition process to the new proposed transmission
service would not provide sufficient protection for existing customers.
As with our earlier restructuring efforts in the natural gas and
electric power industries, we want to ensure that existing customers
retain their existing transmission rights and retain rights for future
load growth. While all customers that pay a basic access charge can
schedule transmission service, it is important that customers be able
to protect themselves from congestion costs through Firm Transmission
Rights (FTRs). The Final Rule will eliminate any requirement that FTRs
be auctioned. We will, instead, look to
[[Page 24682]]
regional state committees to determine how such rights should be
allocated to current customers based on current uses of the grid.
Varying approaches to FTR allocation need not create ``seams'' with
neighboring regions.
[sbull] The proposed rule was too prescriptive in substance and in
implementation timetable, and did not sufficiently accommodate regional
differences.
As discussed above, we intend to adopt a Final Rule that allows for
phased-in implementation and sequencing tailored to each region and
that allows modifications to benefit customers within each region. To
the extent that it can be demonstrated to the Commission that the costs
of implementing any feature of the Final Rule outweigh its benefits,
the Commission will not require the RTO or ISO to implement that
feature. Before issuing a Final Rule, we intend to convene technical
conferences with state commissioners and market participants in each
region to discuss which aspects of the platform (if any) have not
already been addressed and the timeline, sequence and budget for moving
forward.\6\ Also, as discussed in Appendix A, each RTO or ISO would
provide a forum for state representatives to participate in the RTO's
or ISO's decisionmaking process. That forum is referred to as the
regional state committee.
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\6\ To avoid the reliability and operational problems that
result when some parts of the grid do not participate in RTO or ISO
functions, we strongly encourage regional decision-making on RTO or
ISO implementation through regional state committees, stakeholder
committees, and other authorities in the region.
[sbull] The proposed rule did not provide sufficient clarity on
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cost recovery for investment in new transmission facilities.
Each RTO or ISO will be required to have a clear transmission cost
recovery policy outlined in its tariff. We will look to the RTO or ISO
and the regional state committee to determine the appropriate regional
approach for allocating the costs of new transmission. Regions may
differ on the extent to which they want to rely on participant funded
expansions; this difference need not create ``seams'' with neighboring
regions. Because this issue is such an important one in stimulating
appropriate investment by both existing and new transmission companies,
we will allow an RTO or ISO to implement such policies once there is a
regional planning process through which an independent entity performs
all necessary facilities studies and determines cost responsibility for
the required transmission upgrades.\7\
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\7\ In Appendix A, we explain that allowing participant funding
on the basis of having an independent entity perform transmission
planning and related cost allocation is a transitional approach that
could be used in anticipation of the RTO or ISO assuming operational
control of the regional transmission grid within one year.
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Wholesale Market Platform
The Commission believes that certain elements need to be in place
for well-functioning wholesale markets.
Regional Independent Grid Operation
Order No. 2000 required that all RTOs meet four minimum
characteristics: independence, scope and regional configuration,
operational authority, and short-term reliability. The Final Rule will
reaffirm the need for these characteristics. In particular, the lack of
independence continues to plague electricity markets because it
provides an incentive for those who own generation and operate
transmission facilities to operate the transmission system in ways that
exclude competing generation suppliers and can allow the exercise of
market power. This conflict of interest cannot be remedied through
oversight and enforcement. Rather, structural separation of
transmission operation from other wholesale market activities is
required to eliminate the ability for such manipulation.
Regional operation is critical for both reliability and efficiency
because power flows freely throughout regional grids. Order No. 2000
said ``the scope and configuration of the regions in which the RTOs are
to operate will significantly affect how well they will be able to
achieve the necessary regulatory, reliability, operational and
competitive benefits.'' However, in the Final Rule we will allow
flexibility on scope and configuration for ISOs. RTOs and ISOs are
developing methods of interregional coordination that allow separate
control, but a single market from the customer's perspective.
Therefore, in the Final Rule we will not require ISOs to meet the scope
and regional configuration requirement. However, all must actively
pursue interregional coordination between RTOs and ISOs, including the
elimination of the payment of multiple access fees for transactions
that cross ISO and RTO borders.
Order No. 2000 required that the RTO be the sole provider of
transmission service and sole administrator of its own open access
tariff. Included in this is the requirement that the RTO have the sole
authority for the evaluation and approval of all requests for
transmission service including requests for new interconnections. The
Final Rule will reaffirm these requirements.
Regional Transmission Planning Process
Regional planning of the transmission grid is essential to ensure
the most effective use of the interconnected grid facilities. The RTO
or ISO is in a unique position to discern regional needs and address
factors inhibiting investment in transmission and generation through
conducting a region-wide planning process. As required in Order No.
2000, the Final Rule will require the RTO or ISO to produce technical
assessments of the regional grid and support the state siting
authorities or multi-state entities by performing necessary studies.
The purpose is to assist the states and market participants by giving
an independent assessment of the transmission facilities needed by the
region to reliably and economically serve load located within the
region. How the RTO or ISO, state commissions, transmission owners, and
other market participants participate in the process will be decided
regionally. By administering the regional tariff, RTOs and ISOs also
provide the critical link to a cost recovery mechanism for regional
transmission expansions. The Final Rule would require RTOs and ISOs to
have a regional planning process in place as soon as practicable.
Fair Cost Allocation for Existing and New Transmission
The costs associated with the existing grid, other than those
directly assigned, will continue to be recovered through rates paid by
customers. To avoid having customers pay multiple, cumulative charges
for transmission service across multiple utility grids in a region, the
rate paid by a customer should permit that customer to have access to
the entire region at a single rate. As discussed in Appendix A,
regional state committees may agree on the form of access charge that
will be filed by the RTO or ISO under section 205 of the Federal Power
Act. That means the committee will decide whether to propose to move to
a uniform rate for transmission service throughout the region (known as
postage stamp rates), or whether to propose to maintain single, but
different access charges depending on where power is taken off the grid
(known as license plate rates).\8\
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\8\ Under license plate rates, the single access charge is
usually based on each transmission owners' service area.
