A. Undue Discrimination and Impediments
to Competition Remain
1. Since the issuance of Order Nos. 888 and
2000, it has become clear that additional, mandatory measures are needed to
achieve the goals of non-discriminatory transmission access and competition in
electricity markets. Vertically
integrated transmission owners and operators continue to use their interstate
transmission facilities in ways that inhibit competition in wholesale power markets
as well as competition in those retail power markets where states have adopted
retail choice. The discriminatory
preferences that these transmission owners and operators give to their own uses
of the interstate transmission grid to serve their retail customers (whether or
not they are in retail choice states) results in discrimination against, and in
costs being borne by, other wholesale and retail customers who also rely on the
interstate transmission facilities to buy power. The discriminatory preferences also create barriers to new sellers
that could provide lower-cost power.
This could result in higher prices to the native load served by the
transmission owner. For example,
transmission-dependent utilities30 and
other load-serving entities need the interstate transmission facilities to move
power they are purchasing by contract from distant generators or suppliers, but
allege that despite the requirements of Order No. 888, they are denied
comparable access to the grid.
Similarly, new generators wishing to compete in wholesale markets or for
retail customers in retail choice states tell us that they are denied
comparable access to the grid, thus inhibiting entry of new, lower-cost,
efficient and environmentally superior power suppliers.
2. The Commission recently has taken
additional steps to address some of the remaining impediments to
non-discriminatory transmission access and competition in wholesale power
markets. For example, the Commission's
recently issued Generator Interconnection proposed rule seeks to remove one
particular type of undue discrimination occurring in the marketplace – barriers
to obtaining interconnections to the interstate transmission grid – so that new
generators can compete with vertically integrated transmission providers to
serve load.31 However, this initiative will resolve only
one aspect of remaining discriminatory practices. Other opportunities for vertically integrated transmission
providers to operate in ways that favor their own generation remain within the
construct of the pro forma tariff (e.g., preferences for
native load and network customers to reserve transmission capability, differing
transmission services that raise barriers to competition, the lack of inclusion
of all services under the same tariff).
As noted in Order No. 2000, "perceptions of discrimination are
significant impediments to competitive markets. Efficient and competitive markets will develop only if market
participants have confidence that the system is administered fairly."32
3. Furthermore, it has become apparent
that there are also opportunities to discriminate and to hinder an efficient,
competitive marketplace due to the absence of standardization with respect to
market rules and practices within and between regional markets. So-called "seams" problems (e.g.,
different rules and different pricing systems)
create transaction costs and artificial barriers to trade. These problems inhibit the Commission from
fulfilling its statutory responsibility to ensure that customers receive
reliable power supplies at the lowest reasonable costs.33
4. Finally, innovation that the
Commission expected to see with respect to new service offerings has been
sporadic and unsteady. Innovations in
transmission control and pricing (e.g., ISO control of transmission and
LMP for generation and transmission services in the Northeast, RTO formation in
the Midwest), while impressive, have been slow to take root in other regions of
the country. The pro forma
tariff was envisioned as the baseline above which transmission providers were
encouraged to develop competitive and customer-responsive service
offerings. But Florida Power
Corporation's network contract demand service, a hybrid of Network Integration
Transmission Service and Point-to-Point Transmission Service features,34 and Duke Energy Corporation's "recallable
long-term firm" service35 are
the only noteworthy new services accepted by the Commission for use with a
single utility's open access transmission tariff. Other proposed pro forma tariff revisions amounted
to little more than working around the edges of the existing services and
procedures and did not produce more competitive transmission service that
reduces overall electricity costs.
5. Most ISOs recently introduced
centralized short-term real-time hourly markets and day-ahead markets for
energy (i.e., spot markets) where sellers sell into the market and
buyers buy from the market without matching a particular seller with a
particular buyer. In such organized
spot markets, there is a single market clearing price established that is
received by all generators who bid into the market below that price and is paid
by all load that bids in above that price.
However, the ability of customers to bid demand reductions into the spot
market in response to supplier prices is still limited and needs to be improved
significantly for short-term markets to operate more competitively. Further, while there have been benefits of
market development in the Northeast (PJM, New York ISO, ISO-New England), Texas
and California (during the first two years of its restructuring), the Midwest
ISO is still in the formative stages of operation with respect to markets, and
few market benefits have materialized in the Southeast and West.
