Electric industry restructuring and its consequences seized the headlines in 2001.
When deregulation was first introduced to state and federal regulators in the
early 1990s, few imagined that the road to restructuring would turn into such
a roller coaster ride. Over the past year, blackouts in California and other states
kicked off the summer, then appeared to subside. Electricity prices skyrocketed
on the spot market. Market uncertainty continues as the economy slows. When the
huge energy price spikes and blackouts that had been predicted for the hottest
summer months failed to materialize and prices eased, the attempts to resolve
transmission issues were still continuing.

While at first electric industry restructuring appeared to be a way to offer lower
rates to consumers and less regulation for generators and utilities, it has profited
only some and bankrupted others. It has now become a political hot potato. Many
entrepreneurs and investors, who were looking to profit from new generation construction
are now on unsure footing. Independent power companies have witnessed their stock
valuations and public images decline. At the center of these issues is the development
of an organizational structure for transmission facilities.

Transmission is the key element of the structural changes being developed. Yet,
new transmission investment has been slowed by the uncertainty surrounding rates
of return and investment capital recovery. Whether the for-profit model or the
not -for-profit model works better is also uncertain. In this climate, the push
to create four Regional Transmission Organizations (RTOs) nationwide is clearly
the new direction at the changing Federal Energy Regulatory Commission.

This overview chronicles recent milestones of electric industry restructuring
related to Regional Transmission Organizations and relates them to the present
trends in order to bring the reader up to date.

Even more dramatic change is likely in the near future as the FERC is reconstituted
under a new administration — the new chairman of the FERC is in place and
we await the appointment of another commissioner by President Bush. Depending
upon that selection, we may see policy revisions regarding the specific nuances
of transmission structure. Will a consensus form about the new FERC directives
to create four giant RTOs? As of this writing, the question remains unanswered.

In the last years of the 20th Century, American corporations generally —
and energy companies in particular — strove to improve efficiency by taking
advantage of economies of scale. Service unbundling and deregulation initiatives
spawned new market entrants, some of whom recombined in an effort to remain viable
in a competitive environment. Some got it right, some failed and others are still
searching for solutions.

At the same time that traditional utilities became more comfortable thinking “outside
the box,” consumers, regulators, and non-traditional service providers had to
cope with the consequences of inconsistent pro-competitive policies. These consequences
included how to regulate conduct among affiliates, ensure fair and reliable system
management, determine consumer electric rates, minimize rate aberrations and maximize
reliability in abnormal (and often unpredictable) situations, recognize environmental
necessities, and whether and how to recover costs associated with inefficient
assets in the newly restructured market.

By 1999, it was apparent to both the regulators and the regulated that the newly
emerging “system,” such as it was, had holes. Reliability was less secure than
it should be. Letting the invisible hand of the markets determine the need for
services and the prices to be charged for them was nice in theory, but there was
not yet a solution to the problem of an imperfect market functioning imperfectly.

The Evolution of the Solution

The solution proffered by the FERC was Order No. 2000, which promoted the creation
of geographically vast Regional Transmission Organizations while trying mightily
not to recreate existing efforts to allow independent management and operation
of the North American power grid.

Order No. 2000 had its precursor in Order No. 888. Order No. 888-A and its electronic
information sidekick, Order No. 889-A, were issued in March 1997.

On June 30, 2000, the U.S. Court of Appeals for the D.C. Circuit affirmed Order
Nos. 888 and 889 in all important respects (Transmission Access Policy Study
Group, et al. v. FERC, No. 97-1715). On February 26, 2001, the U.S. Supreme
Court granted certiorari to review the D.C. Circuit’s decision. Nine state commissions
claimed that Order No. 888 exceeded the FERC’s jurisdiction under the Federal
Power Act (FPA) by extending it to the transmission portion of unbundled retail
electricity transactions. Enron Power Marketing contended that the commission
should have extended the requirements of Order No. 888 to bundled retail transmission
sales. The cases were consolidated for oral argument. (New York, et al. v. FERC,
et al., No. 00-568; Enron Power Marketing Inc. v. FERC, No. 00-809). Certainly
this appeal could greatly impact the FERC’s restructuring policies, as could
numerous legislative initiatives currently in Congress.

