Federal Energy Regulatory Commission's Standard Market Design Activities

Federal Energy Regulatory Commission's Standard Market Design Activities

Order Code RS21407
January 31, 2003
CRS Report for Congress
Received through the CRS Web
Federal Energy Regulatory Commission’s
Standard Market Design Activities
name redacted
Specialist in Energy Policy
Resources, Science, and Industry Division
Summary
On July 31, 2002, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking (NOPR) on standard market design (SMD) that is
intended to remove the remaining impediments to competitive electricity markets. FERC
expects to issue a final rule in the summer of 2003. The SMD NOPR addresses
congestion management, long-term resource planning, day-ahead and spot market
design, and market monitoring and mitigation. Those in favor of the SMD NOPR argue
that it is necessary to eliminate discrimination in the transmission system and to create
competitive markets. Opponents argue in part that the NOPR would usurp state authority
by transferring aspects of transmission, resource planning, and retail rate design away
from the states. This report will be updated as events warrant.
Background
The electric utility industry has been in the process of transformation. During the
past two decades, technology improvements, changes in the economics for generating
electricity, and new federal laws and regulations have changed the nature of electric
generation and created wholesale markets for electricity. As a result, competition is
occurring on the wholesale level and more than half of the states are moving toward retail
competition. Between 1989 and 2000, wholesale trade of power nearly tripled to
represent 40% of the total electricity supply. Congress continues to face the issue of how
much to intervene to ensure that functioning markets are operating throughout the United
States.
As a result of a mandate in the Energy Policy Act of 1992 (EPACT),1 the Federal
Energy Regulatory Commission (FERC) issued Order 888 and its companion Order 889
in April 1996. These Orders required investor-owned utilities to open up their
1 P.L. 102-486.
Congressional Research Service ˜ The Library of Congress

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transmission systems on a nondiscriminatory basis to any power supplier.2 FERC
recognized that Orders 888 and 889 did not completely eliminate unfair discriminatory
business practices.
As a result, Order 2000 attempted to address remaining issues related to
nondiscriminatory access to the wholesale transmission system.3 The Order encourages
transmission owners to join Regional Transmission Organizations (RTOs) that would
maintain independent grid oversight and eliminate utilities’ ability to exert control over
transmission lines. FERC has approved three RTOS, the Midwest Independent System
Operator (MISO), RTO West and PJM Interconnection, LLC. Several other RTOS have
been conditionally approved by FERC.4
However, many have asserted that discrimination still exists in wholesale electric
markets and that a wholesale electric market design is needed to provide a level playing
field for all market participants. According to FERC, many recent cases demonstrate that
discrimination still occurs in the wholesale electric markets: Transmission owners favor
their own generation; inconsistent transmission rules exist that allow utilities to limit
some transactions while lowering costs for others; different tariffs and rules between areas
increase costs for interregional bulk power transfers; and vertically integrated utilities can
interrupt their competitors’ transmission transactions to address system reliability, while
protecting their own affiliates’ generation and transmission flows.5
Notice of Proposed Rulemaking
On July 31, 2002, FERC issued a Notice of Proposed Rulemaking (NOPR) on
standard market design (SMD) (Docket No. RM01-12-000).6 FERC’s stated goal of
establishing SMD requirements in conjunction with a standardized transmission service
is to create “seamless” wholesale power markets that allow sellers to transact easily across
transmission grid boundaries. Currently, seams issues occur when there are different
transmission rules and power market rules across a public utility or regional transmission
organization boundary. Under the SMD, bilateral contracts would form the basis of the
power market. These contracts would be supplemented with a spot market for energy and
ancillary services. The proposed rulemaking would create a new tariff under which each
transmission owner would be required to turn over operation of its transmission system
to an unaffiliated independent transmission provider (ITP). The ITP, which could be an
2 Order 888 can be found at: [http://www.ferc.gov/news/rules/pages/order888.htm].
Order 889 can be found at: [http://www.ferc.gov/news/rules/pages/order889.htm].
3 Order 2000 can be found at: [http://www.ferc.gov/news/rules/pages/RM99-2A.pdf].
4 A map of the RTO geographic boundaries as well as FERC RTO orders can be found at :
[http://ferc.gov/Electric/rto/post_rto.htm].
5 FERC SMD 101 Document,can be found at:
[http://ferc.gov/Electric/rto/Mrkt-Strct-comments/nopr/SMD101.pdf].
6 The SMD NOPR can be found at:
[http://www.ferc.gov/Electric/RTO/Mrkt-Strct-comments/nopr/Web-NOPR.pdf].

