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An essential industry at the crossroads

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Title:
An essential industry at the crossroads deregulation, restructuring, and a new model for the United States' bulk power system
Creator:
Hein, Jeffrey Thomas
Publication Date:
Language:
English
Physical Description:
158 leaves : illustrations ; 28 cm

Subjects

Subjects / Keywords:
Electric utilities -- United States ( lcsh )
Electric utilities -- Deregulation -- United States ( lcsh )
Electric power distribution -- Management -- United States ( lcsh )
Electric power distribution -- Management ( fast )
Electric utilities ( fast )
Electric utilities -- Deregulation ( fast )
United States ( fast )
Genre:
bibliography ( marcgt )
theses ( marcgt )
non-fiction ( marcgt )

Notes

Bibliography:
Includes bibliographical references (leaves 155-158).
General Note:
Department of Electrical Engineering
Statement of Responsibility:
by Jeffrey Thomas Hein.

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Source Institution:
|University of Colorado Denver
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Auraria Library
Rights Management:
All applicable rights reserved by the source institution and holding location.
Resource Identifier:
55609245 ( OCLC )
ocm55609245
Classification:
LD1190.E54 2003m H43 ( lcc )

Full Text
AN ESSENTIAL INDUSTRY AT THE CROSSROADS:
DEREGULATION, RESTRUCTURING, AND A NEW MODEL FOR THE
UNITED STATES BULK POWER SYSTEM
by
Jeffrey Thomas Hein
B.S.E.E., Michigan Technological University, 1989
A thesis submitted to the
University of Colorado at Denver
in partial fulfillment
of the requirements for the degree of
Master of Science
Electrical Engineering


2003 by Jeffrey Thomas Hein, P.E.
All rights reserved.


This thesis for the Master of Science
degree by
Jeffrey Thomas Hein
has been approved
by
Qa^, ^5 '2jOCP)
Date


Hein, Jeffrey Thomas, P.E. (M.S., Electrical Engineering)
An Essential Industry at the Crossroads: Deregulation, Restructuring, and a New
Model for the United States Bulk Power System
Thesis directed by Professor Pankaj K. Sen
ABSTRACT
Today, the electric utility industry faces an uncertain future. Political, regional and
intra-industry debates are delaying legislation and rules for industry operation which
are needed to ensure the viability of this essential industry and its service. This thesis
proposes a new architecture, or model, for this industry. This new architecture will
ensure all consumers throughout the United States, receive reliable and cost-effective
electricity.
This thesis briefly reviews the history of the electric utility industry, from its
competitive beginnings to its regulation as a natural monopoly and finally, to its
evolution into the present day configuration of three interconnected transmission
networks that cover North America.
The thesis also examines the effects on the industry of several compounding factors:
the 1970s energy crisis, increased electricity costs, improved generation technologies,
and the desire to deregulate the generation sector, previously a natural monopoly.
Industry policy issues ranging from the Public Utility Regulatory Policies Act
IV


(PURPA) up to the Federal Energy Regulatory Commission (FERC) Standard Market
Design (SMD) White Paper are reviewed and summarized.
Finally, the problems associated with present-day restructuring efforts are
summarized, and an architecture, or model, which resolves these problems and
introduces benefits to industry restructuring, is proposed. The architecture of this
new model, as proposed by this thesis, calls for the creation of a two-independent
Transmission Operator (ITO) model for the entire United States with national
oversight by a newly established National Power Administration (NPA).
Transmission is a national and interstate concern and should be treated accordingly.
To optimize the cost-benefit operation of the nations bulk power system, issues must
be addressed by interconnection across the entire nation.
This abstract accurately represents the content of the candidates thesis. I recommend
its publication.
v


DEDICATION
To Heather, my incredible wife, whose infinite amounts of love, patience,
understanding and support made this possible.
In addition, thanks to my loving parents, Jim and Barb, for instilling in me ethics of
hard work and dedication.


ACKNOWLEDGEMENT
Many thanks to my advisor Dr. Pankaj Sen, whose vast knowledge, wonderful advice,
tremendous demeanor, undying desire to improve power systems, and countless hours
of effort, made this possible.
In addition, thanks to Western Area Power Administration and the many industry
professionals I contacted during my research, of which there are too many to list.


CONTENTS
Figures......................................................................xii
Chapter
1.0 - Introduction.............................................................1
2.0 - History of the United States Electric Utility Industry................5
2.1 Origins & Early Developments (1879 1895)...............................5
2.1.1 Let There Be Light (at Night)...........................................6
2.1.2 Development & Competition................................................8
2.1.3 Competing Technologies...................................................8
2.2 The Electric Industry Evolves Competition, Consolidation, State Regulation &
Tremendous Growth (1896 1928)........................................10
2.2.1 Consolidation, Regulation & Early Growth................................12
2.3 Holding Companies: Benefits and Abuses, and Federal Intervention
(1929-1936)............................................................14
2.3.1 Holding Companies: Benefits and Abuses..................................14
2.3.2 Federal Intervention....................................................16
2.3.3 Federal Power Act 1935................................................17
2.3.4 Vertically Integrated Electric Utilities & Regulated Operations.........18
2.4 Technology Improvements and Regional Interconnection (1937 1964)......21
2.5 Northeast Blackout and Regional Reliability (1965 1969)................24
3.0 - Winds of Change........................................................28
3.1 General..................................................................28
3.2 Environmental Issues, The Energy Crisis and Rising Electricity Prices....29
3.3 Public Utility Regulatory Policies Act of 1978 (PURPA)...................32
3.4 Energy Policies Act of 1992 (EPAct)......................................34
3.5FERC Order No. 888.........................................................37
3.5.1 ISO Operational Principles (& Responsibilities):........................41
Vlll


3.5.2 Provisions of Order No. 888............................................43
3.5.2.1 Scope of the Rule.....................................................43
3.5.2.2 Legal Authority.......................................................44
3.5.2.3 Comparability.........................................................44
3.5.2.4 Ancillary Sendees.....................................................44
3.5.2.5 Real-Time Information Networks........................................44
3.5.2.6 Coordination Arrangements.............................................45
3.5.2.7 Pro-Forma Tariff......................................................45
3.5.2.8 Implementation........................................................45
3.5.2.9 Federal and State Jurisdiction: Transmission/Local Distribution.......45
3.5.2.10 Stranded Costs.......................................................45
3.6FERC Order No. 889.........................................................46
3.7 Post FERC Order Nos. 888 & 889 .........................................47
3.8 FERC Order No. 2000......................................................47
3.8.1 Approach to RTO Formation...............................................50
3.8.2 Minimum Characteristics of an RTO.......................................50
3.8.3 Minimum Functions of an RTO.............................................51
3.8.4 Open Architecture.......................................................52
3.8.5 Transmission Rate Making Policy.........................................52
3.8.6 Other Issues............................................................52
3.8.7 Collaborative Process...................................................53
3.8.8 Deadline for RTO Operation..............................................53
3.9 Post FERC Order NO. 2000................................................53
3.10 Standard Market Design (SMD) Notice Of Proposed Rulemaking (NOPR)......55
3.10.1 Summary of SMD Primary Provisions.....................................57
3.10.2 Summary of ITP Responsibilities........................................58
3.10.3 Schedule for SMD Operation.............................................60
3.11 Post SMD NOPR...........................................................60
3.12 Present Day Pricing Mechanisms..........................................61
IX


3.12.1 Electronic Tagging System..............................................62
3.12.2 Summary: Present Day Pricing Mechanisms...............................62
3.12.3 Functional Concepts & Concerns: Present Day Pricing Mechanisms........63
3.12.3.1 The Generation Market Pricing Mechanism..............................63
3.12.3.2 Transmission Service Market Pricing Mechanism(s).....................65
3.12.3.3 Distribution Sector..................................................77
3.12.3.4 Ancillary Services Sector............................................78
3.12.3.5 Demand-Response Sector...............................................78
3.13 Prices since Deregulation...............................................78
3.14 Status of Retail Choice Within the United States.......................80
4.0 - A Restructuring Model for the United States Bulk Power System........82
4.1 General..................................................................82
4.2 Thesis Statement.........................................................82
4.2.1 Overview of Restructuring Architecture..................................83
4.3 Current Transmission System Status.......................................86
4.3.1 General.................................................................86
4.3.2 System Operation........................................................87
4.3.2.1 Constrained Paths (Congestion)......................................87
4.3.2.2 Transmission Capacity Reserves in Decline.............................90
4.3.2.3 Industry Legislation is Unknown (i.e., Rules are Uncertain)........90
4.4 Problems with a Multi-RTO Landscape (as Currently Proposed).............92
4.4.1 Seams Issues............................................................93
4.4.2 Geographic Inadequacy of RTO Proposals..................................96
4.4.3 Inaccurate Embedded Cost Accounting.....................................99
4.4.4 Post-Restructuring Electrical Energy System Operating Costs............100
4.4.5 Delays Restructuring Process...........................................105
4.4.6 Inadequate Investment in Transmission..................................105
4.5 Benefits of Thesis Restructuring Model...................................105
4.5.1 Ensured and Improved Transmission System Reliability (for Consumers)...106
x


4.5.2 Maintain Low-Cost Electricity Service, or Decrease Costs Further.........109
4.5.3 Improved Accountability Through Creation of NPA & ITOs...................113
4.5.4 Expedite Restructuring Process............................................114
4.5.5 Expedite Transmission Infrastructure Investment...........................114
4.5.6 Guidelines of FERC Orders 888, 889 and 2000 Met or Exceeded..............115
4.5.7 Federal Government Agencies with Enhanced FERC Jurisdictional Authority... 115
4.6 The Restructured Bulk Power System: How It Will Work......................117
4.6.1 General Overview..........................................................117
4.6.2 Bulk Power System Architecture & Organization After Restructuring........121
4.6.3 Responsibilities After Restructuring......................................127
4.6.3.1 General..................................................................127
4.6.3.2 Responsibilities of Federal Agencies (NPA, ITOs and FERC)...............127
4.6.3.3 State PUC Responsibilities..............................................132
4.6.3.4 Typical Project Example.................................................134
4.6.3.5 Coordinated Industry Functions..........................................138
4.6.4 Transmission Service Pricing Mechanisms...................................142
5.0 Conclusion and Parting Thoughts................;..........................149
Bibliography.....................................................................155
xi


