UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Electricity Market Design and
Structure RM01-12-000
COMMENTS OF EDISON ELECTRIC INSTITUTE
The Edison Electric Institute (EEI),
on behalf of its Alliance of Energy Suppliers (Alliance), Transmission Group
and Energy Services divisions, is pleased to file the following comments on the
Commission’s Working Paper on Standardized Transmission Service and Wholesale
Market Design (SMD Working Paper) in this important proceeding.[1]
EEI is the association of the nation’s shareholder-owned
electric utility companies and industry affiliates and associates worldwide,
including companies that generate, transmit, and distribute electricity and
provide an array of energy and other services to their customers. The Alliance division of EEI represents
independent power producers, generators, and power marketers in the United
States’ wholesale electricity markets.
The EEI Transmission Group represents utilities and transmission companies
that transmit electricity in wholesale transactions. The Energy Services division represents the retail services and
load serving entities of EEI member companies.
Together our U.S. members serve nearly 95 percent of the customers of
the shareholder-owned segment of the industry and about 70 percent of all
consumers of electricity in the United States, generating and delivering almost
70 percent of the country’s electricity.
EEI welcomes the SMD Working Paper
for development of a standard market design for national wholesale electric
markets. Conceptually, it sets forth an
excellent framework for developing standardized electric markets and should
help to bring stability to what has appeared to be a confusing and changing
regulatory landscape. EEI believes that
the Commission’s SMD, particularly the creation of centralized markets and the
single Network Access Tariff (NAT) present a new paradigm for the provision of
electric and transmission services in many areas of the nation. It moves from a “wheeling model” promulgated
under Order No. 888 (which is conceptually based on an integrated utility
moving electrons for others when it has capacity to spare) to a centralized
market using one transmission service, with transmission capacity allocated
based on price, not ownership.
As a result of this paradigm shift, many regions of the
country will have to develop new systems and facilities – over and above those
contemplated under Order No. 2000 and Regional Transmission Organization (RTO)
implementation. Moreover,
implementation of the concepts in the SMD Working Paper will involve many
complex cost, jurisdictional and practical issues. We urge that the Commission move forward to develop the standard
market design (SMD) and rulemaking in a manner that remains mindful of the
complex issues affecting different stakeholders that must be resolved in the
process of achieving the objectives of developing well functioning and well
designed wholesale electricity markets at least cost in conjunction with
appropriate state regulators. By doing
so, the SMD should bring benefits to all electric customers, regardless of the
degree of electric restructuring in their state.
EEI particularly applauds the Commission for developing a
coherent wholesale electricity market design based on principles that have been
proven to work in several regions of the United States. Conceptually, EEI supports much of the SMD
set forth in the SMD Working Paper. In
particular, EEI agrees with many of the
core elements of the SMD proposed in the SMD Working Paper, including
provisions for: day-ahead and real-time
wholesale energy markets; spot energy prices that result from and are linked to
the physical dispatch of the system through locational marginal prices (LMP);
and congestion management performed through the use of LMPs, including use of
tradable transmission rights as a hedging tool to assure a known price for
transmission. Finally, EEI agrees with
the Commission that the RTOs should have a market monitoring unit that is
independent of RTO management and that the SMD should be open to further
development as more experience is gained.
While we strongly endorse the framework of the SMD
Working Paper, EEI offers comments on a number of proposals. EEI recommends that the Commission make
rulings in existing RTO filings as the chief vehicle for establishing
independent transmission providers, nationwide, as well as to provide
regulatory clarity and certainty. EEI
recommends that the Commission provide an opportunity for different business
models of independent transmission companies be permitted to operate in
coordination with RTO markets and system dispatch requirements. EEI recommends that the Commission obtain
state public utility commission support for the NAT as the single transmission
tariff for all service. EEI also
recommends that the interim hubbing measures be consistent with reliability
requirements. While EEI fully supports
the Commission’s commitment to expanding demand response, EEI cautions that new
initiatives need to be integrated carefully within existing demand response
programs. Expansion and planning
policies need to be consonant with the evolution of the markets and to reflect
the need for new resources – particularly transmission -- and congestion
reduction. In addition, as transmission
is shifted from state to federal jurisdiction, the Commission needs to limit
transmission owner and operator liability consistent with its policies on the
gas side and with decades-old state policies.