B. Specific Instances of Undue
Discrimination and Impediments to Competition
6. The specific reasons for requiring
reform are many. Market participants
have identified, through formal complaints, hotline calls, public conferences,
and pleadings, the difficulties they have experienced in gaining equal access
to the transmission grid to compete with vertically integrated utilities to
serve load. Much of this problem is
directly attributable to the remaining ability of such vertically integrated
utilities (and the existence of sufficient incentives) to exercise some degree
of transmission market power in order to protect their own generation market
share. Further complicating
transmission access is the fact that not all transmission service is provided
under the rates, terms and conditions of the Commission's pro forma
tariff. Rather, over 60 percent of load
has been subject to various state rules governing the transmission component of
bundled retail transactions.
Independent transmission service under a common set of rules would solve
many of these problems.
7. Nevertheless, new problems have been
created by some of the market design experiments. In regions of the country where the separation of transmission
from generation has been addressed through the creation of ISOs (which, in some
instances, have placed nearly all load under a single tariff), market design
flaws create inefficiencies in the marketplace and opportunities for the
exercise of market power. Conflicting
market rules and procedures in neighboring ISOs have created or perpetuated seams
problems that impede the economic flow of power from one region to
another. All of these problems have
hindered the progress towards competitive regional electricity markets. Standard Market Design is intended to
address these problems.
1. Transmission Market Power by
Utilities that are Not Independent
8. By differing means, Order Nos. 888 and
2000 attempt to effect open access transmission by reducing the ability of
transmission owners that also own generators to act in anticompetitive or
unduly discriminatory ways against other generators. In both orders, the Commission attempted to move the electric
industry into a competitive wholesale market without mandating corporate
restructuring. Through Order Nos. 888
and 2000, the Commission required open access to public utility transmission systems,
encouraged the formation of ISOs and, later, RTOs to achieve control of the
transmission grid by entities that are independent from generation marketing or
sales. However, only limited portions
of the country have moved beyond the basic requirements of open access (e.g.,
through the voluntary divestiture of generation or establishment of RTOs, ISOs,
or ITCs). In the rest of the country,
the remaining corporate ties between generation and transmission within public
utilities have proven problematic for transmission access. Thus, across most of the nation, barriers to
entry remain for new generators and new load-serving entities.
9. A large portion of this problem is
directly attributable to the continued ability of vertically integrated
transmission providers to exercise some degree of transmission market power to
advantage their own or affiliated generation.
The longer the vertically integrated transmission provider can use
access to interconnection or transmission service to delay or prevent entry of
competing generators to its service territory, the longer it can profit from
its own generation sales with a limited threat of competition. Vertically integrated transmission providers
have found numerous ways to delay or prevent entry of competitors, some within
the existing rules and some by exceeding reasonable discretion afforded to the
transmission provider. All of these are
difficult to monitor or prevent with behavioral rules.36
10. As part of Standard Market Design, we
propose that an Independent Transmission Provider operate all transmission
facilities. The requirement for
independent control of the transmission grid, preferably by an RTO, resolves
these types of problems.
a. Load Growth
11. Under the current pro forma
tariff, a transmission provider is required to plan its system to allow
customers with existing long-term contracts to extend, or roll over, those
contracts.37 However, the transmission provider has a
right to recall that transmission capacity if it identified in the initial agreement
with the customer that it had projected native load growth that would require
that transmission capacity.38 Transmission providers have failed to
identify any native load growth at the time of the initial agreement, and
disputes have arisen with customers claiming they were denied the ability to
roll over their contracts because the transmission provider claimed, well after
the contract was executed, that the transmission capacity at issue was required
to serve native load growth.39
12. In Standard Market Design, we propose to
eliminate the preference for future native load growth. Instead, since Congestion Revenue Rights
will be used to assure price certainty, Congestion Revenue Rights will be
apportioned based on historical use or by an auction, neither of which grants
preference for future load growth by a particular supplier; this approach
resolves these concerns.
b. Delays in
Responding to Requests for Service
13. Another type of anticompetitive
behavior centers on a vertically integrated transmission provider delaying the
processing of a competitor's request for new transmission service or
interconnection (including the related system impact or facilities
studies). Transmission providers have
done so by failing to follow time lines or expansively interpreting the tariff
procedures. These delays may be enough
to cause the competing generator to lose the sale, particularly if the
potential customer is concerned that it may lose service completely if it does
not stay with the transmission provider.40
14. Under Standard Market Design, these types
of delays are resolved through the requirement for an independent entity,
preferably an RTO, to perform studies and calculate available transfer
capability (ATC),41
since an independent entity would have no incentive to favor one customer over
another.