FIGURES
Figure 2-1 - Timeline: 1879- 1895...............................................5
Figure 2-2 - Charles Brush & Thomas Edison......................................6
Figure 2-3 - The First Incandescent Electric Light Bulb.........................7
Figure 2-4 - Early Electric Fan (note wires in gas tubing conduit)............7
Figure 2-5 - Nikola Tesla, William Stanley, Jr., & George Westinghouse..........8
Figure 2-6 - Ames Power Station, near Telluride, CO (today).....................9
Figure 2-7 - AC Generators, Chicago Worlds Fair...............................10
Figure 2-8 - Edward Dean Adams Power Station...................................10
Figure 2-9 -Timeline: 1903-1927................................................11
Figure 2-10 - Samuel Insull & Charles Parsons .................................11
Figure 2-11 - Fisk Street Station, Commonwealth Edison Co., Chicago.............12
Figure 2-12 - Early Electricity Growth in the U.S...............................13
Figure 2-13- Timeline: 1929-1936...............................................15
Figure 2-14 Franklin D. Roosevelt............................................16
Figure 2-15 Tennessee Valley Authority & Bonneville Power Administration.....17
Figure 2-16 Vertically Integrated Utility Organization & Industry Operations.18
Figure 2-17 Example of Early Control Areas Before Interconnections...........20
Figure 2-18- Timeline: 1936-1964...............................................21
Figure 2-19 - Generator Unit MW Ratings, 1911 1972............................22
Figure 2-20 - Transmission Line Voltage Ratings, 1912 1965....................22
Figure 2-21 - US Interconnections...............................................23
Figure 2-22 - Timeline: 1965- 1977..............................................24
Figure 2-23 - Great Northeast Blackout of 1965..................................25
Figure 2-24 - NERC & Regional Reliability Councils..............................26
Figure 2-25 - Electric Utility Control Areas of North America...................26
Figure 3-1 Deregulation Timeline: 1969 2002 ...............................28
Xll


Figure 3-2 Cost of Electricity Rises.........................................
Figure 3-3 Historical & Present Day Net Generation Statistics................
Figure 3-4 Electricity Generation by Electric Utility Sector.................
Figure 3-5 Electricity Generation by Non-Electric Utility Sector (NUGs)......
Figure 3-6 Generation Additions Since 1990...................................
Figure 3-7 Cost of Electricity, Residential Rates (cents per kWh)............
Figure 3-8 Industry Restructuring Unbundled Functions......................
Figure 3-9 ISO Responsibilities..............................................
Figure 3-10 ISOs Proposed....................................................
Figure 3-11 RTOs Guidelines and Responsibilities.............................
Figure 3-12 FERCs RTO Vision................................................
Figure 3-13 Actual Proposed RTOs.............................................
Figure 3-14 SMD & Seams Issues...............................................
Figure 3-15 Highway-Zonal Tariff Graphic.....................................
Figure 3-16 Dispatched Generation Without Transmission Congestion............
Figure 3-17 Energy Flow Without Transmission Congestion......................
Figure 3-18 LMPs Without Transmission Congestion.............................
Figure 3-19 Load & Generator Bids............................................
Figure 3-20 Dispatch Solution Ignoring Thermal Limits (of Transmission Line)...
Figure 3-21 Actual Dispatched Generation Accounting for Congestion...........
Figure 3-22 Actual Energy Flow Corresponding to Actual Dispatch..............
Figure 3-23 Actual LMPs Corresponding to Actual System Conditions............
Figure 3-24 LMP Costs for Generation.........................................
Figure 3-25 -Residential Electricity Costs Since Order Nos. 888 & 889..........
Figure 3-26 Status of Retail Choice Within the United States.................
Figure 4-1 An Essential Service is at Stake (Earth at Night).................
Figure 4-2 ITO East & ITO West Geographical Scope............................
Figure 4-3 Federal Agency Architecture Power System Sector.................
xiii
31
35
36
36
37
39
40
41
47
49
54
54
56
70
72
72
73
74
74
75
75
76
76
79
80
83
84
84


Figure 4-4 Americas Infrastructure Report Card..............................86
Figure 4-5 National Transmission System Congestion...........................88
Figure 4-6 Congestion Western Interconnection..............................88
Figure 4-7 Congestion Eastern Interconnection..............................89
Figure 4-8 RTOs Proposed (Present-Day).......................................92
Figure 4-9 Seams Issues......................................................93
Figure 4-10 Parallel Path Flows..............................................97
Figure 4-11 Loop Flows.......................................................98
Figure 4-12 Proposed RTOs 2003...............................................99
Figure 4-13 Example of Inaccurate Embedded Cost Accounting..................100
Figure 4-14 Base Case Regions...............................................101
Figure 4-15 Smaller RTO Landscape...........................................102
Figure 4-16 Five RTO Landscape (RTO Policy Case)............................103
Figure 4-17 Three RTO (Larger) Landscape....................................104
Figure 4-18 Control Areas (Present-Day).....................................Ill
Figure 4-19 Control Areas (Proposed)........................................Ill
Figure 4-20 Architecture of Restructuring Proposal..........................119
Figure 4-21 Architecture of Proposed ITOs...................................119
Figure 4-22 Future NERC Regions by NESC Loading Criteria....................123
Figure 4-23 Transmission Owner Architecture.................................124
Figure 4-24 ITO-East Architecture (typical).................................125
Figure 4-25 ITO-West Architecture (typical).................................126
Figure 4-26 NPA and ITO Responsibilities....................................128
Figure 4-27 ITO Operations with State PUC Review and Input..................133
Figure 4-28 Typical Transmission Project Flowchart..........................134
Figure 4-29 Coordinated Industry Standards and Design.......................138
Figure 4-30 Coordinated Industry R&D Activities.............................139
Figure 4-31 -Engineering Standards for Substations & Switching Stations......140


Figure 4-32 -Engineering Standards for Transmission Lines.............141
Figure 4-33 NESC Loading Map........................................141
Figure 4-34 Simplified System with Sagging Bus Voltages.............144
Figure 4-35 Response-Based Pricing Mechanism........................145
Figure 4-36 Response-Based Pricing Mechanism with ITO...............145
Figure 4-37 Wide Area Measurement Systems...........................147
xv


Chapter 1.0 Introduction
The purpose of this thesis was to examine deregulation and restructuring efforts
within the electric utility industry in the United States from a technical perspective.
During the research process, it became clear that to fully understand this topic and
make a contribution to our industry, it was necessary to widen the scope, in both time
and perspective. Therefore, this thesis evolved into one that examines the past -
the various reasons behind the desire to deregulate and the issues involved with
deregulation and restructuring efforts and the future, by proposing a new model for
the national bulk power system. In addition, proposing a new model meant expanding
the perspective from a technical one to one that included a myriad of economical and
policy issues. By expanding the scope of this thesis, the goal is to bridge technical,
economical and policy issues, in order to assist the transition to a viable, secure, cost-
effective, and reliable industry, as it once was, for the future protection of the
consumer and the nation.
This thesis reviews the history of the United States electric utility industry and
presents theoretical concepts for changing its present structure. The following
paragraphs are intended to serve as both summary and road map to the content of this
thesis.
First, in Chapter 2, this thesis briefly reviews the history of the electric utility
industry. This chapter examines its competitive beginnings in 1879 to its evolution
into three interconnected systems of the late 1960s that cover North America.
Pioneers of the industry and their contribution(s) are reflected upon to give the reader
a sense of the industry roots.


Next, in Chapter 3, this thesis examines the effects of several compounding factors
and the resulting policies on the industry. This chapter reviews a perfect storm of
factors that struck the industry in the early 1970s up to the Standard Market Design
(SMD) White Paper issued in April 2003. Industry policies reviewed include the
Public Utility Regulatory Policies Act of 1972 (PURPA), the Energy Policy Act of
1992 (EPAct), FERC Order Nos. 888, 889 and 2000 and the Standard Market Design
(SMD) Notice of Proposed Rulemaking (NOPR). Since the SMD NOPR was issued
jurisdictional and regional debates have raged.
In Chapter 4, the problems associated with present-day restructuring efforts are
summarized, and an architecture, or model, which resolves these problems and
introduces benefits to the industry is proposed. This thesis proposes a new
architecture, or model, for the bulk power system portion of this industry. This new
architecture will ensure that all consumers throughout the United States receive
reliable and cost-effective electricity. The architecture of this new model consists of
a two-independent Transmission Operator (ITO) model for the entire United States
with national oversight by a newly established National Power Administration
(NPA), all federal government agencies The federal government would assume
jurisdiction over most aspects of the bulk power system. Precedence for this was set
in the early 1900s, when states assumed jurisdictional authority over electric utilities
from local governments. Now is the time that jurisdiction over all transmission, and
certain aspects of generation, be shifted to federal oversight (from states).
Transmission and certain aspects of generation are interstate issues and need to be
treated accordingly, with substantial state involvement. This is also a unique
opportunity to streamline many industry processes, given the concurrent evolution of
our industry. We can simplify and streamline our industry for the benefit of all and to
meet the needs of the nation, while at the same time addressing the issue of declining
numbers of personnel entering our industries work force.
2


Finally, Chapter 5 provides a brief summary and several parting thoughts.
Today, the electric utility industry faces an uncertain future. As a result of
deregulation and restructuring efforts, political, regional and intra-industry debates
are delaying legislation and rules regarding industry operation, which are needed to
ensure the viability of this essential industry and its service. As this delay continues,
load growth and societal demands continue to rise on an aging transmission and
generation infrastructure, much of which is 30-50 years old.
Deregulation efforts were initiated to save consumers money and protect the
environment, through improved generation technologies and their operation. It was
once said, the road to hell is paved with good intentions. Merely four years after
wide-sweeping deregulation legislation was introduced in 1996, unchecked greed
reappeared within our industry, after having been prevented for nearly 70 years under
regulated operation. The story of California and the terrible fallout is known by all.
More recently, on August 14, 2003 the largest blackout in United States' history
occurred. During this blackout, 62,000 MW of load was lost, which impacted one-
fifth of the nations population, contributed to two deaths and resulted in revenue
losses totaling nearly $1 billion in New York City alone. Early estimates to upgrade
the transmission infrastructure are nearly $10 billion.
During recent times, a bulk power system whose reliability was taken for granted
turned into a system thats susceptible to regional blackouts and brownouts with
volatile price swings for service. In addition, what was once secure stock for both
investor and utility has turned into a very questionable investment.
3