The Notice of Intent

Following up on comments made in discussion of market activity in California
and the Midwest during the summer of 1998, the FERC issued a Notice of Intent
in November 1998 to consult with the states about establishing RTOs under §202(a)
of the FPA. (Regional Transmission Organizations, Docket No. RM99-2-000, FERC
Stats. & Regs. 35,534). Section 202(a) is part of the interconnection and coordination
portion under the FPA, authorization for which was granted to the Federal Power
Commission when the statute was enacted in 1935, transferred to the Secretary
upon creation of the Department of Energy in 1977, and back to the FERC on October
1, 1998. Although its precise meaning has never been ruled on, §202(a) “empowers”
and “directs” the commission “to divide the country into regional districts
for the voluntary interconnection and coordination of facilities,” following
notice to the commission of each state in which such district is located.

The FERC’s consultative process with the states examined the following questions,
among others:
1. What criteria and policy considerations should be used to establish the boundaries
for effective RTOs?
2. What factors make it appropriate for a utility to belong in a specific region?

3. What is the appropriate role of the states in the formation and governance
of RTOs?
These important issues remain unresolved.

The Notice of Proposed Rulemaking

On May 13, 1999, the FERC issued a NOPR on RTOs that adopted the general principle
that transmission should operate independently of generation on a regional basis
(Regional Transmission Organizations, Docket No. RM99-2-000, 87 FERC 61,173).
The NOPR did not propose to dictate the business form of the organization nor
the boundaries within which RTOs could operate, and the FERC clearly wanted
to accommodate existing ISOs and RTGs. The FERC also characterized its initiative
as “voluntary” but believed that well-developed RTOs could alleviate a number
of real and potential shortcomings in present markets. These benefits include
improved grid reliability and market performance, more efficient grid management,
removing opportunities for discriminatory transmission practices, and facilitating
a lighter governmental regulatory role.

The Final Rule on RTOs

On December 20, 1999, the FERC issued a Final Rule on RTOs (Regional Transmission
Organizations, Docket No. RM99-2-000, 89 FERC 61,285). Like the NOPR, the Final
Rule took a “voluntary” approach to RTO participation, but the FERC made clear
that this approach does not preclude taking action to require RTO participation
as a remedy for undue discrimination or the exercise of market power.

Order No. 2000 required all public utilities that own, operate or control interstate
transmission facilities to file RTO proposals by October 15, 2000 or, alternatively,
to describe any efforts made by the utility to participate in an RTO, the reasons
for not participating, any obstacles to participation and any plans for further
work toward participation. With minor exceptions, the utilities submitted their
filings and many entities have made substantial progress to fulfill the FERC’s
mandate.
Order No. 2000 adopted a flexible approach to RTOs, permitting non-profit ISOs
and for-profit transcos, combinations of the two, or other as yet undetermined
approaches. It adopts the principle of open architecture, so that an RTO may
evolve over time. However, all RTOs must embrace the four core characteristics
and the eight key functions that are discussed below. The Order provided guidance
on flexible rate-making options for RTOs that address congestion pricing and
performance-based regulation and is the “Bible” of transmission philosophy today.

Under Order No. 2000, all RTOs must possess the following four characteristics:

Independence

RTOs must be independent of market participants. A “market participant” is
defined as any entity that, directly or through an affiliate, sells or brokers
electricity or provides transmission or ancillary services to the RTO, unless
the commission finds that the entity does not have economic or commercial interests
that would affect the RTO. This definition, which is used as a starting point
for establishing limits on ownership and standards for independent decision-making
or governance, is narrower than the NOPR proposed because buyers of electricity
are not automatically included (see §35.4(b)(2)). Order No. 2000-A revised the
definition to remove specific references to entities that provide transmission
service to an RTO. Order 2000 distinguished between “active” and “passive” ownership
interests, depending on the ability to control RTO operations. For “active”
owners, the de minimis “safe harbor” in the NOPR was increased to five percent;
however, all active voting interests, with limited exceptions, must be terminated
within five years. Passive ownership interests in RTOs can continue indefinitely
if they can be shown to be truly passive. Order No. 2000 modified somewhat the
proposed requirement that the RTO have the exclusive authority to file tariff
changes under §205 of the FPA. While the RTO has the independent and exclusive
right to make §205 filings that apply to the rates, terms and conditions of
service over the facilities that it controls and operates, transmission owners
retain certain §205 rights with respect to the level of revenue requirement
that they receive from the RTO (and which the RTO will collect from transmission
customers through the RTO’s rates). Thus, a transmission owner may have a tariff
on file that affects the level of the RTO’s revenue requirement, but the transmission
owner is not permitted to file tariff changes that will affect the RTO’s services
to transmission customers.