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[[Page 24683]]
To gain access to a wider range of supply choices, RTOs and ISOs
should eliminate the payment of multiple access fees across RTO and ISO
borders. Rate mechanisms to minimize cost shifts should be used. If
there is a notable imbalance between imports to and exports from an RTO
or ISO, the net exporting RTO or ISO may seek to recover some of its
transmission costs through an export rate.
As discussed above, costs of new transmission expansions will be
recovered in accordance with the regional pricing policy, which may be
informed by the appropriate regional state committee. As discussed in
Appendix A, the regional pricing policy will be filed with the
Commission by the RTO or ISO.
Market Monitoring and Market Power Mitigation
These are relatively undeveloped features of Order No. 2000, which
did not have a market power mitigation component. For customers to
benefit from wholesale power markets, it is critical that market prices
fairly reflect the conditions of supply and demand rather than the
exercise of market power. Each RTO or ISO would have an independent
market monitor either for the individual RTO or ISO or for a larger
region.
The market power mitigation measures must protect against the
exercise of market power without suppressing prices below the level
necessary to attract needed investment in new infrastructure in the
region. At a minimum, the RTO's or ISO's tariff should include rules
limiting bidding flexibility where there is localized market power. The
RTO's or ISO's tariff must also include clear market rules designed to
prevent market manipulation strategies, including the types of anti-
gaming tariff provisions in the proposed rule.
The types of mitigation tools and the triggers and consequences of
mitigation should be tailored to the needs of each region. For example,
energy-limited resources, such as hydroelectric generators, may need to
have bidding mitigation protocols and thresholds that are different
from thermal generators. However, mitigation tools which vary by region
across market seams have the potential to create enforcement problems
and undesirable behavioral incentives. For this reason, the Commission
will look closely at mitigation proposals, not only for their
suitability for the RTO's or ISO's regional markets, but for their
compatibility with neighboring RTOs and ISOs.
Spot Markets To Meet Customers' Real-Time Energy Needs
While we expect that the vast majority of energy bought and sold
will continue to be under negotiated long-term contracts between
customers and suppliers, the nature of electricity requires the
availability of a spot market for the last-minute sales or purchases
needed to ensure system reliability. This balancing function is
currently performed by the transmission provider. Under the Final Rule,
the RTO or ISO must use a real-time market for energy to resolve
imbalances. A transparent spot market not only helps keep the system
reliable and lowers costs but also provides important price and other
information to all market participants on an equal and open basis. It
also gives the public a timely way to assess the functioning of the
market. These markets will also facilitate customer response to prices
as well as ease the introduction of some renewable and other innovative
supply technologies.\9\ The RTO or ISO in each region will develop the
detailed market rules that will be included in its Commission-filed
tariff. An RTO or ISO must also introduce a day-ahead market and a
market for various ancillary services when the market is ready for
those steps. Unlike Order No. 2000, which allowed power exchanges
without a check for security constraints, any RTO or ISO day-ahead
market must be designed to work reliably with the congestion management
system.\10\
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\9\ State action is required for retail customers to have demand
response options. Where states permit end users to participate
directly in wholesale markets, demand response programs could be
administered through the RTO or ISO tariff. The Commission strongly
advocates demand response to limit supplier market power, enhance
reliability and resource adequacy, and limit price volatility.
\10\ The failure to check for security constraints created
perverse incentives for participants in California to create
congestion.
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Transparency and Efficiency in Congestion Management
Regions should develop an approach to manage congestion that
protects against manipulation, uses the grid efficiently, and promotes
use of the lowest cost generation. Efficient market behavior depends
heavily on assigning cost responsibility to those who cause the costs
and the benefits to those who reduce costs. Today, transmission
providers resolve congestion through a system that causes unnecessarily
expensive generation redispatch. These added costs are hidden but are
real and are paid by customers today. Order No. 2000 required RTOs to
have transparent market mechanisms with efficient price signals in
place to manage transmission congestion within one year of initial
operation. We would continue that general approach for both RTOs and
ISOs. We clarify that this rule will not override decisions we have
already made in individual RTO or ISO cases regarding congestion
management.\11\
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\11\ As discussed in Appendix A, we are also including options
that will minimize cost shifts.
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Firm Transmission Rights
RTOs and ISOs that use locational pricing to manage congestion
would be required to make Firm Transmission Rights (FTRs) available to
customers.\12\ FTRs protect customers from the costs of congestion.
Under the Wholesale Power Market Platform, customers in RTOs that use
locational pricing along with network transmission service would have
firm physical transmission service, and customers with FTRs would be
protected from congestion costs.
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\12\ The discussion applies to RTOs and ISOs that have embraced
locational pricing. As noted in Appendix A, there are ongoing
discussions in the Western Interconnection regarding common elements
of market design. We will not prejudge the results of those ongoing
discussions.
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We will not require auctions of these rights. FTRs allow customers
to schedule service according to the paths specified in their rights,
with no risk of congestion charges. There also would be no risk of
curtailment, absent a force majeure event such as the loss of a
transmission line. By providing protection from congestion costs, FTRs
also allow market participants to enter into contracts with a locked-in
price if desired. Thus, FTRs allow for maximum utilization of valuable
scarce grid capacity and therefore lower costs to customers.
In the Final Rule, for RTOs or ISOs that have not already addressed
this issue, these rights would be allocated according to existing
contracts and existing service arrangements in order to hold customers
harmless. To the extent transmission rights have already been approved
by the Commission in RTO or ISO orders we would not override these
decisions in the Final Rule.