After reading this thesis, and processing the information contained within it, the
question of deregulation that must be asked is, Do the potential downfalls outweigh
and out-cost the anticipated benefits? Does deregulation apply to the electric utility
industry? The electric utility industry is much more complicated and critical than
other deregulated industries like telecommunications and airlines. The electric utility
industry is the most capital-intensive industry on the planet, requiring years of lead
time for adding infrastructure. This industry must operate in a proactive manner to
ensure it can meet the needs of the nation during the periods of economic upswing
and expansion.
Whether deregulation efforts continue or the industry is re-regulated, the new bulk
power system model proposed within this thesis should be enacted to ensure the most
reliable, cost-effective electricity continues to be available to its customers and our
nations security, economy and way of life.
4


Chapter 2.0 History of the United States Electric Utility Industry
2.1 Origins & Early Developments (1879 1895) 181, [91, [371. [611, 1641
Electricity was a revolutionary, new technology back in the late 1800s very much like
the Internet is a new technology of modem times. This section reviews its beginnings
(Figure 2-1).
1879 1883 1885 1890 1893
1882
4
Pearl Street
Station
Operational +/-
100V (DC)
-Edison-
First Polyphase
Motor Invented
(AC)
-Tesla-
1884
t
Steam Turbine
Invented
-Parsons-
1886
4
Is' Multiple
Voltage AC
Power System
500V-3kV-
100 V
for house
lighting
Westinghouse/
Stanley
1891
4
Is' Commercial
Use, Modem
Multi-phase
AC Power
System; Ames
Power Plant to
Gold King
Mine
Telluride, CO
-Tesla/
Westinghouse
1895
_____
Edward Dean
Adams
Generating
Station,
Niagara Falls,
NY
3-Phase AC
Installed
instead of DC
-Edison-
Figure 2-1 Timeline: 1879 1895
5


2.1.1 Let There Be Light (at Nisht)
The roots of the modem day electric utility industry can be traced back to two events
that occurred in the year 1879. The first occurred when Charles Brush (Figure 2-2)
invented a dynamo and arc lamp lighting system for street lighting, which he put to
use in Cleveland, Ohio. That same year Thomas Alva Edison (Figure 2-2) and his
team of researchers invented the incandescent light bulb for home lighting, the
predecessor of the light bulb in use today.
Figure 2-2 Charles Brush (l) & Thomas Edison (r) [61/, [641
In New York City in 1882, Pearl Street Station was the first central electricity-
generating station constructed to support the light bulb invention. Using a DC, +/-
100-volt generation and distribution system (with neutral), Pearl Street Station used
reciprocating steam engines to provide the mechanical energy required to create
electricity. Lighting was the first application for electricity (Figure 2-3).
6


Figure 2-3 The First Incandescent Electric Light Bulb [641
In 1878 Edison created the Edison Electric Light Company, which evolved into the
General Electric Company by 1892, of which Edison was a major stockholder.
The need for electricity would grow as appliances, such as irons and even electric
streetcars, were introduced. While their predecessors used wood or coal, which was
dirty, Edison and others were developing a market for cleaner electricity (Figure 2-4).
Figure 2-4 Early Electric Fan (note wires in gas tubing conduit) [371
1


2.1.2 Development & Competition
Soon electricity was being hailed as a modem marvel that would revolutionize
households and industry nationwide. Optimists envisioned increased demand for
electricity and others sought entry into this growing market. Central generating
stations and distribution systems (wires and poles) began sprouting up in many cities,
after receiving approval from municipal governments. Competition between
providers was commonplace. Initially, the United States9 electric utility industry
operated in a competitive, market-based environment.
Because low voltage restricted distribution to about one mile from the generating
station, many generating stations and distribution systems were built. In Chicago
alone 45 electric utilities competed for customers. This industry design was repeated
again and again within cities throughout the United States.
2.1.3 Competins Technolosies [631 [65]
During this same time period, another form of electricity alternating current (AC)
was being developed. The primary developers were Nikola Tesla, William Stanley,
Jr., and George Westinghouse (Figure 2-5).
Fisure 2-5 Nikola Tesla (l), William Stanley, Jr. (c). & Georse Westinzhouse (r)
[65], [63]
8


In 1883, Stanley invented the first modern-day transformer used in AC electrical.
Tesla invented the AC polyphase motor in 1885 and married it with the transformer.
The AC technology was more efficient because it could increase low-voltage
generation to high-voltage for long distance transmission then back to low-voltage
distribution for end use. While DC power systems had a head start and were more
widely used than AC systems, AC power systems were still being developed and
installed. Together with the finances of George Westinghouse, the AC electric
system created a strong competitor to DC systems. Westinghouse Electric Company
was founded in 1886. The first AC system, upon which todays is based, was built in
1891, to provide power from the Ames hydro-power station (Figure 2-6) to the Gold
King Mine near Telluride, CO.
Figure 2-6 Ames Power Station, near Telluride, CO (today)
These two technologies would eventually compete for control of the United States
electricity market. This head-to-head competition occurred during the development
of the Niagara Falls Edward Dean Adams power station (Figure 2-8). The Niagara
Power Commission, wishing to deliver power to Buffalo nearly 23 miles away,
awarded this contract to the Tesla/Westinghouse AC generators, based on their
9


Chicago Worlds Fair exhibit (Figure 2-7). This was a major defeat for Edison and
the DC power systems he envisioned.
Fisure 2-7 AC Generators, Chicago Worlds Fair f,371
Figure 2-8 Edward Dean Adams Power Station
2.2 The Electric Industry Evolves Competition, Consolidation, State
Regulation & Tremendous Growth (1896 -1928) (81, [91, [101, fill
The next major development in the electric utility industry occurred in 1903 with the
introduction of turbine generators (Figure 2-9).
10


Figure 2-9 -Timeline: 1903-1927
Chicago Edison, under the guidance of President Samuel Insull (Figure 2-10),
installed a turbine-generator set(s) that produced 5 MW of AC power at Fisk Street
Station (Figure 2-11) in Chicago. A turbine-generator set was revolutionary because
it used a new technology known as a steam turbine as the generators prime mover.
The rotating steam turbine, developed in England in 1884 by Charles Parsons (Figure
2-10) was far superior to its predecessor, the reciprocating steam engine.
Figure 2-10 Samuel Insull (I) & Charles Parsons (r) 1361, 1661


The new steam turbine was much smaller in size, produced equal amounts of energy,
and could be scaled up to produce more power for little additional capital cost. These
new machines could now produce more electricity at a cheaper cost. Adjusted to
1992 terms, new AC technologies lowered electricity costs to $1.56 per kilowatt-hour
(kWh) in 1892, compared with the more than a rate of $4.00 kWh in 1892.
The downfall of the widespread DC electricity system Edison envisioned was
imminent.
2.2.1 Consolidation, Regulation & Early Growth
Insull realized that a competitive market environment would not result in enough
profits to pay back investment costs. He began acquiring other utilities, eliminating
competition and thus began consolidation. By 1907, Chicago Edison had acquired 20
other utility companies and changed its name to Commonwealth Edison.
12


Consolidation occurred in many other cities, with the local electric utility controlling
the market a natural monopoly.
Using the railroads as precedence, initially cities, then states created pubic utility
commissions (PUC) to oversee electric companies to protect consumers. States
assumed jurisdictional authority over electric utilities which were initially held by
local govemment(s) [10]. Utilities were protected from competition and in return
were obligated to serve all customers.
During the 1910s and 1920s, utilities saw tremendous growth (Figure 2-12) and were
able to charge their expanding customer base for all services they provided. Utility
generation and transmission expanded from 5.9 million kWh in 1907 to 75.4 million
in 1927 while per unit costs of electricity declined 55 percent.
Fisure 2-12 Early Electricity Growth in the U.S.
13


2.3 Holding Companies: Benefits and Abuses, and Federal Intervention (1929 -
1936) T81, T91, TIPI, fill
The next major series of events impacting the industry involved holding companies
and the federal government to prevent industry abuses (Figure 2-13).
2.3.1 Holding Companies: Benefits and Abuses
Commonwealth Edison and other utilities soon began to form an operational structure
known as a holding company. Holding companies acquired various utilities (electric
and railway), known as operating companies. Organized into a pyramid scheme
covering many states, holding companies acquired sub-holding companies and the
corresponding operating companies. During this time, three holding companies
controlled 45 percent of the entire U.S. electric utility industry.
14




929 1. 933 li 936
Figure 2-13 Timeline: 1929-1936
The holding company structure offered many benefits. Operating companies used the
holding companys centralized engineering, management, and purchasing services.
In addition, holding companies increased reliability by interconnecting their operating
companies. The electricity system grew quickly.
However, in the 1920s, holding companies began abusing this structure. The holding
companies were essentially monopolies and began charging exorbitant service fees
and overvaluing purchases, which were then added to the service rate.
The interstate operating structure allowed holding companies to evade state-based
regulatory commissions because these issues were under the jurisdiction of the
15


federal government, and there were no federal authorities providing industry
oversight.
Public distrust of these holding companies came to a head when the stock market
crashed in 1929. Many investors lost their investments in holding companies, whose
weak organizational architecture was susceptible to complete collapse.
Franklin Roosevelt (Figure 2-14), campaigning for the presidency in 1932, promised
to reform the corrupt electric utility industry and create government agencies to
provide electricity to rural areas, long ignored by the electric utilities.
Figure 2-14 Franklin D. Roosevelt f 671
2.3.2 Federal Intervention
Roosevelt was true to his campaign promises. With the approval of Congress, he
created the Tennessee Valley Authority (Figure 2-15) in 1933 [59] and the Rural
16


Electrification Administration and the Bonneville Power Administration (Figure 2-15)
in 1935 [60],
Fieure 2-15 Tennessee Valley Authority (l) <6 Bonneville Power Administration (r)
These government agencies proved that electricity could be generated and delivered
cost effectively to remote, rural areas. As a result, the standard of living in these
remote areas rose tremendously. These rural loads proved to be the largest customer
base in the country at the time and continue to be today.
To prevent future similar abuses, Congress passed the Public Utility Holding
Company Act of 1935 (PUHCA). PUHCA created effective state and federal
regulations for regulating the holding companies.
2,3.3 Federal Power Act -1935
Enacted by Congress in 1935, the Federal Power Act (FPA) increased the Federal
Power Commissions (FPC) responsibilities to oversee and regulate the transmission
and sale of electric energy in interstate commerce. Originally, the FPC was
established to oversee/regulate power projects on navigable waterways under the
Federal Water Power Act.
17