c. Scheduling Advantages
15. A vertically integrated transmission
provider has a structural advantage over many competitors to make economy sales
or to serve its own load, primarily because it has a large portfolio of both
generators and loads. A competitor with
access only to generation outside of the control area and no native load has to
identify the delivery point of its power before being able to secure transmission
service. But a vertically integrated
transmission provider does not have to identify a specific location on the grid
to serve its load because its load is dispersed across its entire system. A vertically integrated transmission
provider also does not have to identify a single generation location, but can
run a combination of its own generators or purchase from lower cost-suppliers
inside or outside of its system. It can
schedule purchased power to one of its own loads (in place of power from one of
its own generators) in order to secure transmission service for the
purchase. Later, it can find a buyer
for the power and schedule transmission service from one of its internal
generators to the load. This often is enough
of a scheduling advantage over a competing supplier to ensure that the transmission
provider (or its affiliated power marketer) gets the sale.
16. While it is true that all network
customers have these same rights and abilities, in many areas of the country
the only customer using network service is the vertically integrated transmission
provider. Moreover, the vertically
integrated transmission provider's size of resources and loads is usually much
greater than any other network customer, giving it that much more of an
advantage in flexibility. In addition,
the vertically integrated transmission provider may have an advantage through
access to better or more transmission and other related information.
17. Under Standard Market Design, all
transmission service will be provided under a new Network Access Service. Having one service for all customers will
eliminate scheduling advantages of competing suppliers.
d. Imbalance Resolution
18. Customers have also alleged that
vertically integrated transmission providers have an advantage over competitors
in the resolution of energy imbalances.
Transmission providers with generation and load of their own can resolve
their own energy imbalances through in-kind energy exchanges with neighboring
systems. In contrast, other customers
of the transmission provider face higher costs if they take service from other
suppliers that could balance against each other. This difference gives the transmission provider a competitive
advantage over other sellers of power.
19. Under Standard Market Design, all
suppliers and loads on a system will resolve imbalances through the same energy
imbalance procedures. This will remove
any competitive advantage the transmission owner with its own generation and
load may have over competing power suppliers.
e. Available Transfer Capability and Affiliates
20. Another source of discrimination is
the calculation of Available Transfer Capability. A transmission provider that is not independent calculates its
Available Transfer Capability, using its own proprietary data and its own equations. This discretion gives it the ability and the
opportunity to discriminate in its own favor against entities that rely upon
the OASIS for Available Transfer Capability information. In several cases, the Commission has found
that utilities' OASIS postings reflect an inaccurate Available Transfer
Capability. Indeed, in response to
"serious concerns about the integrity of the postings of ATC" on the
OASIS systems of two transmission providers, the Commission required the
transmission providers to employ an independent third party to administer their
OASIS systems.42
21. Under Standard Market Design, an
independent entity will calculate Available Transfer Capability and schedule
transmission service. This will
eliminate this potential for undue discrimination.
f. OASIS Postings
22. Manipulation or violation of OASIS
posting requirements and the Commission's standards of conduct is another way
vertically integrated transmission providers that control their own OASIS sites
are able to engage in undue discrimination.
This can occur through prohibited off-OASIS communications between the
transmission provider and its affiliated market participant, e.g.,
informing only the affiliate about Available Transfer Capability that will soon
become available and posted on the OASIS so that the affiliate will be first in
line to claim the capability.43 Such abuses reinforce our belief that, in
the absence of an independent entity calculating Available Transfer Capability
and operating a transmission provider’s OASIS, "a transmission provider's
self-monitoring of its standards of conduct is not sufficient, and that it is
essential for interested parties to be able to participate in this
process" of reviewing communications between market participants.44 Further, even
with the best of intentions, it is not possible for a single transmission
provider in a region to calculate Available Transfer Capability on its system
alone without accounting for the transactions over all the other systems in its
region and neighboring regions.
23. Similarly, control over the design,
function and maintenance of OASIS systems may also present opportunities for
discrimination. The Commission has been
concerned for some time that transmission providers have the ability to impede
competition by making their OASIS sites difficult to use, limiting users'
access to OASIS and limiting access to information about transmission
curtailments and interruptions that would allow the Commission to identify
instances of undue discrimination.45
24. Under Standard Market Design, an
independent entity will operate an OASIS on a regional basis, and thus will
remove any advantages one seller may have over another and improve the accuracy
of regional Available Transfer Capability postings on the OASIS.
g. Capacity Benefit Margin Manipulation
25. The Commission has found instances of
transmission providers taking advantage of their ability to reserve interface
capability to serve their own load while limiting the ability of competing
suppliers to access customers on its system.