Resource Adequacy Approaches
Order No. 2000 did not include a regional view of resource
adequacy. We have learned that if one state has inadequate resources,
it can create severe problems for the larger region. It is difficult
for the Commission to assure just and reasonable wholesale market
prices if there are insufficient resources to meet demand. Each region
with an RTO or ISO will determine how it will ensure that the region
has sufficient
[[Page 24684]]
resources to meet customers' needs. The approach to and level of
resource adequacy will be decided by the states in the region drawing
from a mix of generation, transmission, energy efficiency, and demand
response. It is important to have a consistent approach throughout the
region, which should be developed by the regional state committee.
States may decide to ensure resource adequacy through state imposed
requirements on utilities serving load within the region. Other states
may choose to have RTOs or ISOs operate capacity markets. In any case,
the choice on the approach is made by the states within the region.
Other Issues on Which Commenters Seek Clarification
[sbull] RTO and ISO Governance--We will include overarching
principles of independent governance in the Final Rule, but will decide
governance issues on a case-by-case basis. The Final Rule will not
override governance already approved in earlier RTO orders.
[sbull] RTO Decisions--We confirm that the decisions made in prior
RTO orders in which we noted an overlap with the Standard Market Design
rulemaking will not be overturned in the Final Rule.
[sbull] Liability--A standard tariff provision limiting liability
for transmission providers will be included in the Final Rule.
[sbull] Cyber Security--We will adopt the North American Electric
Reliability Council (NERC) standards for cyber security.
[sbull] Reciprocity--We propose no change to the Order No. 888
reciprocity requirements and Order No. 2000 provisions affecting non-
jurisdictional entities in the U.S., Canada, and Mexico. We believe
non-jurisdictional entities will benefit from RTO formation and the
development of standardized wholesale market rules. We encourage such
non-jurisdictional entities to voluntarily participate in RTOs and ISOs
as full and equal members.
[sbull] Independent Transmission Company--We propose no change in
our prior decisions on the functions that should be performed by an RTO
and those that may be performed by an independent transmission company
that operates within the RTO's territory.\13\
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\13\ See TRANSLink Transmission Company, LLC, et al., 99 FERC ]
61,106 (2002).
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[sbull] Standards--We are encouraged that NERC, the North American
Energy Standards Board, and RTOs and ISOs have reached agreements on a
process through which they will work together in the development of
reliability and market standards. Market standards developed through
this process could be included in RTO and ISO tariffs to facilitate
compatible and seamless rules across the interconnected power grid.
Appendix A Comparison of the Proposed Wholesale Market Platform with
the RTO Requirements of Order No. 2000
This appendix compares the current requirements for RTOs of Order
No. 2000 with the requirements of the Wholesale Market Platform that
would apply to both RTOs and ISOs. The Wholesale Market Platform is
designed to build on these existing requirements. ISOs would have to
satisfy all of the same requirements as RTOs except with respect to
Scope and Regional Configuration.
This appendix identifies the changes and additions to the
Characteristics and Functions specified in Order No. 2000 that would
result from the Wholesale Market Platform. All other Characteristics
and Functions requirements would remain the same. The Final Rule for
the Wholesale Market Platform would also clarify when incremental
pricing of new transmission facilities (participant funding) could be
used. Finally, the Final Rule would impose several new market-related
requirements on RTOs and ISOs.
Order No. 2000 was a voluntary program. Since that time, almost
every public utility has joined or has committed to join an RTO or ISO.
Therefore, the Final Rule will require that all public utilities join
an RTO or ISO.\1\
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\1\ The requirements of the Final Rule will not apply to
Commission-jurisdictional electric power cooperatives that serve
only retail load.
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As discussed in the White Paper, if for a specific RTO or ISO it
can be demonstrated to the Commission that the costs of implementing
any feature of the market platform outweigh its benefits, the
Commission will not require implementation of the feature for that
particular RTO or ISO.
Throughout this appendix we discuss the role of the states in RTO
and ISO decisions. The Wholesale Market Platform would require each RTO
and ISO to provide a forum for state representatives in the decision-
making process, i.e., a regional state committee. This requirement is
discussed in more detail below.
Finally, as discussed in the White Paper, the Commission does not
intend to overturn decisions that have already been made in individual
RTO cases. Decisions made in prior RTO orders in which we noted an
overlap with Standard Market Design will not be overturned in the Final
Rule. The Commission also does not intend to change our prior decisions
regarding the functions that should be performed by an RTO and those
that may be performed by an Independent Transmission Company that
operates within the RTO's territory.
Characteristics and Functions
The four Characteristics required of an RTO are: Independence;
Scope and Regional Configuration; Operational Authority; and Short-term
Reliability.
The eight required Functions are: Tariff Administration and Design;
Congestion Management; Parallel Path Flows; Ancillary Services \2\;
OASIS; Market Monitoring; Planning and Expansion; and Interregional
Coordination.
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\2\ This includes operation of a real-time spot market for
energy imbalances.
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Characteristics
1. Independence
Order No. 2000. RTOs must be independent of market participants. As
set out in Order No. 2000, by market participant, the Commission means
any entity that, either directly or through an affiliate, sells or
brokers electric energy, or provides transmission or ancillary services
to the RTO unless the Commission finds that the entity does not have
economic or commercial interests that would be affected by the RTO's
actions or decisions.
Wholesale Market Platform. RTOs and ISOs would be required to meet
all of the Order No. 2000 principles for Independence. In addition, the
Final Rule will add to the Order No. 2000 requirements overarching
principles on how to structure independent governance. The Commission
will decide RTO governance matters on a case-by-case basis. Further,
these overarching principles will not change governance decisions that
have been approved in earlier RTO orders.