2.3.4 Vertically Integrated Electric Utilities & Regulated Operations
The post-federal intervention era created the foundation for vertically integrated
electric utility companies (VIU). Operating as natural monopolies primarily in or
near urban areas, they were vertically integrated and responsible for providing
generation, transmission and distribution of electricity to customers (Figure 2-16). To
control the balance of energy supplied and used, each utility created a control area.
Regulatory oversight was the responsibility of state PUCs for IOUs, and municipal
leaders for municipal power agencies. To ensure customer abuses did not occur,
service rates were under constant scrutiny through the Uniform System of Accounts
method.
Figure 2-16 Vertically Integrated Utility Organization & Industry Operations
Operating in a regulated, cost-based environment, utilities would plan and build
infrastructure to meet the needs of the customers they were obligated to serve. The
18


utility would recover its operating costs plus regulated profit (approximately 10
percent) through their approved service rates. Electric utilities were under state PUC
oversight, in practice, due to their vertical integration structure and bundled services
operation.
Therefore, as the demand for electricity grew, utilities could add to their system
infrastructure with a guaranteed return on their investment. Utilities would add
facilities and get paid for this investment from service rates paid by their customers.
The utility industry continued to grow and grow quickly. Utilities would construct
generation close to their customers in urban areas to reduce system losses, which are
very costly. The electric utilities were primarily under state PUC oversight and
control since their activities remained predominantly intrastate. PUCs reviewed
every aspect of utility operation, from siting to service requirements, through final
rate development. Initially, each utility operated a control area for the cities they
served. Control areas ensured system operation by matching electrical generation to
load requirements and use. The beginnings of the industry consisted of discreet,
smallish power grids scattered throughout the United States centered at major cities
with connections to outlying areas.
There were regional interconnections in operation, namely the Pennsylvania-Jersey-
Maryland interconnection, but no large-scale bulk power system interconnections
(e.g., across Western United States) as w'e know them today (Figure 2-17).
19


O- Indicates Control Area
Figure 2-17 Example of Earlx Control Areas Before Interconnections [201
Early development of the electric utility industry occurred concurrently, without
many interconnections (note the lack of lines between control areas when compared
to figure 2-25). The landscape of the industry consisted primarily of each utility,
typically located within a city, operating their own control area (Figure 2-17).
20


2.4 Technology Improvements and Regional Interconnection (1937 1964) 181
From the 1930s through the 1960s the industry saw tremendous improvements in
generation and transmission technology (Figure 2-18).
Regional Transmission Planning Councils
Created
-----------------;---------------
1962
1936
1964
Generation Technologies
Improve
Transmission Voltages
Increase
Electric Utility Growth
North American Transmission. System
Inter-connected
Figure 2-18 Timeline: 1936-1964
Over a relatively short period of time however, improved efficiencies of scale in the
generation sector were realized. With larger generators, electricity could be
generated more efficiently and, therefore, cheaper (Figure 2-19).
21


1400 -| 1 *>nn _
1 nnn .
Qnn . ^Generator Unit Ratings MW
cnn .
a nn .
-JftA -
n -
1911 1928 1953 1960 1965 1972
Fieure 2-19 Generator Unit MW Ratines. 1911 -1972
At the same time, transmission voltages increased in order to reduce losses (Figure 2-
20). Larger, central, state-of-the-art, generating stations located nearer their fuel
supply, and connected to high voltage transmission lines, began replacing the smaller
generating stations connected to lower voltage sub-transmission and distribution
lines. This configuration resulted in the cheapest electricity possible while improving
reliability and use of resources.
Fisure 2-20 Transmission Line Voltage Ratines, 1912 1965
22


From 1927 to 1967 electricity prices dropped from 55 cents to 9 cents per kWh, again
in 1992 terms. As a result of this system, the United States electric system evolved
from many locally operated, geographically smaller grids, to one where interstate
transmission lines interconnected many different utility systems. Each utility served
its respective customers either with its own generation or through purchases with
neighboring utilities called wheeling using contract path pricing. The individual
utility control areas still played a very important role in scheduling electricity sales to
neighboring utilities.
The Federal Power Act and individual state laws controlled how the utility industry
operated through regulatory oversight, primarily at the state level, and to a lesser
extent, the federal level. Reliability of the electric system was now both a regional
and local control area concern because three interconnected power systems covered
the entire US (Figure 2-21) and Canada.
Figure 2-21 US Interconnections [91
23


2.5 Northeast Blackout and Regional Reliability (1965 1969) 181, [91, [101, 1111
As the bulk power system became more interconnected, benefits were realized,
unforeseen problems arose, and means to correct these problems were developed
(Figure 2-22).
1965
1968
1972
1964 1967 1970 1996
Figure 2-22 Timeline: 1965- 1977
The great Northeast Blackout of 1965 uncovered a weakness in the United States and
Canadas interconnected electric grid. A disturbance in one section of a large
interconnected grid could interrupt service across a wide geographical area. The
blackout interrupted electric service over 80,000 square miles (eight states) in the
24


Northeastern US and large parts of Canada (Figure 2-23). This blackout started with
a single 345kV transmission line relaying failure near Toronto, Canada.
Figure 2-23 Great Northeast Blackout of 1965
It was determined that a regional coordinating body should be created to ensure
regional reliability over a large geographic area. The North American Electric
Reliability Council (NERC) was formed on June 1, 1968, under the Electric Power
Reliability Act of 1967.
Today, NERC is responsible for overall reliability, planning and coordination of
electricity supply in North America. NERC is a non-profit agency comprised of 10
regional reliability councils, which represent smaller regions of North America
(Figure 2-24). Each reliability council coordinates activities between the many
control areas of the utilities it encompasses and their interconnections (Figure 2-25).
25


*note: Each white circle indicates a control area operator.
Fieure 2-25 Electric Utility Control Areas of North America f201
26


Through this model, North Americas interconnected electric power system produced
the cheapest, most reliable electricity in the world. This is essentially how utilities
operated before conservation, deregulation, and restructuring legislation began to
appear.
27


Chapter 3.0 Winds of Change
3.1 General
The next chapter in the industrys history began in the late 1960s / early 1970s with
growing environmental concerns, the energy crisis and energy conservation
programs. This would prove to be the start of very difficult times for the industry.
Electricity prices would rise, consumers would become disgruntled, and a desire of
some to deregulate the generation sector (because of new generation technologies)
would emerge (Figure 3-1). To address these issues, industry policies were enacted,
This chapter reviews those policies and the reasons behind them.
Figure 3-1 Deregulation Timeline: 1969 2002
28


3.2 Environmental Issues. The Energy Crisis and Rising Electricity Prices TIL T81
The 1970s were the start of difficult times for the electric utility industry.
Prices of electricity would quadruple between 1970 and 1985. This was not
due to poor management of utilities for they continued to operate with their
customers best interest in mind by employing techniques (large central
stations and HV/EHV transmission) to continue delivering reliable, cheap
electricity. It was due, instead, to a perfect storm of unforeseen,
uncontrollable events that occurred at or near the same time. The perfect
storm was comprised of environmental and conservation concerns, an energy
crisis, a poor economy, inflation, occupational safety issues, and low load
growth.
In 1970, environmental concerns resulted in passage of the Clean Air Act by
Congress. This act forced substantial reductions in allowable emission levels (SO )
from coal-fired power plants because of acid rain concerns. This was followed by the
Water Pollution Control Act of 1972. Both acts substantially reduced the amount of
electrical power the state-of-the-art, large, central generating stations could create,
thereby reducing the amount of generation available to the interconnected power
system.
The energy crisis of 1973, fueled by the OPEC oil embargo, raised electric generation
fuel prices. This led to a mindset of conservation and energy efficiency. The Energy
Supply & Environmental Coordination Act of 1974 (ESECA) required utilities to stop
using natural gas or other petroleum based products to generate electricity. This, 9
followed by the Resource Conservation & Recovery Act of 1976, amendments to the
1970 Clean Air Act issued in 1977, the Power plant & Industrial Fuel Use Act of
1978, and the National Energy Conservation Policy Act of 1978 all contributed to
29


further reductions in generating capacity of the large power plants. In response to the
precarious national energy situation, several Federal agencies, including the DOE and
the FERC were created by the Department of Energy Organization Act in 1977.
FERC was given the jurisdictional authority previously assigned to the FPC.
This was also a difficult time for the US economy. Inflation grew and economic
expansion slowed to a crawl or stopped altogether. The utility industry reflected
minimal or no load growth.
However many state-of-the-art, large, central station power plants were under
construction to supply the forecasted load growth. These power plants were primarily
coal and nuclear which were very costly and took years to build. Not only did these
plants cost more as a result of inflation, financing cost increases, safety concerns and
regulatory requirements, but there was no need for them once completed due to the
drastically reduced load growth. The result was excessive generation capacity reserve
margins. These additional costs incurred by the utility were passed on to customers
resulting in dramatic price increases (Figure 3-2). Average residential customers paid
$2.2 per kWh in 1969, and $6.6 in 1985. Industrial customers paid $1.5 per kWh in
1970 and $6.0 in 1985.
30


The utility managers were trying to operate their companies effectively, but given the
unforeseen perfect storm factors, essentially a run of what was bad luck, it
appeared to the public that utilities were mismanaged. These generation stations
costs were added to the rate base. Ultimately, because it was a cost-based industry
with obligation to serve requirements, the costs of these unnecessary generating
stations were passed onto the public sector, a legitimate practice, causing electricity
service rates to rise. Rising electricity costs and declining utility investment
dividends coupled with difficult economic times caused public outcry.
In response, public actions were taken to explore ways to reduce the cost of electricity
service.
New, alternative forms of generation technologies appeared in the late 1970s
(combined cycle, gas pow'ered turbines and fluidized bed combustion). These new
technologies were more efficient, reliable, responsive, required less construction time,
31


required less maintenance and down-time, and as a result required less capital than
their larger predecessor. This new type of generation was more cost effective with
less financial risk. In addition to the expense benefits, the new technologies were
more environmentally friendly than their predecessors. The modern generating unit
now had an optimal operating rating of 50-150MW as compared to its 500-1300MW
predecessor. These newer units could now produce electricity for 3-5 cents per kWh
whereas their larger predecessors could produce electricity for 4-7 cents per kWh in
coal-fueled plants and 9-15 cents per kWh in nuclear-fueled plants.
Economies of scale no longer favored bigger generating units since they were no
more efficient than their smaller competitors. Bigger w,as no longer better.
In order to develop these alternate forms of generating electricity, FERC needed to
create legislation mandating industry reorganization and new operating characteristics
that would allow a fair system to allow this new form of generation. This legislation
was the Public Utility Regulatory Policies Act of 1978 (PURPA).
3.3 Public Utility Regulatory Policies Act of 1978 (PURPA) [II, f81,191, f 10], [111
Public Utility Regulatory Policy Acts provisions created a tremendous ripple effect
throughout the electric utility industry that would impact it for many years to come
and which continues today.
The intent of PURPA was to introduce more efficient, cheaper, and environmentally
friendly generation to the power system. New generation technologies could produce
electricity more cheaply than their large predecessors. Economies of scale favored
these new technologies bigger was no longer better. Reduced US dependency on
foreign oil and more generation capacity was needed.
32