Reserve markets need more development to function properly and capacity
adequacy needs to be addressed. The SMD
should include clearinghouse functions and market monitoring units should be
advocates for competition. Finally, EEI
urges the Commission to work with states and utilities to find ways in due
course to integrate the benefits of SMD with state retail market design.[2]
In keeping with the Commission’s new and welcome practice
of incorporating substantial public discussion in its rulemakings,[3]
EEI urges that in this most important docket the Commission to continue its
programs of outreach and dialogue to address both continuing policy concerns
and regional and local implementation issues.[4] EEI believes that the industry needs to
avoid high cost mistakes and consequent stranding of costs. In order to implement SMD in a least cost
manner, existing regional infrastructure assets and human resources should be
incorporated to the maximum extent; it
is critical to coordinate closely with state regulators. Continuing regional consultations would
focus on identifying how to achieve least cost solutions adapted to each
region. EEI also believes that such an
approach could lead to entities being in a position to make conforming filings
prior to the issuance of a final rule.
II. EEI Commends the Commission’s Vision
in the SMD Working Paper, But Cautions that Some Provisions May Need to Be
Modified in any NOPR.
EEI supports the Commission’s plan to bring full
competition to all wholesale electric markets nationwide. EEI is hopeful that the Commission, working
with the industry and the states, can devise additional mechanisms to bring
federal, state and municipal power suppliers as well as cooperatives into full
conformity with the SMD. In
anticipation of a formal rulemaking, the SMD Working Paper focuses squarely on
designing uniform national market rules and structure through a new,
single-service open access tariff – the Network Access Tariff -- as the
centerpiece of RTO development.
EEI commends the Commission for developing a coherent
wholesale electricity market design based on principles that have been proven
to work in several regions of the United States. EEI supports much of the SMD set forth in the SMD Working
Paper. EEI agrees that the SMD should
include day-ahead and real-time wholesale energy markets. Such a design should allow for the
coordination or the integration of the system operation and market administration
functions to be accomplished in a manner using existing infrastructure. EEI believes, however, that the SMD can and
should also allow for alternative transmission business models. Spot energy prices should result from and be
linked to the physical dispatch of the system through locational marginal
prices (LMP). Congestion management
should be performed through the use of LMPs and include tradable transmission
rights as a hedging tool to assure a known price for transmission. EEI agrees that RTOs should have a market
monitoring unit that is independent of RTO management. EEI applauds the Commission’s balanced
approach in calling for “the regional transmission planning process . . . [to]
be aggressive about facilitating new demand response, transmission or
generation construction as needed.”[5] Finally, EEI agrees with the Commission that
the SMD should be open to further development as more experience is gained.[6]
B.
EEI Notes That Certain
Elements of the Proposed SMD and Transmission Service Need Modification.
While
supporting many aspects of the SMD and the introduction of a new NAT, EEI
cautions that a number of elements proposed in the SMD Working Paper may hinder
achieving an SMD in a timely manner, may need to be adjusted or could prove
harmful to developing well functioning wholesale markets. These elements are discussed below.
1. EEI
Believes That A Key Step to Implementing the SMD Will Be For the Commission to
Rule on Existing RTO Proposals.
The Commission
calls for administration of the markets, as well as the performance of a number
of critical functions,[7]
by “an entity independent of the market participants.”[8] This “transmission provider”[9] could be an RTO or ISO or an
“independent entity.” EEI believes that
the most effective way for the Commission to achieve this objective is to rule
on the existing proposals before the Commission to form RTOs. It is not clear that establishing an
“independent entity” as an interim step will not be a distraction from the task
of implementing Commission-approved RTOs.
Virtually all regions have RTO proposals on file. Swift and clear Commission action will speed
the process and stabilize current regulatory uncertainty.
2. Different
Approaches to Coordinating Market Operations and Grid Operations are Necessary
to Achieve Full Development of Transmission Businesses and Their Contribution
to the SMD and Congestion Management
Regarding the “slice and dice” debate about how to
structure the transmission business models, EEI notes that the Commission said
it would make scope and governance calls in individual RTO cases.[10] The Commission did, however, address a major
element influencing the ability of independent transmission companies to
contribute positively to the workings of the market and to bringing benefits to
customers: co-locating the market
operations with the system operations.[11] Without taking sides on the question, EEI
points to the fact that there are different types of efficiencies to be
obtained in different regions of the country and therefore the solution need
not be made with a one-size-fits all approach.
Historically, in the northeast, for many decades
utilities developed a regional, centralized dispatch of numerous systems. With the advent of Order No. 888, requiring
the tight pools to file a single tariff, it may have been most efficient for
each of the sub-regions to overlay a single market design over existing system
dispatch infrastructure. This legacy,
of course, should not preclude entities within that region finding new or
continuing to use other approaches that may be more effective and efficient,
using satellite control centers[12]
or combining a super-regional market and LMP dispatch but retaining multiple
control centers.