2. Scope and Regional Configuration
Order No. 2000. The RTO must serve an appropriate region. The
region must be of sufficient scope and configuration to permit the RTO
to maintain reliability, effectively perform its required functions,
and support efficient and non-discriminatory power markets.
Wholesale Market Platform. RTOs would be required to satisfy this
Characteristic. However, new and existing ISOs would not be required to
satisfy this Characteristic. But, ISOs must actively pursue
interregional coordination to minimize the creation of
[[Page 24685]]
seams that act as barriers to trade among regions.
3. Operational Authority
Order No. 2000. The RTO must have operational authority for all
transmission facilities under its control. The RTO must also be the
security coordinator for the facilities that it controls.
Wholesale Market Platform. RTOs and ISOs would be required to meet
this Characteristic.
4. Short-Term Reliability
Order No. 2000. The RTO must have exclusive authority for
maintaining the short-term reliability of the grid that it operates. It
must have exclusive authority for receiving, confirming and
implementing all interchange schedules. The RTO must have the right to
order redispatch of any generator connected to transmission facilities
it operates if necessary for the reliable operation of these
facilities. When the RTO operates transmission facilities owned by
other entities, it must have authority to approve or disapprove all
requests for scheduled outages of transmission facilities to ensure
that the outages can be accommodated within established reliability
standards.
Wholesale Market Platform. RTOs and ISOs would be required to
satisfy this Characteristic.
Functions
Under Order No. 2000, the RTO must perform the following Functions
when it commences operations, unless otherwise noted.
1. Tariff Administration and Design
Order No. 2000. The RTO must administer its own transmission tariff
and employ a transmission pricing system that will promote efficient
use and expansion of transmission and generation facilities. The RTO
must be the only provider of transmission service over the facilities
under its control, and must be the sole administrator of its own
Commission-approved open access transmission tariff. It must have the
sole authority to receive, evaluate, and approve or deny all requests
for transmission service. The RTO must have the authority to review and
approve requests for new interconnections. Customers under the RTO
tariff must not be charged multiple access fees for the recovery of
capital costs for transmission service over facilities that the RTO
controls.
Wholesale Market Platform. The Final Rule would retain these
features and also would clarify the jurisdictional consequences that
result when a public utility that owns, controls, or operates
transmission facilities in interstate commerce joins an RTO or ISO. In
the context of RTOs and ISOs, the RTO or ISO becomes the sole provider
of transmission services for the facilities it controls, and
transmission owning members of the RTO or ISO become wholesale
customers of the RTO or ISO.
To accommodate both the realities of a regionally operated
transmission system and the jurisdiction concerns raised by the states,
the Commission will distinguish non-price terms and conditions of
transmission service from rates for transmission service. As discussed
below, we will assert jurisdiction over the non-price terms and
conditions of transmission used by wholesale transmission customers to
serve bundled retail customers, but we will not assert jurisdiction
over the transmission rate component of bundled retail sales of
electric energy.\3\ Moreover, in setting the wholesale rate for
transmission, the Commission will rely upon the transmission rate set
by the states for bundled retail service.
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\3\ Bundled retail sales of electric energy are sales of
electric energy to retail customers where generation, transmission,
distribution, and other services necessary to supply electric energy
to such customers are sold as a single delivered service by a single
seller and retail supplier choice is not permitted by state
authorities.
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Non-price terms and conditions of transmission service include
matters such as reserving capacity and scheduling service, and it is
critical in the context of RTOs and ISOs that such non-price terms and
conditions apply to all customers on a not unduly discriminatory basis,
with appropriate protection of native load customers. Consistent with
our existing policy for transmission service used to serve unbundled
retail customers (i.e., those in retail choice states), the Final Rule
would allow state regulatory authorities to request waivers of any non-
price terms and conditions of the RTO or ISO tariff that are not
compatible with bundled retail service needs. We note that Commission-
filed open access tariffs have successfully accommodated service to
unbundled retail customers since Order No. 888 went into effect in 1996
and that ISO and RTO tariffs have successfully accommodated service to
unbundled as well as bundled retail customers.
We clarify that Commission jurisdiction over non-price terms and
conditions of transmission used by wholesale transmission customers to
serve bundled retail customers does not affect state authority over
retail choice decisions, transmission siting, or local issues
associated with transmission or distribution (e.g., maintenance, tree
trimming, downed lines, etc.).
The price that a transmission owner pays to the RTO or ISO becomes
its cost for the transmission used to deliver the energy sold at
retail. Consistent with existing Commission policy, transmission owners
would be free to seek a rate from the RTO or ISO for the transmission
purchased to deliver energy to bundled retail customers that is equal
to the transmission component of the bundled retail rates set by the
state commission. Under this approach, the rate set for transmission in
interstate commerce to be re-sold as part of bundled retail service
would be the same rate set by the state for the transmission component
of bundled retail sales. This arrangement would be accomplished under a
wholesale contract between the RTO or ISO and the transmission owner.
Service agreements reflecting such proposed rates would be filed with
the Commission and must be consistent with the Federal Power Act (FPA).
The Final Rule would also clarify that the RTO or ISO may use
license plate or postage stamp rates for designing the access charges
for the region. Each regional state committee may determine which
approach the RTO or ISO should file with the Commission under section
205 of the FPA. If the regional state committee is unable to reach a
decision on the methodology that should be used, the RTO or ISO would
file its own proposal pursuant to section 205 of the FPA.