Scope and Regional Configuration

RTOs must serve a region of sufficient scope and configuration to permit the
RTO to maintain reliability, effectively perform its required functions and
support efficient and non-discriminatory power markets. The commission did not
attempt to draw RTO boundaries. If faced with multiple RTO proposals for a region,
the FERC would have to determine which would best meet their objectives. In
making a determination, the FERC would look to regional configuration factors,
i.e., the RTO’s ability to make accurate, reliable ATC determinations; resolve
loop flow issues; manage congestion; offer service at non-pancaked rates; improve
operations (e.g., a single OASIS operator over an area of sufficient regional
scope will better allocate scarcity, promote simplicity and one-stop shopping,
and lower costs); and plan and coordinate transmission expansion.

In evaluating boundaries, the FERC considered the extent to which the proposed
boundaries facilitate performing essential RTO functions and achieving RTO goals;
encompass a contiguous geographic area; encompass a highly interconnected portion
of the grid; deter the exercise of market power; recognize existing trading
patterns; take existing regional boundaries into account (e.g., NERC regions);
encompass existing regional transmission entities; encompass existing control
areas; and consider international boundaries.

All or most of the transmission facilities in a region must be included in the
RTO.

Operational Authority

The RTO must be the security coordinator for the region it serves. As such,
the RTO has responsibility for performing load-flow and stability studies to
anticipate, identify and address security problems; exchanging security information
with local and regional entities; monitoring real-time operating characteristics
such as reserve availability, power flows, interchange schedules, system frequency
and generation adequacy; and directing actions to maintain reliability, including
firm load-shedding.
An RTO may contract out security coordinator responsibilities to an independent
coordinator. The FERC allowed flexibility as to how operational authority is
accomplished and did not require the RTO to operate a single control area for
its region.

Short-term Reliability

The RTO must have exclusive authority to maintain short-term reliability of
the grid it operates, including exclusive authority for receiving, confirming
and implementing all interchange schedules and the right to order redispatch
if necessary for reliable operation of transmission facilities. The phrase “short-term”
is intended to cover transmission reliability responsibilities short of grid
capacity enhancement and includes all time periods necessary for the RTO to
satisfy its reliability responsibilities up to the planning horizon. An RTO
that operates transmission facilities owned by others must have authority to
approve all requests for scheduled outages but is not required to have authority
over proposed generation maintenance schedules nor to establish facility ratings.

All RTOs must also be prepared to perform the following eight functions:

Tariff Administration and Design

The RTO must be the sole provider of transmission service and sole administrator
of its own open access tariff. It must have sole authority over the facilities
it controls, to evaluate and approve or deny all requests for transmission service
and to approve requests for new interconnections.

Congestion Management

The RTO must ensure the development and operation of congestion management
mechanisms. Responsibility for operating these market mechanisms must reside
either with the RTO or with an entity that is unaffiliated with any market participant.
The RTO must have an effective congestion management protocol from “day one”
of operations, but has one year to implement a market mechanism.

Parallel Path Flows

The RTO should implement procedures to address parallel path flow issues within
its region and with other regions on the date of initial operation. It will
have three years to implement measures to address parallel path flows between
regions.

Ancillary Services

The RTO must serve as the provider of last resort of all required ancillary
services, which must be included in the RTO-administered tariff. Since the RTO
is not required to be a single control area operator, the FERC concluded that
it cannot require an RTO that owns no generation to be a supplier of ancillary
services, as the NOPR had proposed. An RTO can fulfill its ancillary services
obligations through a variety of mechanisms, including contractual arrangements,
indirect or direct control of specified generation facilities, or market mechanisms.

Market participants must have the option of either self-supplying or acquiring
ancillary services from third parties. The RTO must have authority to decide
the minimum required amounts of each ancillary service and, if necessary, the
locations where these services must be provided. All facilities that provide
ancillary services must be subject to direct or indirect operational control
by the RTO. The RTO must also ensure that customers have access to a real-time
balancing market that is developed and operated either by the RTO or by another
entity unaffiliated with any market participant. Even if the RTO is not a control
area operator, the FERC expects it to have sufficient operational authority
to ensure that a real-time balancing market can be implemented.