For instance, transmission providers have reserved excessive amounts of
capacity benefit margin (CBM) to serve their own load,46 and violated the pro forma tariff by
reserving large amounts (e.g., 2,000 MW) of transfer capability at
multiple interfaces, under the label of "firm import for native
load," without designating resources or loads associated with the
reservations as other transmission customers are required to do.47 Import
capability reserved by the transmission provider blocks a competing supplier
from securing firm service across the interface, limiting that supplier’s
ability to compete to serve load on the system, or on neighboring systems. A related issue is whether those who set
aside transmission for CBM are reserving it and paying for it under the terms
of the pro forma tariff.
When transfer capability for CBM is set aside for the use of one market
participant, its cost is not necessarily allocated to that market participant
alone. Because transmission facility
embedded costs are allocated to transmission customers on the basis of use –
capacity reservation for Point-to-Point Transmission Service customers and load
ratio share (which does not include the transmission capability set-aside of
CBM) for Network Integration Transmission Service customers – all customers may unfairly subsidize the
cost of the CBM capability.
26. Under Standard Market Design, entities
that want to reserve transfer capability must pay for that capability to reach
generation reserves across an interface.
Thus, the preferential treatment would be eliminated.
h. Discretionary Use of Transmission Loading Relief
27. The opportunity for anticompetitive
behavior arises when transmission providers have discretion to dispatch their
own generation to serve their own load in a way that requires transmission
service curtailments through the use of transmission loading relief (TLR)
procedures.
28. There has been a sharp increase in the
number of TLRs used in some regions, suggesting that transmission operators
rely upon them to do more than simply relieve emergency transmission overloads.48 There are
unmistakable financial incentives to rely on TLRs in forward transmission
planning:
The
increased incidence of TLRs may suggest that some transmission capacity is
being oversold. Market participants
have attributed a tendency to implement a greater number of TLRs to the
commercial reality that transmission providers do not have to refund
transmission reservation fees for service curtailed because a TLR is called.[49]
29. When a vertically integrated transmission
provider injects power from its own generation onto its own power lines to meet
the constantly shifting demands of the load on its system, it has both the
opportunity and the incentive to manipulate the transmission system for its own
benefit. It can either dispatch
generators to create a transmission constraint that prevents a competitor from
making a sale that the transmission provider would also like to make, or it can
capitalize on legitimate constraints into a load pocket to curtail a competitor's
transmission transaction and serve the customer with its own generation
instead. The key here is that none of
the transmission provider’s actions require direct communication with its
merchant function or marketing affiliate.
A simplified hypothetical example of such anti-competitive behavior is
set forth in Appendix C.
30. Several aspects of our proposed
remedy address this concern, including the use of LMP to manage congestion and
the requirement that transmission facilities be operated by an Independent
Transmission Provider.
2. Lack of Common Rules Governing
Transmission
31. Some of the difficulties that come from
having different rules as power moves across the grid are discussed later in
the Seams Problems Section III.B.4), where a "seam" is a dividing
line between different sets of grid rules.
32. Having two or more different sets of rules
governing the operation of a transmission system makes it difficult – if not at
times impossible – for that system to support an efficient regional electric
power market. If the interstate
transmission system is to provide fair and efficient movement of power on
behalf of all users of the system, the same general rules must govern such
matters as who gets service, who has the right to transmission service when not
all service requests can be accepted, how the transmission facility costs are
allocated among transmission customers, who gets its transmission curtailed and
by how much when a transmission outage prevents all the planned services from
being accommodated, who plans the additions to the grid and who pays for these
additions.
33. Today there are not only different rules
in different public utility systems, but there may be more than one set of
rules for transmission owned by a single utility. This is because there are different rules for two types of
wholesale transmission service, and the rules for bundled retail transmission
service may differ from the rules for wholesale and unbundled retail
transmission services.
34. The Commission established an open access transmission
tariff under Order No. 888 that provides for two distinct types of wholesale
transmission services – Network Integration Transmission Service and
Point-to-Point Transmission Service.
Network Integration Transmission Service was designed primarily to meet
the needs of the transmission customer that wants to integrate many generators
and many loads at diverse locations on the public utility's grid; it was
intended to be comparable to the service that the public utility provided to
its own bundled retail customers.
Point-to-Point Transmission Service, as the name implies, was designed
primarily for the customer that wants to move power from one discrete location
to another.