RTOs and ISOs should eliminate export and import fees where there
is not a notable imbalance between imports to and exports from a
region. Other rate measures could be used to prevent cost shifts among
the regions.\4\ This could include adjusting the revenue requirement
for the importing region to include a portion of the revenue
requirement of the exporting region. However, where there is a notable
imbalance between imports to and exports from a region, the RTO or ISO
may seek to recover some of its transmission costs through an export
fee.
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\4\ For example, a portion of the transmission cost of service
of the exporting region could be recovered through the access charge
of the importing region. Such a measure would reduce the
transmission costs that would be collected from customers in the
exporting region.
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2. Congestion Management
Order No. 2000. The RTO must ensure the development and operation
of market mechanisms to manage transmission congestion. The market
mechanisms must accommodate broad
[[Page 24686]]
participation by all market participants, and must provide all
transmission customers with efficient price signals that show the
consequences of their transmission usage decisions. The RTO must either
operate such markets itself or ensure that the task is performed by
another entity that is not affiliated with any market participant. The
RTO must satisfy the market mechanism requirement no later than one
year after it commences initial operation. However, it must have in
place at the time of initial operation an effective protocol for
managing congestion.
Wholesale Market Platform. The Final Rule would retain the
requirements that the RTO or ISO have an effective protocol for
managing congestion at the time of initial operation and a market
mechanism for congestion management after one year of operation.
The Final Rule would modify the requirement for market mechanisms
to manage congestion. The RTO or ISO would be required to operate such
markets itself. However, two or more RTOs or ISOs may apply to the
Commission to do coordinated congestion management over a multi-RTO or
ISO area as long as this function is carried out by an independent
entity approved by the Commission.
Additionally, the Final Rule would add general principles that a
good market congestion management system must satisfy. The congestion
management system must: (1) Protect against market manipulation, such
as experienced in the California markets; (2) promote the efficient use
of the transmission grid; (3) promote the use of the lowest cost
generation as intended under traditional economic generation dispatch;
(4) assign cost responsibility to those that cause congestion costs and
assign the benefits to those that reduce congestion costs; (5) reduce
involuntary transmission service curtailments, e.g., Transmission Line
Loading Relief; and (6) be compatible with congestion management
systems used by other RTOs and ISOs in the electrical interconnection,
to avoid creating barriers to trade among RTOs and ISOs.\5\
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\5\ For purposes of this discussion, the electrical
intereconnections are the Eastern Interconnection and the Western
Interconnection.
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The Commission has already tasked the Seams Steering Group-Western
Interconnection (SSG-WI) with developing consistent and compatible
market elements for the Western Interconnection by the fourth quarter
of 2003. The congestion management system being developed by SSG-WI
should satisfy these general principles.
The Commission's preferred approach to congestion management is
through locational pricing. However, other methods may be proposed. The
RTO or ISO would need to demonstrate to the Commission how the proposed
congestion management system satisfies these general principles.
If an RTO or ISO uses locational pricing, it must ensure that each
existing firm customer (including transmission owners with a service
obligation for native load) has the opportunity to obtain FTRs \6\
equivalent to that customer's existing firm rights.\7\ We will ensure
not only that existing customers retain their existing rights, but also
that they have the ability to obtain rights for future load growth.
Customers who paid for transmission for load growth can retain the FTRs
for that capacity. The FTRs that are offered by the RTO or ISO must, in
the aggregate, be consistent with the physical limitations of the
transmission system.\8\ If transmission rights or their allocation have
already been approved by the Commission in RTO or ISO orders, we would
not override these decisions in the Final Rule.
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\6\ In the proposed rule, we coined the term ``Congestion
Revenue Rights,'' or ``CRRs,'' as a standard term to describe the
tradable, financial rights that would take the place of the current
``physical'' rights to firm transmission service. We chose this term
to accurately describe what the holder had a right to receive--
congestion revenues associated with the held CRRs' specified receipt
and delivery points and MW quantity. These rights mirror those of
FTRs used in most power markets. Reaction to our replacing ``FTR''
with ``CRR'' was less than enthusiastic; many saw no need for a new
term unless a CRR differs from an FTR. As there is no real
difference, we will now use the term ``FTR,'' or ``Firm Transmission
Right,''.
\7\ A similar transition requirement would apply to a congestion
management system not based on locational pricing.
\8\ Existing rights to service will be preserved. If necessary
to meet these requirements, the RTO or ISO will create counterflow
FTRs to make the aggregate set of FTRs physically feasible. If this
results in a revenue shortfall, it could be recovered through an
uplift charge.
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There would be no requirement to auction these FTRs either
initially or after a transition period. The RTO or ISO tariff must also
offer customers the ability to obtain additional FTRs for load growth.
Customers paying the access charge would have the right to receive the
additional FTRs associated with transmission upgrades that are included
in the regional transmission plan. Entities that pay for the
construction of transmission upgrades through participant funding will
receive the FTRs that result from the transmission upgrades. Once the
initial allocation of FTRs is completed, the RTO or ISO must operate a
secondary market for holders of FTRs to voluntarily sell their FTRs to
others.
The market mechanism for congestion management must be in place
within one year after initial operation, unless the Commission approves
a different timetable. As noted previously, the Commission will be
flexible both as to timing and implementation based on regional
differences and needs.
3. Parallel Path Flow
Order No. 2000. The RTO must develop and implement procedures to
address parallel path flow issues within its region and with other
regions. It will have three years to implement measures to address
parallel path flows between regions.
Wholesale Market Platform. RTOs and ISOs will be required to
perform this Function.
4. Ancillary Services
Order No. 2000. The RTO must serve as a provider of last resort of
all ancillary services (including energy imbalance service) required by
Order No. 888 and subsequent orders. The services must be included in
the RTO administered tariff so that transmission customers will have
access to one-stop shopping for transmission service. All market
participants must have the option of self-supplying or acquiring
ancillary services from third parties. The RTO must have the authority
to decide the minimum required amounts of each ancillary service and,
if necessary, the locations at which these services must be provided.