PURPA accomplished this through the introduction of FERC approved, non-utility
generation called Qualifying Facilities (QF) or non-utility generators (NUG).
Utilities were required to purchase this generation from the QFs. The additional
capacity QFs supplied was relatively small due to limitations imposed upon them.
Other PURPA provisions included the addition of sections 210, 211 and 212 to the
FPA, which gave FERC authority over QF interconnections and transmission
wheeling.
Near-term results of PURPA legislation was cheaper and cleaner generation
technology development, which was added to the power system via QFs and larger
Independent Power Producers (IPPs). There were other more subtle effects -
discussion of deregulating the generation sector.
At this time, the natural gas sector was also being deregulated under FERCs
oversight. This led many to believe the same could be applied to the generation
sector. Many believed the generation sector was no longer a natural monopoly since
most companies could now afford to construct power plants using new generation
technologies. Many believed replacing the regulated, cost-based sector with a
deregulated, or competitive, market-based approach would result in cheaper
electricity through improved business decisions combined with the cheaper
generation technologies.
Not knowing the direction the industry would take; utilities began to reduce
generation, transmission, distribution and employment costs. In addition, public
resistance to new infrastructure being built was rising. Terms like BANANA -
Build Absolutely Nothing Anywhere Near Anybody, NIMBY Not In My
33


Backyard, and finally NOPE Not On Planet Earth were commonplace and
reflected public opinion. As a result generation and transmission reserve capacity
began to decline.
Between 1978 and 1987, other industries in the US were deregulated. These other
industries included the airline industry in 1978 and telecommunications (AT&T) in
1984. Further deregulation in the natural gas industry opened access to the pipelines
and created a spot market in 1986 and 1987. It was believed deregulation would
lower costs to consumers and increase supply and reliability
3.4 Energy Policies Act of 1992 (EPAct) HI. T81. T91. HOI. HU
The primary intent of the EPAct was to create open access to the transmission system
for all generating companies, both utility and non-utility (QFs and IPPs a.k.a.
NUGs). There were instances reported to FERC of VIUs preventing QF and IPP
generation being dispatched through manipulation of transmission system operations,
both still under the control of VIUs and their control area operators. It was believed
by FERC and Congress that without open access to the transmission system, the
anticipated benefits of new generation technologies (cheaper and more
environmentally friendly electricity) would not be realized.
Primary provisions of EPAct included FERC approval of Exempt Wholesale
generators (EWGs) and added section 213 to the FPA. EWGs were allowed to sell
electricity to the bulk power market, and section 213 extended FERC jurisdictional
authority and oversight over transmission access issues. As a result of EPAct,
transmission tariff structures improved and open access tariffs had to be filed (with
FERC) before access to lucrative contracts would be granted by FERC. In 1992, for
the first time, generation added by NUGs exceeded that added by traditional utilities.
34


The next series of figures shows the history of generation added to the electric utility
industry. The first figure (Figure 3-3) shows total generation capacity added for both
utility and non-utility generators.
Total. 1949*2000
Net Geneiatlon, 2000
<1 *
oa
o
1950
i i i ,1'T1
1960 1970 1960 1990
FlecUlMJt lines
NonuMMy Power
Prod trees
By Source. 2000
3-
ShJres by settee, 2000
(Percent of Totali
Itaird
Oat
Barite ItalrtDK Nonu Dirty Pcm*r
Pr*duc*r
Figure 3-3 Historical & Present Day Net Generation Statistics [181
The next two figures separate the information shown in Figure 3-3 into typical
electric utility companies and non-electric utility companies or NUGs. Generation
capacity added to the US electric utility industry by typical electric utility companies
(Figure 3-4) covers years 1949 through 2000 while capacity added by NUGs,
(Figure 3-5) covers years 1989 through 2000.
35


Total, 1549-2000
By Source, 2000
3.5-
1050 1955 1980 1065 1970 1075 TOGO 1065 1090 1095 2C03
By Source. 1949*2000
2A-
2.0 -
Figure 3-4 Electricity Generation by Electric Utility Sector [181
Figure 3-5 Electricity Generation by Non-Electric Utility Sector (NUGs) f181
36


Figure 3-6 Generation Additions Since 1990
After the EPAct and up through 1995, transmission system access discrimination by
VIUs continued to be reported to FERC. The VIUs were able to prevent open access
to transmission because they still dispatched generation and operated the transmission
system. The VIUs would operate the transmission system and dispatch generation in
a way that benefited the VIU generation over their non-utility (e.g. IPPs) competitors.
In response FERC, acknowledging transmission was still a natural monopoly and
should be treated as such, issued several policy statements. These policies did not
achieve the goal of ensuring open access to transmission. IPPs continued to report
instances of discrimination by VIUs. To promote generation sector competition and
correct the open access issue once and for all, FERC issued Orders 888 and 889.
3.5 FERC Order No. 888 HI, T31, T91
These two orders were issued concurrently and were the first attempt at wide-
sweeping changes to promote deregulation of the generation sector. Order No. 888
addressed open access to transmission issues. Order No. 889 addressed the issue of
access to transmission system information by all interested parties.
37


Why deregulate the US electric utility industry, the worlds most reliable and
cheapest system?
There were three primary reasons: [68]
1) to reduce the cost of electricity through new technologies and improved
business decisions.
Anticipated annual cost savings were estimated at:
$250.00 for each residential household (based on a typical family of
four $20,000,000.00 national total)
$ 100,000.00 for each industrial customer
Reduced electricity costs totaling $3.8 to $5.4 billion per year
2) to accelerate the introduction of new generation technologies; and
3) to provide regions (e.g. California and the Northeast) with expensive
electricity access to cheaper electricity that existed in other US regions (e.g.
Northwest and Midwest (Figure 3-7).
38


Figure 3-7 Cost of Electricity. Residential Rates (cents per kWh) [18]
Its important to note that FERCs deregulation efforts apply only to the
generation sector at the national level. Deregulation, would move the generation
sector from a regulated industry to a competitive, market-based environment where
utility and non-utility generating companies (GENCO) would compete for customers.
Markets would dictate which would survive.
The industry needs restructuring to ensure transmission system open access for
the competing generating companies. The transmission sector would remain
regulated, and restructured to promote open access to all GENCOs.
Order 888s primary objective was to promote generation sector competition and
provide non-utility generators (EWGs, IPPs, QFs) and utility generators open access
to the transmission system. The primary provisions to accomplish this were: 1) all
jurisdictional utilities were required to file an open-access transmission tariff; 2)
39


require IOUs to functionally un-bundle wholesale generation from transmission
services nationally; reciprocity for non-jurisdictional utilities; recovery of
generation-related stranded costs; and allow other areas of utility operations like
ancillary services, comparable service, mergers, etc.
The industry would be restructured through the creation of entities termed
Independent System Operators responsible for operating the transmission system, and
requiring jurisdictional utilities to unbundle their generation and transmission
functions (Figure 3-8). Functional unbundling would separate the ties VIUs had
between generation and transmission thus removing discrimination, allowing open
access to transmission and promoting generation sector competition.
GENCOs ____
(Utilities &
NUGs)
ISO operates
member
transmission owners
(TOs) facilities
Native Utility
(typically)
-Distribution
Unbundled
^ functions
(Nationally)
Retail choice
(by state)
Figure 3-8 Industry Restructuring Unbundled Functions
Independent system operators (ISO) would be created (Figure 3-9). Order 888
outlined 11 ISO operational principles and guidelines. It made ISOs responsible for
40


operating the transmission system, OASIS, generation dispatch (and queue) and the
ISO control area power markets (generation and transmission).
ISO Responsibilities
Transmission sector
*State-based Control Area (typically)
^System operations, OASIS, market
* Non-profit, operating costs only
Generation sector
ISO dispatches generation
Operates market and queue
ISO
IOU1
Co-op
, FPMA

IOU211
Muni,,
I
Distribution
1
Customers
Figure 3-9 ISO Responsibilities
3.5.1 ISO Operational Principles (& Responsibilities):
The ISOs governance should be structured in a fair and non-discriminatory
manner.
An ISO and its employees should have no financial interest in the economic
performance of any power market participant. An ISO should adopt and
enforce strict conflict of interest standards.
An ISO should provide open access to the transmission system and all
services under its control at non-pancaked rates pursuant to a single,
unbundled, grid-wide tariff that applies to all eligible users in a non-
discriminatory manner.
41


An ISO should have the primary responsibility in ensuring short-term
reliability of grid operations. Its role in this responsibility should be well-
defined and comply with applicable standards set by NERC and the regional
reliability council.
An ISO should have control over the operation of interconnected
transmission facilities within its region.
An ISO should identify constraints on the system and be able to take
operational actions to relieve those constraints within the trading rales
established by the governing body. These rales should promote efficient
trading.
The ISO should have appropriate incentives for efficient management and
administration and should procure the services needed for such management
and administration in an open competitive market.
An ISOs transmission and ancillary services pricing policies should
promote the efficient use of and investment in generation, transmission and
consumption. An ISO or an RTG of which the ISO is a member should
conduct such studies as may be necessary to identify operational problems or
appropriate expansions.
An ISO should make transmission system information publicly available on
a timely basis via an electronic information network consistent with the
Commissions requirements.
42