35. At the time Order No. 888 issued, the
Commission recognized the potential for problems with having two wholesale
services that could not be truly equal, especially the problem of dealing with
claims of undue discrimination between the services. Consequently, along with the issuance of Order No. 888 the
Commission proposed a rule to create a new tariff, called the Capacity
Reservation Tariff.50 It was intended to remedy the anticipated
problems by establishing a new tariff that would replace the two wholesale
services with one. The Commission
received many comments on the proposed rule and held a technical conference
with representatives of diverse stakeholders.51
36. Some parties expressed concern about
moving quickly to a single service based on the Capacity Reservation Tariff
model, while other parties asserted that, although a single tariff reducing the
two services to one was a good policy, there were problems with the particular
Capacity Reservation Tariff that was proposed.
They recommended that the Commission delay acting on the proposed rule
until it learned the best form of single service tariff through industry
experience with open access. This is
the approach that the Commission in effect followed. Since the two Order No. 888 services were adopted, however, there
have been allegations of undue discrimination between customers of the two
services as discussed later in this section.
37. There are also different rules for bundled
retail transmission service and for wholesale and unbundled retail transmission
services. States have historically
established the rules for the transmission component of bundled retail
transactions, while the Commission has established the rules for wholesale and
unbundled retail transmission services.
38. Despite the requirement in Order No.
888 that no transmission customer may have any undue advantage over another,
there remain real or perceived advantages for the customers of vertically
integrated transmission owners. In many
cases, the perceived advantage is one of Network Integration Transmission Service
over Point-to-Point Transmission Service, where Network Integration
Transmission Service is available to both bundled retail transmission customers
and wholesale Network Integration Transmission Service customers, while
Point-to-Point Transmission Service is taken primarily for wholesale transmission
by independent power producers and marketers.
39. Four prominent examples highlight the
alleged advantages that a public utility's bundled retail customers have over
wholesale and unbundled retail customers.
First, certain reliability practices related to keeping the transmission
system balanced may allow a public utility that is responsible for keeping
generation and load in balance to obtain lower costs for its own power
customers. Second, a transmission-owning
public utility may have more de facto flexibility to designate
transmission receipt and delivery points than other transmission customers, if
that public utility also provides power to customers on its transmission
system. Third, the bundled retail customers
of a transmission owner may have certain transmission reservation and pricing
advantages regarding transmission transfer capability set aside for
reliability. Fourth, state transmission
curtailment rules that favor a public utility's bundled retail customers may
conflict with the Commission's transmission curtailment rules, resulting in a
transmission preference to customers in one state over customers served in
other states.52 The first three of these were summarized
above, and a detailed discussion with examples is set forth in Appendix C.
40. The requirement for all services on the
transmission grid to be taken under a common set of rates, terms and conditions
will resolve these concerns.
3. Congestion
Management
41. Due to new transmission usage patterns and
the lack of transmission infrastructure improvements, congestion has
increased. However, economically sound
congestion management plans do not exist in most parts of the country, and
transmission customers have been exposed to transmission service interruptions
and increasing generation costs due to the risk of interruption. The operating rules that do exist were not
designed as a congestion management tool for allocating scarce transmission
capacity, but were designed to keep facilities from overloading in an
emergency, such as when a transmission facility unexpectedly goes out of
service.
42. Currently, under the existing pro
forma tariff, congestion is managed primarily through a system of
physical reservation of capacity, based on each individual transmission
provider's calculation of the Available Transfer Capability of its grid, a
calculation often made without knowledge of the power flows on its grid that
result from transactions scheduled over other grids in its region. Under the current pro forma
tariff, customers reserve capacity on either a firm or non-firm basis,
based on the assumed contract path that the transaction will use. Once the customer has reserved capacity on a
firm basis, it is supposed to receive certainty both that power will be
delivered and the price that the customer will be charged for
transmission. If the customer has
non-firm capacity, it has no certainty that capacity will be available to
deliver power, but does know that there will be no congestion charge if the
delivery does occur.
43. The existing pro forma
tariff also provides that the redispatch of a transmission provider's
generating units to relieve congestion is required only if it can be achieved
while maintaining reliable operation of the transmission system in accordance
with prudent utility practice. The
recovery of the higher generation costs resulting from such generator
redispatch, which are a subset of opportunity costs, requires that (1) a formal
generator redispatch protocol be developed and made available to all
transmission customers and (2) all information to calculate redispatch costs be
made available to the customer for audit.