In other areas of the
country, large systems have historically not been integrated for control
purposes. It may be more efficient -- and less costly -- to use existing
control areas and personnel to implement system dispatch while developing the
various markets (day ahead, real time, ancillary services, transmission rights)
and locational dispatch protocols into one centralized operation. This will permit vital regional market and
dispatch functions to be centralized while operations in various control
centers can perform functions consistent with the market design, thereby
allowing for regional differences and innovation.
While there must be absolute coordination between market
operations, system dispatch and system control, there may be different low cost
approaches to achieving that objective.
In order to avoid stranding costs and more importantly to fully use
existing physical plant and human resources, the Commission will need to allow
different solutions. This will blend
the single standard market design with different but compatible business models
appropriate to different regional conditions.
3. The
Commission Should Seek State Concurrence on the Proposal to Adopt a Single
Transmission Tariff for all Transmission Service.
The requirement that all
transmission be served under a single, federal tariff will need substantial
agreement from state public utility commissions. EEI members could find themselves caught between two conflicting
jurisdictions unless this question is settled.
The conflict can take many forms.
It would be unfortunate, leaving aside the question of jurisdiction, for
the Commission’s objectives to founder on state reluctance to permit public
utilities to convey control of their transmission systems to RTOs.[13] While the proposed single transmission
service proposal clearly would establish non-discriminatory access for and
treatment of all generation, EEI urges the Commission to obtain consensus of
the states on this provision. EEI notes
that there could be other options to the single tariff, including separate
transmission and market tariffs, as the Commission required for the New York
ISO.
As
a transition device, the SMD Working Paper proposes that transmission providers
that do not offer centralized markets should implement interim physical trading
hubs.[14] EEI supports the concept of “hub”
transmission service if such service is designed in a manner that does not
undermine system reliability or increase risks for the pre-existing
transmission customers. Such a service
is strongly desired by many market participants today for the additional
flexibility it provides transmission customers and for complementing the
established financial trading hubs across the country. As envisioned, hub transmission service
would provide physical transmission service commensurate with the energy
products traded universally across the interconnect – even without SMD.
Although the SMD Working Paper suggests that some
transmission providers should implement physical trading hubs prior to the full tariff redesign, the
proposal is not discussed in detail.
EEI requests that the Commission
use the upcoming NOPR process to further develop the precise design and
operation of these hubs, and to determine the circumstances that would have to
exist in order for such hubs to be employed in a manner that maintains system
reliability and that actually encourages competitive wholesale markets. Finally, as the Commission proceeds to
clarify its policy towards interim physical trading, EEI urges the Commission
to carefully distinguish between hub transmission service and an actual
scheduling hub. Unlike the former, a
scheduling hub would allow customers to not only purchase hub transmission
service, but to actually schedule unbalanced transactions to/from the hub
because the hub would itself be considered a pseudo "source" or
"sink". Until a balancing
market is implemented as part of the SMD, allowing unbalanced schedule to the
hub could be problematic.
EEI fully supports
efforts to implement demand response as part of the SMD. Demand response, as the Commission points
out, “is essential in competitive markets to assure the sufficient interaction
of supply and demand”.[15]
Allowing customer demand response to price signals has the potential to bring
substantial benefits to the growth, depth and liquidity of wholesale electric
markets. In addition to the
Commission’s cited benefits of market power mitigation and greater customer
choice, demand response can dampen volatility, lower prices to consumers,
support reliability, contribute to conservation, and create business
opportunities.
EEI believes that the
framework set forth in the SMD Working Paper for incorporating demand response
as an integral part of the SMD provides a good platform for further efforts to
define the role of demand response, to learn from the wide range of demand
response programs ongoing at the retail level, and to determine how best to
harmonize demand response at both the RTO and retail customer levels. EEI members have decades of experience in
operating cost-effective state-approved demand response programs. Actions taken and rules promulgated under
the SMD should accommodate, and not interfere with, these cost-effective
bilateral programs. Moreover, since
demand response measures involve retail service issues, the Commission must
work closely with state commissions to coordinate integration of these measures
into regional market structures. EEI is
also concerned that demand response programs that are uneconomic, or that
impose preferences, subsidies, or arbitrary targets may distort the market and
lead to inefficiencies as well as conflicts with state programs.