OASIS

Upon commencement of service, the RTO must be the single OASIS administrator
for all transmission facilities under its control and must independently calculate
total transmission capability and available transmission capability. The RTO
has flexibility to contract out OASIS responsibilities to another independent
entity if justified. The FERC recognizes that standardized communications protocols
and business practices will be needed to promote trade across RTO boundaries.

Market Monitoring

The RTO must provide for objective market monitoring. However, the FERC recognizes
that different market monitoring plans will be appropriate for different RTOs.
Standards include a design that ensures there is objective information about
the markets that the RTO operates or administers and a vehicle to propose appropriate
action regarding any opportunities for efficiency improvement, market design
flaws or abuses of market power.

The monitoring plan must also evaluate the behavior of market participants to
determine whether their behavior adversely affects the ability of the RTO to
provide reliable, efficient, nondiscriminatory transmission service. It must
also periodically assess whether behavior in other markets in the RTO’s region
affect operations, as well as how RTO operations affect the efficiency of markets
operated by others.

Planning and Expansion

The RTO must be responsible for planning and directing necessary transmission
expansions and upgrades to provide efficient, reliable, nondiscriminatory service
and to coordinate such efforts with the appropriate state authorities. Specifically,
this function includes: market-based operations and investments for alleviating
congestion, accommodating efforts by state regulatory commissions to create
multi-state agreements that review and approve new transmission facilities and
coordinate with existing RTG programs where necessary, and if the RTO is initially
unable to satisfy this function, to file a plan with the FERC listing milestones
that will ensure the RTO meets the overall planning and expansion requirements
within three years of commencing initial operations. The RTO should have the
ultimate planning and expansion responsibility so that investments will not
work at cross-purposes which could adversely affect reliability. However, the
emphasis in Order No. 2000 is a coordinated approach, and where feasible, the
RTO should encourage market approaches to relieving congestion.

Interregional Coordination

Order No. 2000 adds the explicit requirement that RTOs must develop mechanisms
to coordinate their activities with other regions (whether or not those regions
have RTOs) and must explain how the RTO will ensure the integration of reliability
and market interface practices among regions.

In addition to the minimum functions and characteristics, the FERC required
RTOs to have open architecture, so that they will be able to evolve over time
and will be flexible enough to improve their organizations. Open architecture
will permit RTOs to evolve in the following ways: it will allow basic changes
in RTO organizational form to reflect changes in utility ownership and revised
corporate structure; it will accommodate changes in the geographical scope of
RTOs; it ensures that future developments to provide market support (e.g., formation
of a power exchange) are not foreclosed; it accommodates operational needs;
and it is necessary to accommodate technological changes and permit design modification
to keep pace with technology.

Order No. 2000 states that it is critical for RTOs to develop rate-making practices
that eliminate regional rate pancaking, manage congestion, internalize parallel
path flows, deal effectively and fairly with non-participating transmission-owning
utilities, and provide incentives for transmission-owning utilities to efficiently
operate and invest in their systems.

In §35.34(e)(2), innovative transmission rate treatment is defined as any of
the following: (1) a transmission rate moratorium, which may include proposals
based on formerly bundled retail rates; (2) rates of return that consider risk
premiums and account for demonstrated adjustments in risk, or do not vary with
capital structure; (3) non-traditional depreciation schedules for new transmission
investment; (4) transmission rates based on leveled recovery of capital costs;
(5) transmission rates that combine incremental cost pricing for new transmission
facilities with an embedded-cost access fee for existing transmission facilities;
or (6) performance-based transmission rates, which may include such factors
as (i) a method for calculating initial transmission rates (including price
caps and any provisions for discounting, (ii) a mechanism for adjusting initial
rates, which may be derived from or based on external factors or indices or
a specific performance measure, (iii) time periods for determining initial rates,
and (iv) costs to be excluded from performance-based rates.

Order No. 2000-A

The FERC issued its rehearing order on Order No. 2000 on February 25, 2000
(Regional Transmission Organizations, Docket No. RM99-2-001, 90 FERC 61,201).
Order No. 2000-A reaffirmed the core elements of Order No. 2000 and clarified
a number of issues, including concerns about the requirement that the RTO have
exclusive and independent authority to propose rates, terms and conditions of
transmission service over the facilities it operates. The order also amended
the regulatory text in three respects: It revised the definition of market participant
in §35.34(b)(2) to remove specific references to entities that provide transmission
service to an RTO, added §35.34(j)(1)(iv) to codify the requirement for audits
with respect to the independence characteristic, and revised §35.34(d)(4) to
require RTO proposals to include an explanation of efforts made to include cooperatively
owned entities in addition to public power entities.