All ancillary service providers must be subject to direct or indirect
operational control by the RTO. The RTO must promote the development of
competitive markets for ancillary services whenever feasible. To
provide energy imbalance service, the RTO must ensure that its
transmission customers have access to a real-time balancing market. The
RTO must either develop and operate this market itself or ensure that
this task is performed by another entity that is not affiliated with
any market participant.
Wholesale Market Platform. The Final Rule would require RTOs and
ISOs to perform this Function. In addition, the Final Rule would
require the RTO or ISO itself to operate a security constrained real-
time market for balancing.\9\ The RTO or ISO would not be permitted to
use a separate power exchange to perform this function. The RTO or ISO
must also operate a day-ahead market for energy and a market
[[Page 24687]]
for various ancillary services unless it is demonstrated that the costs
exceed the benefits of such markets.
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\9\ The spot market(s) operated by the RTO or ISO are intended
only to supplement long-term supply arrangements.
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The spot market(s) operated by the RTO or ISO should facilitate
price transparency (i.e., for these spot markets the RTO or ISO should
be required to provide on a timely basis, information about the
availability and market price of sales of electric energy at wholesale
in interstate commerce and transmission of electric energy in
interstate commerce to the Commission, state commissions, buyers and
sellers of wholesale electric energy, users of transmission services,
and the public.)
Load-serving entities must also be able to schedule transmission
for generation owned by or contracted for by that load-serving entity
to meet a service obligation to customers or an existing wholesale
obligation. Buyers, including intermittent resources, may procure power
through these spot market(s) to meet their short-term energy needs.
Sellers, including intermittent resources, may offer power for sale
through the spot market(s).
The spot market(s) operated by the RTO or ISO must facilitate the
ability of demand to respond to prices. The RTO or ISO must work with
state authorities to facilitate any demand response programs operated
under state retail tariffs. The RTO or ISO must also work with states
that permit end users to directly access the wholesale market to
facilitate state required demand response programs or to include
appropriate demand response programs in the RTO's or ISO's tariff.
Where a locational pricing system is used for congestion
management, the prices in these spot market(s) must be location
specific for sellers (nodal). The RTO or ISO may use zonal or nodal
prices for buyers. Under a zonal system, the prices paid by load would
be aggregated for the zone (e.g., a utility service territory).\10\ A
locational pricing system can use either cost-based bids or market-
based bids to determine the locational prices.\11\
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\10\ This approach is in operation in the New York Independent
System Operator, Inc. Under that system, generators see location
specific prices. Load sees an aggregate price for each zone. Each
zone is based on the service territory of an individual transmission
owner.
\11\ When PJM Interconnection, L.L.C. first started using
locational pricing it did so using cost-based bids. As a
transitional measure, regions may wish to take a similar initial
approach to start locational pricing.
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The RTO may charge for transmission losses within the region based
on average or marginal losses.
5. OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC)
Order No. 2000. The RTO must be the single OASIS site administrator
for all transmission facilities under its control and independently
calculate TTC and ATC.
Wholesale Market Platform. RTOs and ISOs would be required to
perform this Function.
6. Market Monitoring
Order No. 2000. The RTO must provide for objective monitoring of
the markets it operates to identify design flaws, market power abuses,
and opportunities for efficiency improvements, and must propose
appropriate actions. Reports on these issues must be filed with the
Commission and affected regulatory authorities. The Commission believes
the information collected will be data that the RTO will collect or
have access to in the normal course of business.
Wholesale Market Platform. The Final Rule would retain these
features but would change the name and scope of this Function to Market
Monitoring and Market Power Mitigation. The Final Rule would both
expand and further define the role of market monitoring in the RTO or
ISO. It would also expand this function to require the RTO or ISO and
its market monitor to file market power mitigation measures that are
needed for the market(s) operated by the RTO or ISO. Finally, the Final
Rule would require that the RTO or ISO tariff include clear and
enforceable rules to define and police market manipulation and gaming
strategies.
The Final Rule would require that each RTO or ISO have an
independent market monitor either for the individual RTO or ISO or for
a larger region. The RTO or ISO tariff must contain appropriate market
power mitigation measures to address market power problems in the spot
markets. These mitigation measures must work together with measures on
resource adequacy to ensure that the measures do not suppress prices
below the level necessary to attract needed investment in
infrastructure in the region.
The RTO or ISO tariff must also include a clear set of rules
governing market participant conduct with the consequences for
violations clearly spelled out. At a minimum these would include rules
on: (1) Physical withholding of supplies; (2) economic withholding of
supplies; (3) reporting on availability of units; (4) factual accuracy
of information submitted to the RTO or ISO; (5) the obligation of
market participants to provide information to the market monitor; (6)
cooperation of market participants in investigations or audits
conducted by the market monitor; and (7) the requirement that all bids
that designate specific resources must be physically feasible.
The Final Rule would identify the reporting process that would be
used if the market monitor thinks the markets are not resulting in just
and reasonable prices or providing appropriate incentives for
investment in needed infrastructure. This would include notification of
the Commission, the regional state committee, and other appropriate
state regulatory authorities of the nature of the problem and
recommended solutions.
The Final Rule would also specify the periodic reports that the
market monitor must prepare. The market monitor will provide annual
reports on the state of its markets to the Commission, the regional
state committee, and other appropriate state regulatory authorities.
These reports will incorporate market metrics to provide a basis for
measuring the performance of these markets across RTOs and ISOs, and to
compare the performance of the market in each RTO or ISO over time.
Metrics will also be developed to provide standard performance
information on a monthly basis.