In working through these
next steps to define demand response in the context of the SMD, EEI notes, and
as FERC is keenly aware,[16]
that accommodating demand response in the wholesale markets is only one of a
wide range of proposed modifications to market design and market rules, and by
itself is not a complete solution to some existing market weaknesses. While demand response will have mitigative
effects on the potential exercise of market power, EEI recommends to the
Commission that demand response by itself may not be sufficient – particularly
in the early stages of transition - and that the Commission should not rely on
it as a sole mechanism for mitigating market power. For example, to the extent that retail rate caps mute the price
signal to retail customers, the potential for demand response to mitigate market
power will be limited...
Customers should have options to protect against high and/or volatile
prices and system emergencies. For
example, in system emergencies, customers should be able to reduce demand in
accordance with contracts or bid-based pricing. EEI believes that there should be some standards defining when
both resources and customers can respond quickly during periods of price
volatility or system emergency. These
standards can serve the dual goals of advancing competitive wholesale markets
while also ensuring system reliability.
EEI recommends that if any demand response
programs developed at an RTO level permit third-party demand response
providers, that the SMD encourage information sharing between load serving
entities (LSEs), demand response providers, and RTOs. The purpose of information sharing is to provide the LSE with the
opportunity to know if a customer plans to reduce load, to assist the LSE in
its own scheduling requirements, and to ensure that the RTO is not double
counting demand response from customers who are participating in multiple
programs. This is particularly central in states without retail
competition. The Commission needs to
assure that demand response programs in the SMD accommodate the varying stages
of retail restructuring.
EEI strongly supports the
Commission’s recommendation that “[d]emand response options should be available
so that end users can respond to price signals and reduce loads as they feel
the price exceeds their individual willingness to pay for delivered
electricity.”[17] It is
important that the SMD accommodate the ability of buyers in the RTO or other
markets to submit price responsive demand bids, i.e., negatively sloped demand
curves. EEI also supports a general
proposal that demand can participate in some product markets as sellers,
e.g., by offering to sell operating reserves or by providing emergency
load reduction. However,
recommendations that demand response and generation supply be treated as
equivalent may not be appropriate in all markets, since the two display
significant differences in operational and economic characteristics.
If
demand response is treated as a form of supply, as described above, the
Commission should require in the SMD that sellers of demand meet the same general
business standards as sellers of supply, including performance, licensing,
creditworthiness and market monitoring and mitigation requirements. This would help assure that demand
response achieves wide acceptance and is viewed as a legitimate alternative.
Finally,
EEI recommends that the Commission encourage an industry consensus-building
effort for developing standards for integrating demand response into
markets. This willThis will
lead to swift implementation of economically efficient, market-based
approaches. This approach will also
allow for the Commission and stakeholders to learn from ongoing state retail
demand response programs, including which approaches are most cost effective.
6. Long-term Planning and Expansion Needs to be Consistent with Emerging
Market Forces.
EEI commends the Commission’s balanced approach to
long-term planning and expansion and the principle that the planning process
should “identify opportunities for increasing competition, particularly the
elimination of local market power when possible, and should be aggressive about
facilitating new demand response, transmission and generation construction as
needed.”[18] The Commission’s detailed proposals
regarding long-term planning and expansion[19]
appear, however, to take a step back toward central planning approaches by
providing that “the RTO would choose an ultimate solution, whether
transmission, generation or demand side, after vetting proposals through an
open stakeholder process.”[20] There is a risk that this approach could
impede development of competitive generation supplies, could stymie the
development of economically efficient demand response, and at the same time
undermine investment in transmission as well as vitiate the necessary regulated
monopoly status of transmission.
EEI offers two principles that the Commission should
apply in developing long-term planning and expansion. One, as in any other industry, market risk should be placed on
competitively supplied elements.
Generation, merchant transmission and demand response programs arguably
should meet the market test. Regulators
and RTO managers and their stakeholder advisers should not be dictating
development.[21]
Two, planning for transmission expansion
and its response to the new competitive realities of generation
unpredictability and demand fluctuations will require a paradigm shift. When supply and transmission were developed
by a regulated franchised utility based on projections of a static demand, and
regulators could shape rate changes to minimize rate shock, centralized
planning for transmission expansion was consistent with centralized planning
for generation. Today and tomorrow,
when generation, merchant transmission and demand (where possible) can and
should respond to market forces, transmission needs to respond to these new
market forces.