Transco and RTO Formation Efforts —The Freight Train of FERC Directives

At its July 11, 2001 meeting, the FERC announced its preference for four large
RTOs — one each for the Northeast, Southeast, Midwest and West. The large-area
RTO approach is one that over the last several years was championed by Commissioner
William Massey but appeared to have negligible support until action was taken
on the PJM, New York and New England proposals by the FERC this summer.

Since PJM appears to be more advanced than the others in satisfying the RTO
characteristics and functions of Order No. 2000, the commission expects it to
serve as a platform for development of a Northeast-wide RTO. At the same time,
the commission expects that the best practices of each system will be incorporated
into the new emerging organization.
Commissioner Linda Breathitt viewed the directive to form four specific RTOs
as a “dramatic departure” from the approach taken in Order No. 2000 and dissented
on this issue in all of the RTO orders approved at the July 11 meeting.

Separate orders initiated mediation on a 45-day schedule, under the direction
of two administrative law judges. Participants in the PJM, PJM West, New York
and New England RTOs were directed to participate in the Northeast discussions,
and state commissions and Canadian entities were encouraged to do so (Regional
Transmission Organizations, Docket No. RT01-99-000, 96 FERC 61,065). Parties
to the Southwest Power Pool, Entergy, Southern and GridSouth RTO proceedings
were directed to participate in the Southeast RTO discussions, and GridFlorida
parties were invited to do so. State commissions and public entities such as
the Tennessee Valley Authority and Santee Cooper were urged to be present (Regional
Transmission Organizations, Docket No. RT01-100-000, 96 FERC 61,066).

The judges issued their reports in late September and summarized them at the
October 24, 2001 FERC meeting. Although both proceedings showed some progress
on regional accommodations, both reports evidenced persistent difficulties with
the large-scale approach that a four-RTO environment entails. These include
the weighting of regional influences in the governance structure minimizing
the cost-shifting effects of the switch to RTOs, development of the technical
capabilities to replace multiple independent system operators with a single
RTO, and how RTO proposals that have been “rejected” in favor of larger-scale
operations (New York and New England are examples) can recover their substantial
organizational and development costs. Other stumbling blocks included whether
Congressional pressure could be used to delimit or require RTOs, and an argument
before the Supreme Court over the FERC’s jurisdiction to mandate unbundling
and the possible anticompetitive effects of large-scale transmission management.

By late September, it was apparent that the December 15, 2001 RTO implementation
date was overly optimistic. Instead, the new FERC chairman recommended the date
should be used as the deadline for jurisdictional utilities to elect to join
an approved RTO or have all market-based rate privileges of any corporate affiliate
prospectively revoked, following an investigation under §206 of the FPA. It
also appears that no mergers will be approved for entities that do not agree
to become part of an operational RTO. However, since it appears that an RTO
participant will be subjected to little market power analysis or none at all,
whereas the analysis for non-participants will be significantly strengthened.
So the choice whether to join an RTO may be limited.

Since then, the commission has embarked on two parallel tracks to address issues
concerning RTO structure, organization and operation. The first is directed
toward getting RTOs operational. The Midwest, Northeast and Southeast RTOs were
to be acted upon by November 2001. The chairman observed that it’s time for
Desert Star and RTO West to “marry up.” However, keeping California operations
separate from the rest of the western United States has support because of some
of its restructuring problems. In Opinion No. 453, issued October 11, the FERC
moved the Midwest ISO closer to RTO operational status by acting on rate-related
issues that predate Order No. 2000, and praised the Midwest ISO for its substantial
progress.

The second track encompasses substantive operational issues and is intended
to give clearer guidance about how the functions and characteristics requirements
of Order No. 2000 are to be satisfied. To this end, the FERC held a series of
RTO workshops during the week of October 15, focusing on core issues such as
congestion management, cost recovery, market monitoring, transmission planning,
business and reliability standards, and the nature of transmission rights. State
regulators and other experts were encouraged to participate. A rulemaking under
§206 of the FPA on market design and structure was expected to follow. Chairman
Wood leans strongly toward market design standardization, while Commissioner
Massey favors treating new market design rules as a rebuttable presumption that
may be superceded by something that provides even greater flexibility for market
participants. The answers will emerge throughout 2002 as RTOs take shape.