If a transmission provider collects revenues to cover the redispatch
costs from a specific transmission customer, it must credit these revenues to
the cost of fuel and purchased power expense included in its wholesale fuel
adjustment clause. Various tariff
provisions specify how redispatch is to be implemented. For instance, Sections 33.2 and 33.3 of the
existing pro forma tariff provide that the redispatch of all
network resources and the transmission provider's own resources, on a
least-cost basis without regard to ownership, is to be performed only to
maintain system reliability, not for economic reasons. Under those circumstances, the redispatch
costs would be shared among the network customers and the transmission provider
on a load ratio basis. Sections 13.5
and 27 of the existing pro forma tariff permit the transmission
provider to provide the requested transmission service and relieve a system constraint
by redispatching the transmission provider's resources: (1) if this costs less than constructing
network upgrades; and (2) if, under Section 13.5, the transmission customer
agrees to compensate the transmission provider for any such redispatch costs on
an incremental basis as specified in the customer's service agreement prior to
the commencement of service.
44. Although the existing pro forma
tariff allows the recovery of generating unit redispatch costs, the Commission
generally has not accepted proposals submitted by single-utility transmission
providers to recover such costs. For
instance, the Commission rejected Bangor Hydro-Electric Company's (Bangor
Hydro) proposed formula to recover opportunity costs for lack of supporting
data showing that its opportunity cost pricing would be consistent with the
principle of comparability and because the formula lacked sufficient detail to
operate as a rate formula itself.53 The
Commission directed Bangor Hydro to submit a separate section 205 filing with revised
opportunity cost pricing before implementing such pricing. The Commission also rejected a proposal by
the operating companies of Central and South West Corporation (CSW) regarding
redispatch costs because they did not provide sufficient specificity to enable
a customer to calculate or verify redispatch costs and because the formula
lacked sufficient detail to operate as a formula rate.54 The
Commission also directed CSW to submit a separate filing under section 205
before implementing such pricing.
45. Because it is difficult for a
single-utility transmission provider to develop a formula that specifies the
costs of redispatch and protects transmission customers' interests, generation
redispatch has not been used as extensively as it could be used to relieve
congestion. A transmission provider
will not redispatch generating units if it cannot collect its higher generation
costs, and less transmission transfer capability will be available to the
energy market.
46. In
1998, the Commission called on public utilities to work with the North American
Electric Reliability Council (NERC) to develop a congestion management system
based on redispatch.55 NERC responded with its pilot Market
Redispatch program that relied on counterflow transactions, i.e., power
transfers against the prevailing flows on the constraint, to relieve the
congestion.56 Although the program has been in place for
several years, it has been implemented only infrequently because of the
difficulty in establishing counterflow transactions and the limited
availability of data to the transmitting customer.57
47. In 1998, Commonwealth Edison Company
(ComEd) proposed a similar voluntary redispatch program, which predated NERC's
Market Redispatch Program.58 In November 1998, ComEd submitted the first
of two interim reports to the Commission summarizing its experience with the
program.59 It determined that a single utility cannot
effectively offer redispatch over other systems, especially where other
generation owners do not participate.
48. The overall result of the Order No. 888
congestion management system is that the transmission system is not utilized in
the most efficient manner. Customers
can be denied access to lower-cost supplies that could be made available if the
congestion management and pricing system had an efficient and fair method of
recovering the cost of generator redispatch.
49. Managing congestion using an LMP
system, coupled with a single transmission service that relies on price (rather
than first-come, first-served) to allocate limited transmission capacity, will
resolve these problems.
4. Seams
Problems
50. A lack of common transmission rules
inhibits competition in power markets not only when there are different rules
for different customers under one public utility's tariff or one RTO's tariff,
but also when there are different rules from one public utility to the next, or
from one RTO to the next. The term
"seam" has come into common use in the electric power industry over the
last several years to refer to a boundary between areas with different
transmission or other market rules.
Market participants assert that it can be difficult to move power
"across a seam" from one area to another.
51. Seams issues include differences in
transmission rules as well as differences in power market rules. They include such diverse matters as
different operating rules (e.g., rules for recalling firm transmission
capacity; coordination of generation and transmission maintenance schedules;
how parallel path flows are determined to affect other regions); different
market rules (e.g., bidding rules; market product definitions);
different market designs (e.g., congestion management procedures; demand
response rules; market price intervention practices); different business
practices (e.g., scheduling practices; reservation practices; OASIS
designs; processes to verify transactions between ISOs and market participants;
transmission and generation outage information dissemination, compensation, and
coordination rules; generation interconnection practices; liability
provisions); and different electronic and telephonic communications protocols.
52. Market participants have called for
a "seamless market," by which they mean a market whose operation is
not encumbered by differences in rules at public utility or RTO
boundaries. To achieve a seamless
market, some assert that rules may differ but only in ways that the differences
are invisible to power sellers and buyers.