In the SMD Working Paper, the Commission
advocated long term planning and expansion rules that could substitute
centralized RTO planning – driven by participant-sector voting – for
traditional regulated investment mechanisms and for truly market-responsive
decisions. At the heart of the debate
is the role of transmission in wholesale electricity markets: Is transmission a substitute for (or,
competitor with) the supply and demand sides of the market, or is transmission
a complement for supply and demand by joining them through the delivery
infrastructure? In some circumstances,
the substitutability of generation or demand response for transmission can be
identified. For example, constraints
might be eased by building new generation within a load pocket or by expanding
transmission into the pocket; conservation or other demand reduction, if they
are reliable and sure to persist, may remove or at least delay the need for new
transmission investment.
Transmission is, however, the backbone of the electric
utility system and is much more of a complement to the supply and demand
functions than it is a substitute. EEI
believes that a robust transmission system is imperative in order to deliver
the benefits of competition to customers, including greater access for new
competitive generation resources, reduction of congestion costs and greater
reliability. Rules that completely
remove transmission investment planning decisions from the owners (who are also
the investors) of the transmission system introduce a greater risk that needed
transmission investment just won’t happen.
Rules that place the origination and determination of transmission
investment planning and decision processes with market participants, regulators
and special interest groups rather than investors may create gridlock.
EEI recommends that the Commission take substantial
comment and develop a carefully crafted policy regarding planning and expansion
so as to achieve the greatest public benefit. The Commission’s proposed centralized RTO
approach is in need of review and clarification so that the roles and
responsibilities are clearly and appropriately delineated.
7. The NAT
Needs to Limit the Liability of Transmission Assets Under Federal Jurisdiction.
EEI urges the Commission to address the important issue
of limitation of the transmission owner’s liability in the reformation of the
OATT. In doing so, EEI believes that
limiting transmission owner liability to gross negligence and intentional
actions, as the Commission recently articulated for the natural gas pipelines,[22]
will help to spur RTO formation, the advance of the SMD and the adoption of an
NAT. In the past, as noted by the court
in the order No. 888 litigation, “FERC . . . allowed electric utility tariffs
to explicitly limit a utility’s liability for service interruptions to
instances of gross negligence or willful misconduct.”[23] The Commission has rejected provisions
limiting liability in the OATT with the argument that state regulatory
limitations already provided that protection.[24] However, because considerable transmission
assets have been transferred from state to federal jurisdiction since Order No.
2000 and the Commission’s current policies will further that transfer, state
tariff limitations will have a declining role.
EEI recommends that the current policy be changed to substitute a
federal protection that comports with previous state law limitations and the
similar protection offered to gas pipelines.
The same public policy rationales that supported the state limitations
of liability support the Commission adopting that same limitation. It keeps costs low and fair, it puts the
risk on the entity most appropriate to bear and accommodate it, and it does not
change the transmission owner’s responsibility to provide the safe and reliable
service it has always had.
8.
Reserve Markets Need
More Development.
The SMD Working Paper appears to prescribe a system of
reserve markets that clears day ahead based upon availability bids and with
provision for self supply. The SMD
Working Paper correctly points out that such markets should insure by their
design that higher valued products should have higher prices than lower valued
products and that higher valued products should be substituted for lower valued
products where the price is lower and they are substitutes. The problem with the prescription is that
such a market is not in operation. PJM
allows for self supply, but does not simultaneously optimize its reserve and
energy markets. New York ISO
simultaneously optimizes, but does not provide for self supply. This is an area where more development work
is needed. Instead of prescribing an
untested end state, the Commission should allow alternative formulations of
these markets as long as the totality of the energy, reserve and capacity
markets work together to provide proper price signals.
9. Capacity Adequacy
Needs to Be Addressed in Each RTO.
The SMD Working Paper does not
prescribe a specific capacity market, but recognizes the need for some
mechanism to insure system adequacy.
The Paper concludes that “… there may be a need to include specific
measures to insure that LSEs maintain a reasonable reserve margin.”[25] The Paper also correctly recognizes that
the design of mechanisms to insure that LSEs procure an adequate amount of
capacity is a contentious one.[26]
The history of tight power pools in
the Northeast is instructive in defining the issues. A capacity market has been part of the design of the tight power
pools in the Northeast for decades. The
rationale for a capacity market was that when a participant was short of
energy, additional energy could be purchased at formula rate based upon the
marginal cost of operation. In
addition, if in real time the pool was short, curtailment rules provided for
equitable, although not necessarily economic, means of customer
interruption. Since the marginal cost
of operation would only recover the operating costs of the last unit that
operated, that unit was not compensated for its capital costs through the
energy market. Instead the capital
costs were recovered through retail rates of the integrated utility providing
the service to the end use customer.