An ISO should develop mechanisms to coordinate with neighboring control
areas.
An ISO should establish a first instance dispute resolution process.
3.5.2 Provisions of Order No. 888
This section summarizes the provisions of Order No. 888.
3.5.2.1 Scope of the Rule
To achieve the goals of Order 888 the following were FERCs final rules as they
pertain to the topics shown below.
Functional Unbundling. Utilities that use their own transmission system
for selling and purchasing electrical power must be separated from other
activities like generation and distribution.
Market-Based Rates. In order to sell electricity at market-based rates,
whether from new or existing capacity, the seller must not have or must have
mitigated market power in generation and transmission and not control other
barriers to entry.
Merger Policy. Mergers will be allowed if FERC determines them to be
pro-competition.
Contract Reform. Current contracts are not voided under this rule.
Contracts may be modified but only after the approval of FERC.
43


3.5.2.2 Legal Authority
Under sections 205 and 206 of the Federal Power Act (FPA), FERC has the authority
to oversee the restructuring of the United States high-voltage transmission system.
3.5.2.3 Comparability
Any entity wanting to buy or sell electricity must provide the same level of service
they would give themselves. This applies to transmission capacity used presently and
that for future use.
3.5.2.4 Ancillary Semces
The following six (6) ancillary services, required for proper operation and reliability
of the grid, are required to be included in the transmission tariff. The transmission
provider must offer these six ancillary services. The ancillary services are:
Scheduling, System Control and Dispatch Service
Reactive Supply, and Voltage Control from Generation Sources Service
Regulation and Frequency Response Service
Energy Imbalance Service
Operating Reserves Spinning Reserve Service
Operating Reserves Supplemental Reserve Service
3.5.2.5 Real-Time Information Networks
This item addresses the creation of an independent, objective, real-time transmission
information system known as an Open Access Same time Information System
(OASIS). The OASIS system will be discussed in more detail in the next section.
44


3.5.2.6 Coordination Arrangements
Each public utility must unbundle their existing, pre-Order 888 transmission rates and
take service under their new tariffs created under the requirements of Order 888. By
breaking up existing agreements, preferential transmission pricing and access will be
eliminated creating comparability or equal access to the transmission system
3.5.2.7 Pro-Forma Tariff
The goal was to initiate open access to the transmission system, owned and/or
operated by others, through pricing mechanisms that force the owning and/or
controlling utility to charge eligible customers the same they would charge
themselves for its use (for both point-to-point transmission systems, network
transmission systems and ancillary services).
3.5.2.8 Implementation
Deadline for submitting this open access tariff: July 9, 1996.
3.5.2.9 Federal and State Jurisdiction: Transmission/Local Distribution
FERC asserts it has jurisdictional authority over unbundled and wholesale (wheeling)
transmission. Jurisdictional boundaries are set by seven tests for determining which
facilities are transmission and those that are distribution.
3.5.2.10 Stranded Costs
Utilities were allowed to recover stranded costs in generation and transmission
sectors associated with long-term contracts made under the regulated environment
previous to deregulation efforts. One example of stranded cost recovery was in the
45


form of an exit fee paid to the utility by the customer if they were changing
providers.
3.6 FERC Order No. 889 121. f31. f91
Order No. 889 mandated the sharing of transmission system information, previously
exclusive to VIUs, through the creation of an Open Access Same-time Information
System, or OASIS. OASIS made this information transparent to all interested
parties, which addressed the issue of insufficient sharing and knowledge of
transmission system information, which was one way VIUs had discriminated against
IPPs (as reported to FERC) in the past. Typical types of information included on
OASIS sites are:
Transmission Services: Available and Total Transfer Capacity, Available
Service(s), etc.
Ancillary Services Information
Tariff Information
46


3.7 Post FERC Order Nos. 888 & 889 [31. T81. T91. f391. T401. 1411. T441. [451. T511
ISOs proposed after Orders 888 and 889 were typically organized by state boundaries
or slightly larger areas (Figure 3-10).
Figure 3-10 ISOs Proposed
After operating under the provisions of Order 888 for several years, FERC
determined that substantial barriers to functional deregulation continued to exist,
specifically inadequate geographic scope, and would need to be corrected. As a
means to that end, FERC issued Order No. 2000 on Dec. 20, 1999.
3.8 FERC Order No. 2000 [31. [41.191
Order 888 had two primary shortcomings: inefficient operation and expansion of the
transmission system; and continued transmission system access discrimination. Order
No. 2000, FERCs second attempt at wide-sweeping changes in how the electric
47


utility industry operated, was issued primarily to address these two issues. Other
benefits were anticipated, lower electricity prices plus a creation of lighter handed
regulation.
FERC believed that transmission would be more effective and efficient (cheaper) if it
were addressed on a regional, multi-state scale. This is important because electricity
follows the laws of physics, not the boarders established by laws of man. All states
within an interconnection are impacted by disturbances within it, as evidenced by the
Western interconnection (WECC) disturbances in the summer of 1996. ISOs should
be larger than just the state boundaries, FERC asserted. To that end, the Commission
created Regional Transmission Organizations (RTO) intended to replace its ISO
predecessor. FERC intended to have transmission as reliable now as it had been
before deregulation.
Under FERCs plan, RTOs would operate the transmission facilities (above 69kV) of
their member transmission owners (TO) that comprised an RTOs control area, but
these organizations would be larger, appropriately-sized versions of their ISO
predecessors (Figure 3-11). RTOs, through their guidelines, would end continued
transmission system access discrimination.
48


At or near this time, Independent Transmission Companies began to appear. An ITC
is a collection of transmission owners combining to form one large transmission
company (e.g. TRANSLink). FERC specified that ITCs could participate as a
member of an RTO or form their own. Therefore, an RTO could be a non-profit
organization which was previously an ISO or it could be a regulated for profit
Transco.
In order to be an approved RTO, certain guidelines (FERC approved) had to be met.
These guidelines consisted of four characteristics and eight functions, discussed in
greater detail (sections 2.8.1 and 2.8.2). The ISOs already in operation were required
to prove they met these criteria to receive FERC approval as an RTO. There were
differences between RTOs and ISOs. RTOs could be operated to earn a regulated
profit for financing infrastructure expansion, whereas ISOs were non-profit
49


organizations. Another significant difference was that RTOs typically encompassed a
larger geographic area than their ISO predecessor. FERC encouraged a voluntary
approach for transmission owners to hand over control of their facilities to an RTO of
which they were a member.
Specific points addressed by the FERC Order 2000 were:
3.8.1 Approach to RTO Formation
FERC felt the following approach (to RTO creation) was best.
Voluntary Approach. A voluntary approach should be used.
Organizational Form. Proposed structures could vary from a non-profit
ISO to a regulated profit Transco or a hybrid as long as the proposed RTO
meets the minimum characteristics, functions and other requirements of
Order No. 2000.
Degree of Specialty in the Rule. These are flexible, non-specific
guidelines and goals for proposed RTOs to follow and meet with a feeling of
teamwork.
Legal Authority. FERC has the authority to oversee RTO formation in
accordance with sections 205 and 206 of the Federal Power Act.
3.8.2 Minimum Characteristics of an RTO
FERC felt proposed RTOs should meet the following four minimum characteristics.
Independence. The RTO must be independent of market participants.
50


Scope and Regional Configuration. The RTOs region (control area) must
be large enough, with regard to scope and regional configuration, to
effectively perform its required functions.
Operational Authority. The RTO will have complete authority for the
operation of the transmission system its controlling.
Short-Term Reliability. The RTO will be responsible for and have the
authority to maintain the short-term reliability of the transmission grid it
controls.
3.8.3 Minimum Functions of an RTO
FERC felt proposed RTOs should meet the following four minimum functions.
Tariff Administration and Design. Tariff administration and design shall
be the exclusive responsibility of the RTO.
Congestion Management. Congestion management policies shall be the
exclusive responsibility of the RTO.
Parallel Path Flow. Concerns and problems arising from parallel path
flows shall be addressed within a three (3) year period of the start-up date.
Ancillary Services. Ancillary services, as defined by Order No. 888, shall
be provided by the RTO on a competitive basis where possible.
OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC). The RTO shall have one OASIS node
and shall be responsible for all information placed on it.
Market Monitoring. The RTO is responsible to provide an objective
market monitoring plan to prevent and/or mitigate market power.
Planning and Expansion. The RTO must develop a system planning and
expansion plan.
51


Interregional Coordination. Each RTO is to ensure the integration of
reliability practices within an interconnection and market interface between
regions.
3.8.4 Open Architecture
An open architecture style of organization (structure, regional scope, market and
operations) will be allowed and give the proper flexibility to evolve with the needs of
the electricity market it operates within.
3.8.5 Transmission Rate Making Policy
Each RTO should develop rates taking into consideration the following:
Pancaked rates should be eliminated (reduce electricity costs).
Reciprocal waiving of access charges between RTOs.
Uniform access charges for all RTOs.
Congestion pricing mechanism development to properly address associated
costs.
Service to transmission-owning utilities not participating in an RTO will
have a separate and different tariff.
Performance-Based Rate Regulation (PBR) containing financial incentives.
Incentive-based transmission service rates which are unique and innovative.
3.8.6 Other Issues
The following issues were addressed:
Public power entities are encouraged to place their transmission facilities
under RTO control for an effective transmission system.
52


Canadian and Mexican entities participation are encouraged.
Existing contracts wont be automatically dissolved by FERC, but will be
addressed by RTO.
RTOs will determine a need for power exchanges.
Effect on states with low-cost generation will be to lower to cost in the long
run.
No specific states roles were stated, but generation siting is one example of
states roles.
Uniform System of Accounts will continue to be used, modifications to it are
encouraged.
Bid-based markets are expected to be central to RTO formation. Markets
shall address multiple products (supply and demand), feasibility, real-time
balancing, market participation, demand-side bidding, market information
and monitoring and several others.
3.8.7 Collaborative Process
A regional, voluntary, collaborative process should be used to create RTOs involving
all interested parties.
3.8.8 Deadline for RTO Operation
RTO Startup December 15, 2001
3.9 Post FERC Order NO. 2000 151.1141. 1191.1171.139-541
RTOs proposed after Order 2000 were typically geographically larger than their ISO
predecessors, but were still not as large as FERC believed necessary to be truly
effective. FERC envisioned five RTOs for the entire U.S. transmission system -
53


Northeast, Southeast, Midwest, Texas and the entire Western Interconnection
(Figure 3-12).
ERCOT
Figure 3-12 FERCs RTO Vision 1141
This did not occur. Instead thirteen separate, non-continuous RTOs were initially
proposed, each with its own unique transmission and wholesale market rules (Figure
3-13).
Figure 3-13 Actual Proposed RTOs [701
54