Others assert that such management of differences rarely works in
practice and that the rules must be the same everywhere to achieve a seamless
market.
53. The Commission has long recognized
the need for more coordination and uniformity throughout a region in
transmission matters. Our Regional
Transmission Group Policy Statement of 199360 encouraged public utilities to develop a common set
of rules for regional expansion planning, and our Transmission Pricing Policy
Statement of 199461
encouraged the development of a common pricing policy for a region that would
internalize and rationalize the pricing of parallel path flows. As explained above, Order Nos. 888 and 2000
recognized the need to bring the various public utility transmission systems in
a region under a common set of transmission rules. Order No. 888 not only applied a common set of open access
transmission rules to public utility transmission systems, but included a
reciprocity provision that conditioned a non-public utility's use of a public
utility's open access transmission tariff on the non-public utility's agreement
to provide comparable transmission service to the public utility. Indeed, Order No. 888 also encouraged the
formation of ISOs not only to bring all the transmission systems in a region
under common rules, but also under unified operation. Many parties in Canada have stressed the necessity of having a
common set of rules for reliability and trading protocols for cross-border
transmission facilities.62 Order No. 2000 built on this theme by
strongly encouraging the formation of RTOs to bring all facilities in a region
under a common set of transmission rules.
However, RTOs have not developed at the pace anticipated when Order No.
2000 was issued and seams problems continue to exist. In June 2001, the Commission held a technical conference on seams
issues.63 Participants to the seams conference
explained that resolution of seams issues is critical for making the inter-RTO
transmission systems and power markets work.
54. We set forth in Appendix C a number of
examples of differences in rules that can create seams problems, and a
discussion of efforts at the Commission or within the industry to address seams
problems.
55. The requirement under Standard Market
Design for a single tariff and a single market design operating with the same
set of rules throughout the entire interconnection resolves the seams problems
discussed above.
5. Market
Design Flaws
56. Poorly designed market rules, or market
rules with unforeseen or unintended consequences, can have a debilitating
effect on markets, market pricing and overall confidence in the markets of the
market participants. Moreover,
differences in market designs in neighboring regions can also lead to problems
such as the exercise of market power through the exploitation of the
differences.
57. Wholesale electricity markets are
complex, with multiple products traded at multiple locations on different
time-frames, while subject to the unique physical characteristics of
electricity (e.g., non-storable, need for system stability and
balancing, physics of power flows).
Market rules have been affected by the variation in generation mix,
the transmission network layout and the local and regional regulatory history
in different regions of the country.
For example, the initial California markets had a design quite different
from the designs of the markets in the Northeast region (PJM, New York and New
England).
58. In the regions where voluntary, organized
ISO markets for energy, transmission and ancillary services have been
established under the existing tariff, problems due to the design choices have
been characterized as "market design flaws." A market design flaw is a market rule –
including product specification, bid format, auction rules and pricing rules –
that allows distortions in the market prices or availability of a product or
service, whether energy, ancillary services, transmission service or installed
capacity. In the years since the ISO
markets have been operating, dozens of market design flaws have been
identified, ranging from minor problems that cause temporary inconveniences to
major problems that require markets to be re-designed. No region has been exempt from market design
flaws of one type or another. We
set forth in Appendix C examples of specific design flaws.
59. These problems have resulted in markets
that are inefficient and do not produce the lowest reasonable prices for
electric power. These problems cannot
be resolved on a case-by-case basis because that will maintain and exacerbate
the problems due to local differences in rules. Only standardization of electricity market design will solve
these problems. In the parts of the
country in which markets are most mature, including the Northeast, Midwest and
California, there is broad consensus on the principal elements of market design
and business practices. A standard market
design rule will help advance this process and extend it to other regions. Our goal is to use the Standard Market
Design rulemaking to address and remedy many of the market design flaws
identified to date and to raise the quality of all electric markets
simultaneously.
60. Market rules will need to be
flexible and have the ability to evolve over time. However, consistent rules across the entire interconnection based
on best practices, coupled with sound market monitoring to promptly identify
and correct any design flaws will provide the necessary foundation for future
market innovation and improvement.
C. Reform Essential Given the Changed
Nature of the Electric Industry
61. The need to address the instances of
discrimination described above is all the more critical given the changing
nature of the electric industry. The
United States electric power industry is in the middle of a transition from a
predominantly monopoly industry to a predominantly competitive industry. The fundamental economic driver of change
has been, and continues to be, the reduction of economies of scale in new
generation construction, combined with environmental restrictions that
encourage gas-fired units. This is due
in large part to the introduction during the 1980s of highly efficient gas
turbines and combined cycle generators that produce much more electricity from
a given amount of gas. A relatively
small gas-fired generator can compete effectively with power from a large
central generating station.