However, under this system there needed to be some type of mechanism in
place to insure that one set of retail ratepayers did not lean on or be
subsidized by another set of retail ratepayers. Accordingly, along with this system of cost based regulation, it
was sensible for the pool to require as a condition of membership that all participants
have sufficient capacity to meet their own requirements and enforce it with a
capacity deficiency mechanism, thereby ensuring that no one participant leaned
on the resources of another without providing compensation. When the tight pools developed markets, they
naturally tried to avoid having one entity lean on another by incorporating
capacity markets in their market design.
Without taking a position on the merits of any one market proposal,
suffice it to say these capacity markets have been the subject of substantial
debate and modification.
Nonetheless, the problem identified by the developers of
the tight power pools and the reason for which these capacity markets were
developed has survived the development of bid based markets. That is, customer involuntary interruptions
are still performed on an equitable basis and bid caps as well as other
mitigation schemes exist so that energy is still purchased below its scarcity
value even at times of system shortage.
The same issue persist in the SMD Working Paper. The Paper recognizes at least part of the
dilemma by suggesting that, “[w]hen load must be curtailed due to insufficient
generation, the transmission provider should avoid curtailing those LSEs that
have procured sufficient generation, if operationally possible.”[27] However, the nature of the permissive
language above and the suggestion in the Paper that bid caps should persist as
a proxy for price responsive load implies that the problem recognized by the
tight pools will still be extant in the SMD market. Thus, as long as curtailment procedures are not explicitly tied
to price (willingness to pay) and bid caps artificially provide a regulatory
hedge for market participants that are short, it will be necessary to have some
type of mechanism to insure system adequacy and to true up among
participants. The staff was wise in not
prescribing a specific method to address this issue, but should be more
explicit in defining the problem and mandating that each RTO market design
filing explain how it intends to resolve this issue. Each RTO should answer the question “what type of capacity market
is consistent with the totality of the market design?”
10.
Clearinghouse Functions
Should Be Part of the SMD.
The RTO performs
important functions referred to as clearinghouse functions in its
administration of the markets. These
functions include billing, settlement and credit. For example, each of the Northeast ISOs (PJM, New York ISO and
ISO-NE/NEPOOL) has different billing, settlement and credit provisions. Since the RTO is the market operator, it
must perform these functions. Any SMD
prescription for an RTO should contain these provisions and to the extent that
standards can be developed, they should be.
Accordingly, the Commission should, at a minimum, include a requirement
that the RTO provide these functions and include them in the new NAT.
The SMD Working Paper
correctly notes the importance of the function of the SMD in assuring that
energy spot markets are competitive.
The Paper points correctly to the principle that structural solutions
are in general better than behavioral ones.[28] It also points to the necessity of insuring
ease of entry and exit. If market rules
and the structure of the market itself do not result in a competitive spot
markets, the Paper correctly notes that ex ante rules are preferable to
invasive ex post regulation.
Only as a last resort should any mitigation rules be adopted and only
for so long as it is necessary to get the structure of the market correct. The Paper correctly points to demand
response as a necessary missing element in the design of a competitive market
for electricity and correctly calls for the promotion of demand response. EEI general agrees with this ordering of
the principles: 1) structural solutions; 2) proper market structure; 3) ex
ante fixes to market rules; 4) regulatory ex ante solutions such as
call contracts to defease localized market power; and 5) as a last resort,
market mitigation rules such as bid caps.
EEI believes that the sine
qua non of the market monitoring function should be the promotion of
competition. Thus, the market monitor
should be an advocate for competition and should actively pursue that
goal. This includes not only reviewing
market participants’ behavior, but recommending the substitution of properly
structured and designed markets for invasive market mitigation rules. The Paper’s focus on promoting demand
response is both necessary and appropriate, since the temporary bid caps
incorporated in the proposal are a poor substitute for a properly functioning
market. In that regard, the market
monitor should focus on the comparative statistics of the market (the
relationship between demand and supply over time) and should provide periodic
reports that explicitly evaluate the effectiveness of price sensitive demand
including under what conditions such demand will become effective in promoting
competitive electricity spot markets.
Thus, the monitor should be required to report periodically on, among
other things, what additional modifications to the market would be necessary to
eliminate market interventions such as the temporary bid caps suggested in the
Paper.