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RTO, would provide service to all customers and run energy markets. Under the NOPR,
congestion would be managed with locational marginal pricing.7
The NOPR comment period originally was 75 days (November 15, 2002), but the
comment period was extended to January 10, 2003, for the following issues:1) market
design for the Western Interconnection; 2) transmission planning and pricing, including
participant funding; 3) Regional State Advisory Committees and state participation; 4)
resource adequacy; and 5) Congestion Revenue Rights and transition issues. FERC
expects to release a White Paper in April 2003 that outlines public input to the NOPR.
The Final Rule is expected to be published in midsummer 2003.
Public Utility Commissioners from 19 states (Alabama, Arkansas, California,
Colorado, Georgia, Idaho, Kentucky, Louisiana, Mississippi, New Mexico, New
Hampshire, North Carolina, South Carolina, Oregon, South Carolina, South Dakota,
Tennessee, Virginia and Washington) have voiced opposition to FERC’s SMD proposal.
Most of the Commissioners’ concerns are on the grounds that FERC usurps state authority
by transferring aspects of transmission, resource planning, and retail rate design away
from the states.8 Other critics have asserted that the NOPR does not take into account
regional differences and sees the standard market design proposal as a “one-size-fits-all”
approach. As a result, these critics predict that the SMD would lead to the export of
cheap power to regions with higher electricity costs. FERC’s assertion of jurisdiction over
all transmission, including service to bundled retail customers, is based on the recent
Supreme Court decision in New York v. FERC.9
7 Locational Marginal Pricing determines electricity prices at each location (node) along the
transmission system based on bids of sellers and buyers at a particular time. Congestion prevents
the cheapest power from being transmitted to all nodes along the grid. At points of congestion,
prices will be higher. LMP manages congestion through economic dispatch: increasing energy
generation behind a constraint (where power is flowing to) and decreasing generation in front of
a constraint (where power is flowing from). Locational Marginal Pricing is currently used by
PJM and the New York ISO.
8 State Public Utility Commissioners and consumer advocates opposed to SMD have formed the
Alliance of State Leaders Protecting Electricity Consumers. Their website can be found at:
[http://protectpowerconsumers.org/index.htm].
9 On October 3, 2001, the U.S. Supreme Court heard arguments in a case (New York et al. v.
Federal Energy Regulatory Commission) that challenged FERC's authority under Order 888 to
regulate transmission for retail sales if a utility unbundles transmission from other retail charges.
In states that have opened their generation market to competition, unbundling occurs when
customers are charged separately for generation, transmission, and distribution. Nine states, led
by New York, filed suit, arguing that the Federal Power Act gives FERC jurisdiction over
wholesale sales and interstate transmission and leaves all retail issues up to the state utility
commissions. Enron argued that FERC clearly has jurisdiction over all transmission and FERC
is obligated to prevent transmission owners from discriminating against those wishing to use the
transmission lines. On March 4, 2002, the U.S. Supreme Court ruled in favor of FERC and held
that FERC has jurisdiction over transmission including unbundled retail transactions. The ruling
is available at:
[http://a257.g.akamaitech.net/7/257/2422/04mar20021030/www.supremecourtus.gov/opinion
s/01pdf/00-568.pdf].