7. Planning and Expansion
Order No. 2000. The RTO must be responsible for planning, and for
directing or arranging, necessary transmission expansions, additions,
and upgrades that will enable it to provide efficient, reliable and
non-discriminatory transmission service and coordinate such efforts
with the appropriate state authorities. As part of this function, an
RTO must encourage market-motivated operating and investment actions
for preventing and relieving congestion. The RTO's planning and
expansion process must accommodate efforts by state regulatory
commissions to create multi-state agreements to review and approve new
transmission facilities. The RTO planning and expansion process must be
coordinated with programs of existing Regional Transmission Groups
where appropriate. If the RTO is unable to satisfy this requirement
when it commences operation, it must file with the Commission a plan
with specified milestones that will ensure that it meets this
requirement no later than three years after initial operation.
Wholesale Market Platform. The Final Rule would retain these
features and also would modify this Function to
[[Page 24688]]
provide that the RTO or ISO must satisfy this requirement as soon as
practicable but no later than when it begins operation, rather than
after three years of initial operation. The Final Rule would not change
the decisions in prior RTO orders regarding the role that an
Independent Transmission Company (ITC) could have in the regional
planning process.\12\
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\12\ See TRANSLink Transmission Company, LLC, et al., 99 FERC ]
61,106 (2002).
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The regional transmission plan must include all transmission
facility expansions in the region. Thus, the RTO or ISO can assess the
combined effect on loop flows and reliability of all existing and
planned facilities, including transmission facility expansions for
which the costs are not necessarily to be borne by all customers.
However, we clarify that transmission owners and others may propose to
build transmission enhancements. The RTO or ISO will assess the impact
of these proposals in the regional transmission plan. In addition, the
RTO or ISO may assess the need for transmission enhancements in view of
opportunities for energy efficiency, demand response, and new
generation technologies, consistent with the policy direction of the
regional state committee on these issues.
The RTO or ISO must also be responsible for transmission planning,
and for directing or arranging, necessary transmission expansions,
additions, and upgrades that will enable it to reliably and
economically serve the needs of all customers in the region, including
historical and native load customers and their projected load growth.
The RTO or ISO would include transmission upgrades in the regional plan
that are necessary to maintain or improve reliability or to reduce
congestion and improve access to lower cost supplies (economic
enhancements).
Economic enhancements would be included in the regional
transmission plan with the costs recovered through the license plate or
postage stamp access charges, if it is prudent to do so from the
perspective of native load in the region. For example, these projects
could include transmission upgrades that: (1) Would resolve significant
and persistent congestion within the region; (2) due to their size and
scope, are unlikely to be undertaken as participant funded transmission
upgrades; or (3) show positive benefits to the region using a cost
benefit analysis that compares the cost to load within the region and
the benefits to load within the region.
We will permit regional flexibility in determining the types of
economic enhancements that would be recovered through the access
charges.\13\ Some RTO or ISO regions may choose an expansive definition
of the types of economic enhancements that benefit customers within the
region. Other RTO or ISO regions may choose to rely more on participant
funding.
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\13\ As discussed below, the choice made by the region will
affect the cost recovery for transmission upgrades. If a
transmission upgrade is determined to be needed to reliably and
economically serve load in the region, the costs will be recovered
through the license plate or postage stamp access charges used by
the region.
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The RTO or ISO tariff would have a clear plan that states the non-
discriminatory criteria that would be used for determining the
reliability and economic enhancements that are needed for customers
within the region. Each regional state committee may determine the
criteria for these economic enhancements. If the regional state
committee reaches a decision on the criteria that would be used, the
RTO or ISO would file these criteria in a filing pursuant to section
205 of the FPA. If the regional state committee is unable to reach a
decision, the RTO or ISO would file its own proposal pursuant to
section 205 of the FPA.
The Final Rule would not require that the RTO or ISO use a Request
for Proposal (RFP) process for transmission upgrades.
8. Interregional Coordination
Order No. 2000. The RTO must ensure the integration of reliability
practices within an interconnection and market interface practices
among regions.
Wholesale Market Platform. RTOs and ISOs would perform this
Function. In addition, the Final Rule would require that RTOs and ISOs
within an electrical interconnection coordinate to resolve seams
issues. Additionally, as discussed above, RTOs and ISOs should
coordinate to eliminate export fees where there is no significant trade
imbalance between the regions.
Transmission Pricing
In addition to the above Characteristics and Functions of an RTO,
Order No. 2000 also addressed transmission pricing reforms by RTOs.
Order No. 2000. RTOs may file for a variety of innovative rate
reforms, including performance-based, returns on equity, non-
traditional methods of determining depreciation schedules for new
transmission investments, and incremental pricing for new transmission
investments (which has since become known as participant funding). Some
of these pricing reforms will be available only through January 1,
2005.
Wholesale Market Platform. The Final Rule would provide that both
RTOs and ISOs would be eligible for the rate reforms identified in
Order No. 2000.
The Final Rule would provide further clarification on when
incremental pricing for new transmission facilities (participant
funding) could be used. The cost of transmission projects that are
determined through the regional planning process to be necessary to
reliably and economically serve load in the region will be recovered
through the access charge that is assessed to load in the region. As
stated above, regions would have flexibility in determining the types
of economic enhancements that would be recovered through the access
charge. Some RTO or ISO regions may choose an expansive definition of
the types of economic enhancements that benefit customers within the
region. Other RTO or ISO regions may choose to rely more on participant
funding.
These rate provisions would be revised to permit an optional
transitional process that could be used for participant funding. For a
transitional period, not to exceed a year, participant funding may be
used for transmission upgrades for generator interconnection as soon as
an independent entity has been approved by the Commission and the
affected states. Using the regional criteria, the independent entity
would make decisions on which transmission upgrades should be
participant funded and which ones should not. These decisions would be
made through a regional planning process conducted by an independent
entity in which the independent entity is also responsible for
conducting all necessary facility studies.\14\ However, this
transitional process is explicitly predicated on the assumption that
this will be the first step towards the RTO or ISO satisfying the
requirements of Sec. 35.34 of the Commission's regulations.