The SMD Working Paper
also notes that the market monitor should be independent of the RTO management
itself. EEI agrees. It is important for the market monitor to be
able to not only review how market participants behave, but how the RTO itself
is structured and operating. The market
monitor must review the operation of the market and determine what, if any,
changes in RTO policies, procedures and actions would promote a competitive
market. In the RTO’s case, the
monitor’s behavioral reviews are not only consonant with but essential to the
monitor’s role as an identifier of market structure failure. To this end the, the market monitor must be
independent of the CEO and the staff of the RTO and must report directly to a
board that is independent of any supervisory responsibility for the operations
of the RTO.
12. Additional Issues Need Addressing and Industry Review
Before The Commission Issues the NOPR.
EEI recommends
that the Commission develop a supplemental Working Paper that will discuss the
Staff’s policy prescriptions in a number of areas, including those the
Commission indicated were not incorporated into the instant Paper. These include, pricing and rate treatment,
of course, as well as several additional issues touched on in the SMD Working
Paper but not elaborated on. These are
discussed below.
a.
CBM – a Legacy from Load
Serving Obligations -- Must be Transitioned.
The SMD
Working paper proposes that any transmission capability set aside for Capacity
Benefit Margin (CBM), i.e., the amount of margin necessary to
import resources so as to reduce the need to construct generating capacity to
meet reserve margins, must be offered for sale by the transmission provider to
all and explicitly charged for.[29] EEI agrees that this proposal make sense in
the end‑state, but believes there are transition issues that must be
addressed.
CBM is a
legacy of the service obligations imposed on LSEs prior to retail choice. To the extent that such obligations continue
to exist, and to the extent that states are not permitting the construction of
generation to meet in-state reliability reserve margins, but rely on
transmission to bring energy from neighboring states or systems, so does the
need for such margins. Further,
recovery of the proposed payments by LSEs is complicated by existing retail
rate caps and freezes. EEI recommends
that the Commission provide for a transition on CBM responsibility, working
with the state to find the right balance.
b.
A Number of
Transition Issues – Long Term Contracts, Native
Load Obligations and the Allocation of
Financial (of Physical) Transmission Rights – Need to Be Addressed.
EEI notes that
the Commission has deferred discussion of a number of critical issues,
including the treatment of long term contracts and native load, and how those
will be converted to the NAT within the SMD.
At the same time, EEI believes that the Commission needs to evaluate
several alternative approaches to FTR allocation, ranging from auction to
direct allocation to LSEs. This is
because different entities are in different positions regarding load serving
obligations and the untested ability of markets to value FTRs properly. There is a risk that in new FTR markets,
participants will underestimate the costs of congestion and hence undervalue
the FTRs, leaving load with underrecovery.
Since not all regions will be in the same position, EEI recommends that
the Commission permit different regions to adopt different approaches. Finally, EEI recommends that the Commission
work to integrate public power suppliers into the SMD.
III. Consistent With Recent Commission
Practice, EEI Recommends That The Commission Consider Additional Input on
Policy Questions and Schedule Regional Workshops on Implementation Details.
EEI recommends that the
Commission undertake further consultation on both the policy and design
questions in the SMD Working Paper and the regional implementation
elements.
As discussed above and
as the Commission will have heard during the instant comment period, there are
a number of policy questions that need further discussion and on which EEI
recommends that the Commission consult the industry before issuing a final
NOPR. Equally as important, myriad
implementation issues will also need to be worked out in all of the
regions. These issues cannot be
resolved in Washington alone because they need the full participation of the
affected parties and because many aspects of the SMD directly affect matters
currently within state jurisdiction.
Several major examples stand out:
how to integrate hydroelectric facilities,[30]
how to coordinate or combine market and grid operations within existing
regional infrastructure and human capital “givens;” how to integrate or develop
demand response mechanisms; and how to integrate state-regulated transmission
and allocate scarce capacity.
EEI believes that the
objective must be to achieve a least-cost implementation of the SMD. At multiple implementation points, this is a
local, regional undertaking requiring local, regional collaboration. Accordingly, EEI recommends that at this
time the Commission initiate regional discussions on various aspects of SMD
that are affected by local and regional considerations. These discussions should proceed
concurrently with drafting the NOPR and can continue during the comment period
as well.[31] This will permit the Commission to
incorporate each region’s “best practices” and to adapt the SMD implementation
to regional givens.
In further support of
continued consultation on implementation of the SMD, EEI believes the
Commission has an opportunity, through stakeholder input and guidance, to help
shape the filings that will need to be made, so that, with appropriate
incentives, entities could make conforming filings before the issuance of the
final rule.
IV.
Conclusion
EEI respectfully
requests that the Commission consider EEI’s recommendations outlined above and
looks forward to working with the Commission on these important issues.