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On August 15, 2002, state regulators from 22 states and the District of Columbia
(Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, Montana, North Dakota, Ohio,
Oklahoma, Texas, Wisconsin, Delaware, the District of Columbia, New Jersey, New
York, Pennsylvania, West Virginia, Connecticut, Maine, Massachusetts, New Hampshire,
and Rhode Island) released a statement that “voiced support for FERC’s ongoing effort
to remedy undue discrimination in the use of the nation’s interstate high voltage
transmission system in order to create a truly competitive bulk power market.”
Supporters argue that the SMD would make it easier and cheaper to transfer electricity
between regions, and prevent incumbent utilities from preventing access to transmission
lines that they own. In general, the industry has been in favor of FERC’s SMD proposal,
but some industry groups have voiced concerns about the implementation of SMD.
Selected Issues
Power Markets and Market Power Monitoring and Mitigation.10 FERC’s
concept of a Standard Market Design relies on bilateral contracts between buyers and
sellers to satisfy the bulk of electricity demand in a region. Under the NOPR, independent
transmission providers would be required to operate day-ahead and real-time energy
markets to handle generation imbalances and ancillary services.11 The ITP would
determine a single market-clearing price for energy, transmission service and ancillary
services at each node for the next day, based on bids. Ancillary services would be bid on
an hourly basis, while energy prices in the real-time market would be determined at each
node for each 5-minute period.
Under the Federal Power Act, FERC is charged with establishing just and reasonable
rates for electricity. Cost-of-service rate regulation has evolved to depend on market
forces to set prices. In an efficient market with many buyers and sellers who cannot
individually influence price, the value of additional supplies and conservation should be
reflected in the price. However, FERC recognizes that the electricity market has not
reached this stage. In the NOPR, FERC notes two significant structural flaws in the
current electricity markets: the lack of price-responsive demand, and generation
concentration in transmission-constrained load pockets. In the NOPR, FERC proposes
to create a Market Monitoring Unit (MMU) that would implement measures to
approximate an outcome that a competitive marketplace would produce. The MMU
would report directly to FERC as well as to each governing board of the Independent
Transmission Provider.
FERC proposes three mandatory components of market power mitigation as well as
a voluntary fourth measure to assure that market power does not result in high prices.
First, in areas where generators are concentrated and transmission constraints exist, the
ITP will enter into a participating generator agreement. Under such an agreement, the
generator would be required to provide all its available energy to the grid during specific
10 FERC defines market power as the ability to raise prices above the competitive level either
through physical withholding or economic withholding.
11 FERC proposes that Scheduling, System Control and Dispatch Services; Reactive Supply and
Voltage Control; and Energy Imbalance must be obtained from the ITP. Other ancillary services
that must be offered by the ITP include: Regulation and Frequency Response; Operating
Reserves-Spinning; and Operating Reserves-Supplemental.

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conditions identified in each agreement. In addition, each participating generator
agreement would specify a bid cap for the energy or ancillary services provided under
such conditions. Second, the spot market would be constrained by a safety-net bid cap
of $1,000 per megawatt hour. Third, the NOPR requires a resource adequacy requirement
(see following section). Fourth, during times when market power may be exerted, the
NOPR calls for a mechanism to determine whether high prices are the result of generators
withholding power.
Resource Adequacy. While most of the NOPR deals with the transmission
system, it also addresses the issue of a reliable supply of electricity. The NOPR addresses
the concern that a combination of a spot market and a price cap will not provide enough
incentives to invest in additional generating capacity. FERC proposes that resource
adequacy be determined on a regional basis and a 12% minimum reserve margin be
adopted.12 Historically, reserve margins for large utilities have averaged 18-20% and
utilities have determined their own reserve margin levels.13 While a 12% reserve margin
is considered by some to be too low to maintain a reliable electric system, the NOPR
requires that the Regional State Advisory Committee determine the appropriate reserve
margin for the region. FERC asserts that single-utility forecasting is inadequate and a
more regional approach needs to be taken. Any entity that uses the transmission system
would be required to satisfy a portion of the regional resources adequacy requirement by
self-generation, local distributed generation, or firm bilateral contracts for power that are
backed by specific generating units. FERC proposes to enforce the resource adequacy
requirement with both penalties and load curtailment.
Transmission Resource Planning. In addition to generation resource planning
taking place on a regional level, FERC proposes that transmission resource planning
would be a regional process. Regional planning is necessary, FERC asserts, because
certain issues such as loop flow cannot be addressed on the local level. Also, certain
transmission expansion projects that are needed to maintain reliability may not be
financially attractive to private investors.
The NOPR identifies three components of transmission planning. First, the
Independent Transmission Providers would establish a mechanism for regional
transmission planning that would include identifying all additional transmission needed
for both reliability and economic needs. Second, the ITPs would be required to issue
requests for proposals when a regional planning process identifies that additional
resources are needed. Responses to a request for proposals could include expansion of
the grid, addition of generation (including distributed generation), or the implementation
of demand response. If the bidding process is not successful, the ITP could require
transmission owners to expand or upgrade the transmission system. Although no formal
studies have been completed, the Environmental Protection Agency (EPA), in its
comments to FERC, expressed concern that the SMD’s encouragement of demand
12 The generating resources expected to be available during a period, less the forecast peak load
during that period, is the reserve. The reserve margin is defined as the ratio of the reserves to the
forecast peak load during a period, expressed as a percentage.
13 North American Electric Reliability Council. 2002 Summer Assessment: Reliability of the
Bulk Electricity Supply in North America. May 2002. Available at:
[ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/summer2002.pdf].

