esponsible for its content.
REPORT TO THE FEDERAL ENERGY OFFICE OF SWITZERLAND REPORT TO

THE SWISS FEDERAL OFFICE OF ENERGY








THE AUGUST 14, 2003 BLACKOUT

IN THE UNITED STATES:

TECHNICAL AND REGULATORY ISSUES












By:

Dr. Richard A. Rosen
Tellus Institute
Boston, Massachusetts 02116
(1-617-266-5400)
rrosen@tellus.org







November 11, 2003
EXECUTIVE SUMMARY


The blackout that struck the Northeast and Midwest of the United States, and
portions of Canada, on August 14, 2003 had no simple, single cause, as far as is currently
known. It appears to have been physically caused by one or more regional power plant
and transmission line contingencies located in Indiana and Ohio, coupled with computer
problems and information limitations at both the FirstEnergy and the Midwest
Independent Transmission System Operator (MISO) control centers. This led to a voltage
collapse in Ohio due to a shortage of reactive power, probably because independent
power producers were not providing enough reactive power along with the real power
they were selling. It also appears that the FirstEnergy system, where the blackout began,
was over-relying on firm power imports for its operating reserves during the entire
summer.

However, while this blackout cannot be definitely attributed to the restructuring
of the electricity industry in the Midwest, it appears that the restructuring process,
especially the unbundling of certain electric services, did create conditions that led to the
blackout. Certainly, the restructuring process contributed directly to the lack of clear
authority for which institution in the region had ultimate control of the transmission grid
for the purpose of maintaining system reliability, the Midwest ISO or each utility control
area. Restructuring also contributed to the blackout due to the significant economic
conflicts that it creates between various corporate entities that own generating units in the
region, and the utilities that continue to operate local distribution and transmission
facilities. The attempt to develop competitive wholesale markets for electricity has led to
the much more frequent long-distance transmission of power in the Midwest, particularly
power from merchant plants. For example, there were probably more bilateral trades of
power occurring on August 14 in MISO than were compatible with preserving adequate
system reliability. Merchant plants also had little incentive to supply sufficient levels of
reactive power without the presence of an ISO with actual dispatch authority and control.


This lack of clear authority relative to which institution had responsibility for
maintaining system reliability is related to the fact that the State of Ohio had begun to
restructure its electric utility industry as a step towards the goal of universal retail
competition. When a state or region adopts retail competition as a goal, the traditional
regulatory boundaries between the state public utilities commission and the Federal
Energy Regulatory Commission (FERC) become more confused and ambiguous than
they were prior to the start of restructuring. Furthermore, as part of the process of
attempting to facilitate the development of regional competitive generation markets,
FERC had established the Midwest ISO (MISO), but it was only in an early stage of
development as of August 2003. MISO could not even provide a central dispatch of the
generators within its control area as the older power pools in the Northeast had done for
many decades. Nor did MISO have a transmission planning function in place. Thus,
transmission planning and the appropriate level of investment in transmission system
upgrades was left to each local utility, many of which had little incentive to invest at
appropriate levels given the retail rate caps established during the restructuring process.
Nor had MISO been involved in the siting of new generating units in order to try to
minimize any negative impacts that they might have on the reliability of the existing
transmission grid.


ES-1 These critical flaws in the system planning process derived from the fact that the
process for establishing MISO as an effective regional transmission organization was
very problematic relative to the processes relied on to establish the three other such
transmission organizations in the Northeast; namely, the Pennsylvania-Jersey-Maryland
(PJM) ISO, the New York ISO, and the New England ISO. The result was that MISO
could only attempt to maintain system reliability through verbal communications with the
scheduling coordinators at each utility control center.

However, the problems with the way in which the MISO was established simply
reflect the generic problems with the way in which electric industry restructuring has
been attempted in the US. There has been no coherent plan for restructuring the US
electric industry, and much of what has been done so far has been based on flawed
economic theories about what restructuring would likely accomplish, and how these goals
of restructuring could be achieved. FERC has adopted many of these flawed theories as
part of its plans for establishing ISOs and Regional Transmission Operators (RTOs).

ES-2
INTRODUCTION


The detailed causes underlying the blackout of August 14, 2003, are still under
investigation. However, preliminary conclusions can be reached based on the data and other
information that have been made available to date. The evidence seems to clearly indicate that
the deregulation process directly contributed to the causes of the power failure. It would,
therefore, be instructive to outline key features of deregulation in the US that may have played a
role in causing the blackout. This report paper is organized with a description of the regulatory
background and important entities in the electricity sector first, followed by a discussion of the
probable causes of the blackout
.

REGULATORY BACKGROUND
In order to better understand the historical context for the Northeastern blackout of
August 14, 2003, it is necessary first to understand how utilities in the US are regulated. In brief,
there are three important institutions involved: the state economic regulatory agencies, generally
called public utilities commissions (PUCs); the federal regulatory body called the Federal
Energy Regulatory Commission (FERC); and the North American Electric Reliability Council
(NERC), which is a voluntary organization of electric utilities. The key distinction between
these agencies is that the state PUCs regulate the terms and conditions of retail electric rates;
FERC regulates the terms and conditions of wholesale power sales between utilities, including
the transmission tariffs used for wholesale power sales; and NERC establishes voluntary rules,
which are fairly strictly obeyed, to ensure the preservation of adequate system reliability. NERC
has established ten regional reliability councils to implement and monitor its reliability rules.
(See Figure 1 below.)

1 In the past, most electric utilities in the US have been privately owned vertically
integrated companies that provided almost all of the generation requirements of their customers,
in addition to all transmission and distribution system services. They were regulated monopolies.
Until recently, only a little of the generation that these vertically integrated companies sold at
retail was purchased wholesale from other utilities, perhaps a few percent, and the price was not
set by a market mechanism. It was a cost-of-service price determined by FERC. However, during
the late 1990s many state PUCs in the Northeast decided to attempt to lower retail rates by
creating competitive generation markets at both the retail and wholesale levels, where the prices
for purchased power would be set by market mechanisms, and, thus, both the retail and
wholesale prices would be deregulated. FERC also began to encourage the construction of new
power plants owned by independent power producers (not regulated utilities) in the early 1990s
based on a 1992 federal law.
Of course, the initial intention of the advocates of deregulation was that transmission
system prices would remain regulated prices for both retail and wholesale sales. However, once
transmission services were unbundled from generation services in those cases where a utilitys
generating plants were sold to either an unregulated subsidiary of the original utility owner, or to
an unregulated third party, FERC had the authority to set cost-of-service transmission rates for
wholesale transactions between those parties. Surprisingly, in the last few years, FERC has
allowed some degree of market-based pricing for transmission services, as well.
During this initial process of restructuring the electric utility industry, many mergers and
acquisitions also occurred between utilities in the hope that future economies of scale and scope
would help make the new, larger companies more profitable and more able to compete in and

2 dominate the restructured electricity markets. No privatization of utility assets has occurred as
part of US electricity restructuring, since most utilities were already investor-owned.
Thus, to understand electric industry restructuring in the US (the term liberaliza