Respectfully submitted,
David
K. Owens
Washington,
D.C,
April
10, 2002
[1] The EEI comments do not necessarily reflect the views of all EEI members. Some EEI members will be filing comments individually to articulate their own views.
[2] EEI applauds FERC for recognizing that “State commissions have an important role in the process of creating an efficient competitive wholesale market.” SMD Working Paper, slip op at 24.
[3] See, e.g. the Advance Notice of Proposed Rulemaking on Generator Interconnections, Docket No. RM02-1-000, 97 FERC ¶ 61,009 (October 25, 2001) and Notice of Dates and Locations for Regional Collaborative Workshops to aid in the formation of RTOs, RM99-2-000, January 31, 2000.
[4] As the Commission acknowledges, many of the difficult issues involved in the transition to the new services envisioned “may need to be decided on a regional basis,” SMD Working Paper, slip op at 26,and it is likely that the pace and nature of market design will vary among the regions.
[5] SMD Working Paper, slip op at 22, paragraph 3.
[6] Id., at 7. “Standard market design should not be static.”
[7] Id. at 5, 21. These functions include: accepting and processing requests for transmission service, administering the OASIS, scheduling transactions, and administering the imbalance markets.
[8] SMD Working Paper, slip op at 5.
[9] EEI is using the term in “transmission provider” in these comments as defined by the Commission in the SMD Working Paper. EEI notes, however, that the Commission is adopting a term that is conventionally used to designate all kinds of entities that provide transmission services and that it may be appropriate for the Commission to use a less generic, more unique term to apply to those entities that qualify as fully independent. This would preserve common parlance and avoid a lot of potential confusion.
[10] The Commission indicated that it would address the “slice and dice” questions in individual RTO dockets. SMD Working Paper, slip op. at 27.
[11] See, for example, the requirement that RTOs perform both imbalance and transmission markets. SMD Working Paper, slip op at 5.
[12] EEI notes that PJM has one single market and market dispatch, but two control centers, PJM proper and PJM West. This basic principle applies to systems elsewhere.
[13] In Florida, for example, the Florida Public Service Commission (“FPSC”) recently issued Order No. PSC-01-2489-FOF-EI on December 20, 2001 regarding the proposed GridFlorida RTO. In this order the FPSC found that the GridFlorida Companies (i.e., Florida Power & Light Company, Tampa Electric Company, and Florida Power Corporation) were prudent in proactively forming a Peninsular Florida RTO. The FPSC further found, however, that certain aspects of GridFlorida were not in the best interests of Florida retail ratepayers, most particularly the transfer of ownership of transmission assets to GridFlorida. The GridFlorida Companies were directed to modify the GridFlorida proposal accordingly. While committed, therefore, to the development and implementation of RTOs, the FPSC is maintaining its commitment to provide regulatory oversight to protect public interest as empowered by state law.
[14] SMD Working Paper, slip op at 26, paragraph 2.
[15] Id. at 6, paragraph 8.
[16] Id. at 5-7.
[17] Id. at 13, paragraph 5.
[18] SMD Working Paper, slip op at 22, paragraph 3.
[19] Id. at 21, paragraph 4.
[20] Id.
[21] Who bears the market risk for non-performing generation investments picked through RTO decision? The RTO? The developer and shareholders? The ratepayers? Suppose an RTO picks a generation solution to a shortage problem. Assume that demand response programs, including long term demand response in the form of energy conservation investments, begin to succeed. Who is responsible for the decline in economic viability of the no-longer-needed generation plant?
[22] ANR Pipeline, 98 FERC ¶ 61,218 (February 2002), slip op at 5.
[23] Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 727 (D.C. Cir. 2000)
[24] Order Nos. 888-A and 888-B, 81 FERC ¶61,248 (1997), 82 FERC ¶ 61,046 (1998). Avista et al, Docket No. RT01-35-000, 95 FERC ¶ 61,114, slip op at 54 (April 26, 2001).
[25] SMD Working Paper, slip ot at 24.
[26] Id.
[27] Id.
[28] Id. at 22, paragraph 4.
[29] Id. at 14, paragraph 1.
[30] Id. at 21.
[31] EEI notes that the Commission has in previous rulemakings of this magnitude adopted policies that encouraged entities to make filings prior to the Commission’s issuance of a final rule. Because of the Commission’s extensive pre-NOPR dialogues, this rulemaking could offer that same opportunity, particularly if the Commission undertakes continued regional dialogues on key sticking points and structures incentives positively.