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response technologies to deal with congestion could increase overall emissions by
“providing economic incentives for operating high-emitting back-up diesel generators.”14
The third transmission planning component would require the ITP to determine if
any proposed projects could be combined to lower costs. For projects that would serve
an entire region, all ratepayers would pay for expansion of the transmission system.
Under the NOPR, FERC would allow participant funding of expansion projects if
the ITP could determine and assign costs to those that benefit from a particular project.
Those in favor of participant funding argue that it is necessary to prevent native load
customers from paying for transmission upgrades needed to export power out of the
region. Those opposed to participant funding argue that everyone benefits from
transmission upgrades by decreasing congestion and that it is virtually impossible to
assign costs associated with transmission upgrades.
Congestion Management. Congestion on the transmission system would be
managed with a combination of Locational Marginal Pricing (see footnote 7) and
Congestion Revenue Rights (CRRs).15 Transmission system congestion prevents the
cheapest power from reaching all locations on the grid where buyers want power
delivered. LMP is a market-based method for congestion management and depends on
the redispatch of energy to avoid constraints. The cost of redispatch is the basis for the
congestion charges under LMP. LMP’s effectiveness depends on complex software to
manage the markets.
CRRs is a system of financial rights to use the transmission system that is expected
to protect customers against congestion costs. The holder of CRRs would be able to
receive congestion revenues in a day-ahead market. Any congestion costs that holder pays
would be offset by its congestion revenue.16 FERC also expects CRRs to provide
incentives to regions to build necessary transmission capacity. Currently, utilities use a
physical reservation system to gain access to the transmission network. During a four-
year transition period, FERC proposes a flexible system either to allocate CRRs to
customers with the existing contracts or to auction such rights. At the end of the four-year
period, all Independent Transmission Providers would be required to auction their CRRs.
RTO West has expressed concern that the transition period may not be long enough
for certain regions and that the conversion to CRRs should be voluntary.17 On the other
hand, groups such as the Electric Power Supply Association (EPSA) and the Industrial
Energy Consumer Group argued at FERC’s December 3, 2002, Technical Conference
that auctions are critical to establishing a forward market to hedge against volatility.
14 Comments of the U.S. Environmental Protection Agency to FERC Docket No. RM 01-12,
FERC Accession Number 20021115-0345, November 15, 2002.
15 Congestion Revenue Rights were formerly known as Financial Transmission Rights (FTRs).
16 If the holder of CRRs does not schedule transmission service, it would still receive the
congestion revenues.
17 Comments of Rich Bayless, Director of Interconnected Systems, PacifiCorp (RTO West) at
FERC Technical Conference on SMD, December 3, 2002. Transcript is available at:
[http://ferc.gov/Electric/RTO/Mrkt-Strct-comments/NOPR/transcript-12-03-02.pdf].

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