FERC did not approve several of these RTOs and requested they combine with a
neighboring RTO. The number of proposed RTOs decreased to nine, but each still
retained its own operating rules.
As a result of this patchwork landscape, a problem arose at the boundaries of
neighboring RTOs referred to as seams issues. Due to their different operating
rules, seams are problems related to resolving schedules and payments for electrical
service when coordinating power flows between RTOs. As reported to FERC, seams
issues allowed continued open access discrimination (to transmission) and
impediments to wholesale power competition. Inadequate geographical scope of
RTOs continued to plaque restructuring and deregulation efforts by allowing
discrimination to continue. To correct this, FERC issued the Standard Market Design
(SMD) Notice of Proposed Rulemaking (NOPR) on July 31, 2002.
3.10 Standard Market Design (SMD) Notice Of Proposed Rulemaking 1NOPR)
In general, and a continuing theme, the goal of FERC by issuing SMD was to build
on Order 888 and create a transmission sector that operates in a fashion that ensures
the anticipated benefits of a competitive wholesale electricity market (generation
sector) is delivered to all consumers.
To that end, the primary goal of SMD was to eliminate seams issues by standardizing
the way generation and transmission markets would work for all RTOs. This design
would also create an effectively larger geographic region, which FERC also
preferred. It was believed SMD would also better mitigate market power, promote
transmission planning and expansion, lower the cost of electricity and create a
framework for cooperative state and federal regulation.
55


To accomplish this goal, major provisions of SMD called for the introduction of
independent transmission providers to replace RTOs. ITPs would retain many RTO
responsibilities, plus others, to accomplish the primary goal of SMD (Figure 3-14).
This 1TP entity would be responsible for ensuring the transmission grid viability to
meet the nations needs (Figure 3-14). Therefore RTOs and ISOs could apply to be
approved as an Independent Transmission Provider (ITP).
ITP Responsibilities
Transmission Sector:
Essentially replaces RTO
Effectively larger RTO
^Operates system, OASIS, market
^Facilities owned by TOs
* Market monitoring, adequacy,....
Generation Sector:
* Essentially same as RTOs
Figure 3-14 SMD & Seams Issues
Under the SMD proposal, jurisdictional utilities had to file new transmission tariffs.
Non-jurisdictional utilities would follow reciprocity guidelines established under
Order No. 888. Locational marginal pricing and congestion revenue rights were
introduced as new transmission pricing policies to address the transmission
congestion issue. FERC asserted it had jurisdictional authority over bundled
transmission, market power and, if required, mitigate market power abuses. Finally,
56


FERC proposed to develop resource adequacy guidelines and a regional planning
process to sustain a viable electrical power system.
3.10.1 Summary of SMD Primary Provisions [4], 15], [191, 169]
Creation of an independent transmission entity termed Independent
Transmission Provider (ITP) to replace RTOs, and assign to it the tasks
required for design, operation and growth of the nations high voltage and
extra-high voltage transmission network.
Remedy continuing undue discrimination in receiving transmission service
by issuing and enforcing a single, nondiscriminatory open access
transmission service tariff (based on Network Access Service of Order 888),
thereby level the playing field for all market participants. This tariff would
be administered by FERC and applied to wholesale transmission (wheeling),
unbundled transmission (ITPs) and bundled transmission (load serving
entities).
Eliminate seams between regional electric wholesale market by creating
and mandating the same rules for: 1) reserving and scheduling transmission;
and 2) scheduling generation.
Require all jurisdictional transmission owners (TO) to join an FTP and
relinquish operational control of their transmission facilities to this ITP.
Expand FERC jurisdiction to include bundled retail transmission service in
addition to wholesale transmission and unbundled retail transmission service
it presides over today.
57


3.10.2 Summary ofITP Responsibilities
Operation of a pricing mechanism for providing transmission service termed
Network Access Service (NAS). NAS consists of two components: one
similar to Network Integration Transmission Service and one similar to
Point-to-Point Service, both presently used today. All services required for
effective transmission service will be addressed (i.e. ancillary services).
Network access service allows flexibility in transmission service options
while integrating resource and loads (similar to Network Integration
Transmission Service of today) in addition to providing specific
reassignment rights of transmission service agreements as long as the
reassignment transaction is feasible under security-constrained guidelines
(similar to Point-to-Point service of today).
Network Access Service charges are intended to recover the embedded costs
various TOs have invested in the transmission grid. The NAS will operate
day-ahead and real-time markets for transmission service and ancillary
services. FERC anticipates bilateral contracts, long-term and short-term
between supplier and customer, to make-up a predominant portion of the
transmission service arrangements. The spot market will make up the
remainder of required transmission service arrangements needed to fulfill all
electrical service needs. The spot-market will be operated in the day-ahead
and real-time mode (long-term bilateral contracts are scheduled every day,
in the day-ahead market).

Operate a congestion management system known as Locational Marginal
Pricing (LMP), and Congestion Revenue Rights (CRR) described in


section 3.12 Present Day Pricing Mechanisms. This system uses
differential pricing on a nodal, or substation bus, basis to assign costs for
electricity based on what generation units are dispatched which results in no
system overloads, as explained in previous section.
Congestion Revenue Rights (CRRs) were intended as a hedging mechanism
to lock in transmission service costs (offset additional costs for transmission
service as a result of nodal generation costs which might be higher than
other nodes within the transmission system). CRRs will be allocated to
entities serving native load and others that wish to purchase it via auction, as
explained in the previous section. Assigning or purchasing CRRs may
change or evolve over the next four years after practical experience using
them is attained.
Operate energy imbalance markets to allow market participants to sell or buy
their imbalances in a fair and nondiscriminatory manner.
Oversight to ensure customer service after issuance of SMD is equal to or
better than present levels prior to the issuance of SMD.
Authority to develop market power monitoring and mitigation procedures
for the day-ahead and real-time markets.
Assure long-term adequacy of electrical energy generation and delivery
systems on a regional basis.
59


Involve representation from states, and their input, in how UPs operate the
grid in their respective state. This may apply to many aspects of ensuring
grid reliability (i.e.- planning and operation) to ensure their specific,
legitimate and reasonable requirements are met.
Authority to require all users of the transmission system comply with all
standards to ensure transmission system reliability and security.
3.10.3 Schedule for SMD Operation
July 31, 2003 An INTERIM OATT must be filed by jurisdictional
transmission utilities (own, operate or control).
December 1, 2003 All jurisdictional transmission utilities that must file a
revised OATT that meets or exceeds SMD guidelines, which will become
effective no later than September 30, 2004, or other date as determined by
FERC.
September 30, 2004 OATT filed that includes bundled retail transmission
for all public transmission utilities.
3.11 Post SMD NOPR r51. H91. T321. T341. T381
Some states (Northeast, Midwest and Texas) and utilities approved of SMD while
some (Southeast and Northwest states) did not. Those that did not approve of SMD,
and voiced strong opposition to it, were concerned with: 1) jurisdictional overreach
by FERC, 2) destabilizing economic effects (cost shifting) and participant funding, 3)
incomplete operational specifics of how the markets will work and 4) inadequate
attention to regional needs.
60


As a compromise, FERC issued a white paper on April 28, 2003. The new term for
SMD is now Wholesale Power Market Platform (WPMP).
Primary features of the WPMP are: 1) it allows regional flexibility, 2) it permits cost
benefit studies to justify certain functions, and 3) it requires seams issues be resolved.
The term RTOs will be retained and ITP will not be used.
3.12 Present Day Pricing Mechanisms fll, f 151, [411
This section will acquaint the reader with terms and a broad understanding of the
various pricing mechanisms in use today and proposed for the future. An in-depth
analysis of each of mechanism lies outside the scope of this document (for they each
could be a thesis).
The deregulation of the generation sector (wholesale market) and restructuring of
the industry (elimination of the vertically integrated utility through functional
unbundling) has created the need to develop other pricing mechanisms to account for
providing the many invisible functions the vertically integrated utilitys bundled
pricing mechanisms performed. Todays pricing mechanisms can be grouped into the
following broad categories: 1) generation, 2) transmission, 3) distribution, 4)
ancillary services, and 5) demand response.
In the end, there will most-likely be three separate line items that will comprise
electricity bills one line each for generation costs, transmission costs, and
distribution costs.
61


3.12.1 Electronic Tasking System [20]
The system by which all electrical service transactions are performed within the
industry today uses the Electronic-Tag or E-Tagging system. E-Tagging was
developed by NERC in 1995 for addressing the operational needs of the new and
evolving deregulated environment the electric utility industry now found itself in. E-
Tagging is the process by which an electronic identifier is tagged to a packet of
electricity. This packet contains a large amount of information specific to that
transaction. A small representation of this information included within an E-tag is as
follows:
electricity quantity: MW amount
point-to-point location information: BUS A to BUS B
type of service paid for: firm or non-firm contract agreement (firm
meaning high reliability, non-firm meaning lower reliability, service can be
disconnected for economic reasons)
There are many more types of data associated with this tag, but hopefully this gives
the reader a general idea as to what kind of information is included within an E-tag.
3.12.2 Summary: Present Day Pricing Mechanisms
This section will acquaint the reader with the general pricing mechanism concerns,
and functional concepts present today, not an in-depth analysis.
For ease of explaining the new operating characteristics of deregulated generation
market and restructured transmission market, the familiar sectors of generation,
transmission and distribution pricing mechanisms will be addressed first, followed by
the ancillary market and demand response mechanisms.
62


3.12.3 Functional Concepts & Concerns: Present Pax Pricing Mechanisms
The intent of this section is to provide the reader with enough information pertaining
to each mechanism for a working knowledge and understanding of each. We will
discuss, in order, the following sectors: generation, transmission, distribution,
ancillary services, and finally demand-response. Because this thesis addresses the
transmission sector primarily, the distribution sector will not be discussed in as much
detail (as the other sectors) and lies outside the scope of this document. These pricing
mechanisms reflect all mechanisms used throughout the RTO landscape of today.
The term RTO will be used since that is the present term approved by FERC when
referring to transmission sector operations.
3.12.3.1 The Generation Market Pricing Mechanism
Because the generation sector (wholesale power market) is the only truly competitive
market within the industry today, we start here. This market has generating
companies (GENCOs), both with and without roots to vertically integrated utilities,
competing against one another for the ability to supply electrical energy to meet the
load requirements of the Regional Transmission Organization RTO as determined by
the RTO schedulers. Schedulers are RTO employees that record requests for
electrical service from the RTO customers. There are many schedules received by the
RTO, which then sums up these many service requests and then in turn must find an
adequate quantity of GENCOs to satisfy this sum of service requests. Each scheduled
electricity service request must be fulfilled by the RTO. This responsibility is in the
hands of the RTO system operators. Operators, as the title suggests, operate the
transmission system of the RTO to deliver electricity to their scheduled customers.
63