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\14\ E.g., if ESBI were selected by the SeTrans Sponsors to be
their proposed ISA and it received the necessary regulatory
approvals, ESBI could serve this function for SeTrans RTO on an
interim basis.
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Additional Requirements of the Wholesale Market Platform
In addition to the above changes to the existing requirements for
RTOs, the Wholesale Market Platform would require the following:
1. Role of the States
Order No. 2000. Order No. 2000 recognizes that states have an
important role in RTO formation and governance,
[[Page 24689]]
and regional interests forming an RTO are required to consult with the
states about the appropriate role for states and about the
organizational form of the RTO. Although there were calls for the
Commission to establish some form of regional regulation in Order No.
2000, the Commission decided, given the diversity of regional state
interests and state laws, as well as differences in the organizational
forms that RTOs may adopt, to decline to reach generic conclusions
about states' roles. The Commission invited states to participate
collaboratively with the FERC in fostering RTO formation.
Wholesale Market Platform. The Final Rule would retain the
requirement for an important role for states in RTO or ISO formation.
In addition, each RTO or ISO would be required to provide a forum for
the participation of state representatives in its decision making
process. The structure and functions of these groups will be determined
by the states within the region. Each regional state committee will
also decide how it will reach decisions, e.g., unanimous support or
simple majority. State commissions working with existing RTOs and ISOs
have developed procedures that provide examples that could be used in
other regions. In the Midwest, state commissions have proposed the
establishment of a flexible regional organization, a ``Midwest Multi-
State Committee,'' that would provide coordinated action on matters
that are subject to state jurisdiction as well as issues that relate to
wholesale power markets and interstate transmission. In the mid-
Atlantic region, state commissions have a memorandum of understanding
with the RTO. Other procedures could also be used.
An RTO or ISO may propose to recover as part of its annual budget,
the cost of reimbursing state officials' reasonable expenses incurred
by serving on the regional state committee.
Each regional state committee would have the primary responsibility
for determining the regional proposals for cost responsibility and the
transition process listed below. The RTO or ISO will provide the
regional state committee with technical assistance. If the regional
state committee reaches a decision on the methodology that would be
used, the RTO or ISO would file this methodology pursuant to section
205 of the FPA. If the regional state committee is unable to reach a
decision, the RTO or ISO would file its own proposal pursuant to
section 205 of the FPA.
[sbull] Whether, and to what extent, participant funding would be
used within the region for transmission enhancements. This would
include whether participant funding would be used on a transitional
basis before the RTO or ISO assumes operational control of the
transmission facilities.
[sbull] Whether license plate or postage stamp rates will be used
for the access charge paid by load in the region.
[sbull] Where an RTO or ISO uses locational pricing, whether the
region will allocate FTRs directly to customers or whether FTRs will be
auctioned and the revenues from those auctions (Auction Revenue Rights
or ARRs) allocated directly to customers.
[sbull] The transition process that will be used in the region to
ensure that each existing firm customer receives FTRs or ARRs, based on
the regional choice, equivalent to the customer's existing firm rights.
This includes whether any revenue shortfalls would be recovered through
an uplift charge that applies to all customers in the region or over a
narrower class of customers, e.g., only to customers in certain zones
within the region.
Each regional state committee would determine the extent to which
states within the region need to coordinate or have a consistent
approach for certain planning issues that can affect cost
responsibility among transmission owners and other load serving
entities within the region. The RTO or ISO will provide the regional
state committee with technical assistance. These include:
[sbull] Whether transmission upgrades for remote resources will be
included in the regional transmission planning process.
[sbull] The role of transmission owners in proposing transmission
upgrades.
[sbull] The role of generation, transmission, energy efficiency,
and demand response in resource adequacy.
Each regional state committee will also be responsible for
determining the resource adequacy approach that will be used across the
entire region.
2. Resource Adequacy
Order No. 2000. Order No. 2000 has no provision for generation or
demand response resource adequacy.
Wholesale Market Platform. Having sufficient available resources
(generation, transmission, energy efficiency, demand response) is
central to ensuring that wholesale power prices are just and reasonable
and that service is reliable. The Final Rule will not require a uniform
approach to resource adequacy. Rather, each regional state committee
will be asked to determine the approach for resource adequacy across
the entire region. The region may choose to use resource adequacy
measures that are enforced by state regulation of utilities, enforced
through the RTO or ISO tariff, e.g., a capacity market, or other
measures. The Final Rule will not set a minimum reserve margin.
The resource adequacy measures adopted by the region must work
together with the region's market power mitigation measures to ensure
that there are appropriate incentives to invest in sufficient
infrastructure to maintain reliable and reasonably priced service to
customers in the region.
3. Liability
The Final Rule would include standardized tariff provisions that
limit the liability of RTOs and ISOs and transmission owners that
belong to RTOs and ISOs. The tariff would provide that they would not
be liable for any damages arising out of ordinary negligence. In
instances of gross negligence, the RTO or ISO or the transmission
owners that belong to RTOs or ISOs would only be liable for direct
damages, and not for consequential or indirect damages. The same
protections would also apply to generators when they are implementing
the directives of the RTO or ISO. Courts will determine whether an
action is negligent or grossly negligent.
4. Cyber Security
The Commission will adopt the North American Electric Reliability
Council (NERC) standards on cyber security.
[FR Doc. 03-11357 Filed 5-7-03; 8:45 am]
BILLING CODE 6717-01-P