Additionally, small distributed generation is becoming economic, and
some renewable energy resources, especially wind power generation, are also on
the verge of becoming competitive.64 In the right
locations, wind generating units can compete with the much larger coal, nuclear
and hydroelectric units.65
62. Because of these fundamental changes
in industry technology, small producers of electricity can compete with large
producers, and both the smaller utilities and the retail customers of a number
of utilities have demanded access to competing power suppliers in hopes of
lowering their electric bills, improving service and harnessing new
technologies. The pressures for retail
access have been greater in regions with higher rates, which are typically
regions with few low-cost natural resources for generating electric power, such
as nearby coal mines, gas fields, and hydroelectric areas.66 Many of these
regions have taken the lead in retail restructuring, while regions with
historically low electricity production costs have proceeded more cautiously or
even affirmatively decided not to change their retail access policies or to
support their local utilities' participation in regional programs at this time.67
63. One hallmark of electric industry
restructuring has been the growth of wholesale trade. In the past, wholesale power purchases made up a small fraction
of a large vertically integrated utility's power supply, with most of its power
needs met by its own generation. Today,
however, even large vertically integrated utilities rely increasingly on
wholesale purchases for their energy supplies.
For example, as shown in Table 1, between 1989 and 2000, generation by
investor-owned utilities grew from 2,132 thousand GWh to 2,230 thousand GWh, an
increase of less than 5 percent. During
this time, wholesale power purchases by these utilities almost tripled. Table 1 also shows that in 1989 wholesale
power purchases provided 18 percent of the total electric energy available to
investor-owned utilities from both wholesale purchases and their own
generation. By 2000, wholesale
purchases provided over 37 percent of investor-owned utility electric
energy. This percentage has steadily
increased since 1989, and is expected to continue to grow as utility-owned
plants are sold or retired and new power supplies are acquired competitively in
most parts of the country.
|
Table
1. Investor-Owned Utilities' Total
Purchases, 1989 - 2000, As a Percentage of Energy
Purchased and Self-Generated |
|||
|
Year |
IOUs' Purchases |
IOUs' Generation |
Purchases (Purchases + Generation) |
|
|
(GWh) |
(GWh) |
(%) |
|
|
|
|
|
|
1989 |
460,627 |
2,132,065 |
17.8 |
|
1990 |
530,325 |
2,134,429 |
19.9 |
|
1991 |
635,015 |
2,145,435 |
22.8 |
|
1992 |
671,758 |
2,143,847 |
23.9 |
|
1993 |
718,876 |
2,216,724 |
24.5 |
|
1994 |
732,710 |
2,237,652 |
24.7 |
|
1995 |
786,676 |
2,269,958 |
25.7 |
|
1996 |
916,087 |
2,308,156 |
28.4 |
|
`1997 |
1,080,538 |
2,321,225 |
31.8 |
|
1998 |
1,073,638 |
2,402,571 |
30.9 |
|
1999 |
1,083,892 |
2,353,639 |
31.5 |
|
2000 |
1,324,558 |
2,229,617 |
37.3 |
|
|
|
|
|
|
]Source: RDI POWERDAT Database |
|||
Note: Data for
2001 is not yet available.
Investor-owned utility purchases include purchases from affiliates.
1. Table 1 demonstrates the increasing
importance of competitive wholesale energy acquisition in the United States
electric power industry, and the need for this Commission to ensure that
transmission, market rules and institutions are reformed as necessary to
support the new environment. It also
makes clear that a retreat from competitive markets to a cost-regulated
vertically integrated world would be difficult – the nation now depends
increasingly on wholesale interstate electricity markets.
2. Similar data are presented in Tables
2 and 3 for large public power utilities and generation and transmission
cooperatives that generate at least some of their own power.68 These tables
show that wholesale purchases, on average, provide about 40 percent of the
power needs of these large utilities.
Data are not presented for the smaller public power and cooperative
utilities because they typically do not self-generate but buy all of their
power at wholesale.
|
Table
2. Large Public Power Utilities'
Total Purchases, 1992 - 2000, As a Percentage of Energy
Purchased and Self-Generated |
|||
|
Year |
Utilities' Purchases |
Utilities' Generation |
Purchases (Purchases + Generation) |
|
|
(GWh) |
(GWh) |
(%) |
|
|
|
|
|