GENCOs bid on the electrical energy service requirements of the RTO. The low
bidder(s) will be selected until the RTO service requirements are met and then it will
pay the highest bid ($/MWh) to all GENCOs.
Two markets will be operated for the generation sector, they are the day-ahead and
real-time markets. The day-ahead market is expected to address most service
requirements since they tend to be long in duration by nature through long-term
bilateral contracts. The real-time, or spot-market is expected to address any
outages unforeseen in the day-ahead market, and it is security-restrained, bid-based.
Security-restrained, bid-based refers to those measures to assure operations will not
jeopardize grid reliability, while bid-based describes the proposed auction for
imbalance energy. These two markets will trade both electrical energy and ancillary
service requirements.
In addition to these two generation markets, a pricing mechanism called Locational
Marginal Pricing (LMP), developed by PJM, will impact the cost of electricity as
supplied at generation busses or nodes. LMP will be discussed in greater detail in
the Transmission Service Market Pricing Mechanisms, but is mentioned briefly
here for the aspects that affect the generation market. LMP is a tool to relieve
transmission congestion, indicate where congestion exists on the system, and assign
additional costs to congestion at each specific generation bus (node). These
additional costs are passed on to customers but as a result, there are surplus revenues
paid to the RTO. Therefore, if there is congestion on the system, electricity costs at
generation busses is increased by the RTO and the RTO will take in more money than
it pays out. In the case of PJM, where they operate non-profit, this revenue surplus is
refunded to the various GENCOs.
64


Installed capacity requirements will be determined by the LSEs who are responsible
for guaranteeing the load requirements of their customers. LSEs will also pay for real
power losses of the system, which means if their loads total 250MW with a
corresponding 5MW of losses, then the LSE will have to schedule 255MW of
electrical power.
Previous generation markets did not always function as expected due to lack of
generation capacity, lack of transmission capacity, flawed market rules, and unethical
business practices (ENRON) which resulted in price volatility and blackouts as was
witnessed in California.
Under these new market pricing mechanisms, it is anticipated a majority of market
manipulation techniques discovered as a result of the California debacle will be
prevented. Lessons learned from previous generation market failures (California) and
successes will be applied to subsequent FERC rulings addressing deregulation and
restructuring.
3.12.3.2 Transmission Service Market Pricing Mechanism(s)
This section addresses the pricing mechanisms RTOs will use for pricing
transmission services.
Bilateral Contracts, Long and Short Term
The primary pricing mechanism anticipated to be used for all RTOs nation-
wide will use bilateral contracts. A bilateral contract for electricity is an
agreement between a buyer and seller for the sale and purchase of electrical
energy, or Firm Transmission Rights. It is anticipated these contracts will
be used extensively to lock-in electricity costs, since LMP may cause
65


V
electricity costs to fluctuate (increase) during system congestion. The short-
term transmission markets, explained later, will be designed to
accommodate and complement these bilateral agreements.
Network Access Service
This service will consist of a single access fee plus a region-wide
transmission rate. The single access fee will recover the transmission
owners embedded/stranded costs associated with transmission
infrastructure and the region-wide transmission rate will be the cost
associated with the use of the transmission system. The region-wide
transmission rate may be license plate, postage stamp or zonal.
All three transmission rate pricing mechanisms are designed to improve the
amount of or eliminate altogether pancaking of transmission rates.
(Pancaking refers to summing of transmission tariffs across all involved
service areas.)
License Plate Rate Pricing
This reference is derived from how license plates work in that if you buy a
license plate for your car in your state, you have access to the entire United
States region.
Similarly, this transmission service pricing mechanism charges a single rate
for transmission service in the geographic sub-region within the RTO where
the transmission service is delivered. The transmission customer then has
access to the entire RTO region. The transmission rate under the license
plate pricing mechanism is based on the embedded cost of the transmission
infrastructure where the service is received.
66


Within a RTO there will be different rates for transmission service for each
RTO sub-region, which is usually based geographically on control areas.
Each sub-regions rates are based on or calculated from the embedded costs
similar to how the cost-based tariff system worked.
Therefore, like a license plate, in which there are different costs in each
state, once you buy a license plate in your state you can drive anywhere in
the United States. Applied to transmission, you buy transmission service in
your RTO sub-region, which gives you access to electricity attained
throughout by the RTO in its entire regional control area.
Although this mechanism is successful in eliminating pancaking of rates, it
creates other problems related to transmission of electricity. Specifically it
does not 1) allow owners of the transmission infrastructure it traveled over
to recover their embedded costs, thereby shifting those costs to those native
customers not benefiting from this service and 2) support long-term
transmission infrastructure investment to connect low-cost generation to
customers located far away.
This is the most prevalent pricing mechanism in RTO filings made to date,
which is unfortunate.
Postage Stamp Rate Pricing
This pricing mechanism uses one rate for transmission service, throughout
entire RTO control area independent of geographical location within the
system. The embedded cost of all transmission owners embedded costs are
i
67


averaged together and used as the basis to create the transmission service
rate.
It derives its name from how a postage stamp is used. Like a postage stamp
which is the same price in every state for a class of service throughout the
U.S., electricity service is the same price throughout the entire RTO control
area for a type of service.
This pricing mechanism also prevents pancaking and it allows embedded
costs to be recovered but it too creates other problems.
Two such problems with the postage stamp pricing system are: 1) it
promotes more expensive transmission systems and 2) low cost transmission
providers, either through high load density or through cost containment
processes, will be at a disadvantage since they will be either punished for
their system makeup or rewarded for their cost-containment processes. This
system treats low load density systems favorably by shifting costs to the
higher density systems. ISO New England and New York ISO uses this
mechanism.
Highway-Zone
This transmission service rate pricing mechanism employs the best
attributes of license plate and postage stamp pricing mechanisms.
Instead of excessive generalizations to one extreme or the other, the zonal
approach creates transmission service rates based on transmission system
usage. The transmission system is broken up into either highway or zonal
systems. Highway systems are energized at higher voltages (>200kV) and
68


tend to be regional while zonal systems are energized at lower voltages
(<200kV) and tend to be local (Figure 3-15). Because of this breakdown,
highway rates are postage stamp based, while zonal rates are license plate
based.
Zonal rates are further broken down into supply and load zone rates. Supply
zone rates correspond to recovering facility infrastructure costs associated
with generator interconnection facilities for supplying electrical energy.
Load zone rates apply to facilities that supply load.
Supply zone rates are typically applied to facilities energized at 115kV and
above that are not included within the Highway so the costs for these
facilities can be recovered.
The load zone is applied to all facilities not included in the Highway or
Supply Zone which are energized at lOOkV or less. Load zone rates are also
load Density dependant meaning higher transmission service rates for
lower load density areas and vice versa, as a mechanism to further increase
accurate revenue recovery.
69


Zone 1 Zone 2 Zone 3
1 r m mmm wmm mmm mmm M V * mmm 1 1 1 1 1
>=200kV1 1 mgmsMi iiipiippai:::,:: i 3^
1 1 115-161 kV. j i1 ,1 ii ii
1 I i' ii 1 |
<= 100 kVl i|_ i . 1 1 i
l l Allocation to Load Zonal Rate
I I Allocation to Generator Zonal Rate
Figure 3-15 Highway-Zonal Tariff Graphic [46]
Congestion Management
Congestion occurs when system transfer requests exceed the transmission
system ability to transfer electricity. The mechanisms the SMD has
proposed to address transmission congestion are locational marginal pricing
(LMP) and congestion revenue rights (CRR).
Locational Marginal Pricing
Locational Marginal Pricing (LMP) is designed to identify congestion
points, also called flowgates, assign costs of congestion which are then
passed on to customers.
The LMP pricing mechanism is the recommended choice for managing
congestion nation-wide. The intent of this pricing mechanism is to relieve
congestion by dispatching the cheapest generation possible given real-time
system conditions. By using the LMP mechanism, it is expected that the
70


cheapest possible generation will be dispatched, congestion will be avoided
and market abuses, like those seen in California will be prevented.
Locational Marginal Pricing (LMP) is used by PJM/PJM West to determine
electricity costs at each node throughout system in real-time. LMP uses
real-time information to determine electricity generation costs at each
supply node throughout PJM system. These nodal generation costs are what
the GENCOs are paid by the Transmission Provider.
LMP is defined as the marginal cost of supplying the next increment of
electric demand at a specific location (bus or node) oh the electric power
network, taking into account both generation marginal cost and physical
aspects of the transmission system. As mentioned previously LMPs are
nodal and provide market pricing signals associated with congestion. If the
transmission system is unconstrained or uncongested, LMPs are the same
value each node throughout the transmission system (Figure 3-16 through
Figure 3-18).
To explain this further, figure 3-16 shows a dispatchable system which
results in no congestion. The corresponding power flows (red arrows)
shown in Figure 3-17 are below the thermal capacity of the transmission
system. Therefore, since there is no congestion, all system nodes or busses
have the same price for generation costs. Economic dispatch of the cheapest
generation can occur since all load can be supplied without exceeding the
transmission thermal capacity, therefore all LMPs are the same or equal.
71


Figure 3-16 Dispatched Generation Without Transmission Congestion (411
Energy Flow
E
Brighton
240 MW
1 hernial Limit
Sundance
200 MW
SJO/MW h
600 MW
SIO'MWh
110 MW
SI4 MW h
-23 MW 223 MW
Park City g
100 MW
SI5'MW h
c
Solitude
520 MW
S30/MW h
Figure 3-17 Energy Flow Without Transmission Congestion [411
72


LMPs
Brighton
Hi600 MW
600 MW
S10/MW h S14 A
Alta
2f MW,
1 normal I .miit
&
Sundance
200 MW
$30'MW It
III) MVi
S14'.MW It
^iL: 23 MW 223 MW
Park Citv B
100 MW
SI5/MW It
$14 $14
Solitude
520 MW
S30/M W h
Figure 3-18 LMPs Without Transmission Congestion [411
If the transmission system is constrained or congested, LMPs vary by node (bus)
throughout the system (Figure 3-19 through Figure 3-23). LMPs are based on actual
energy flows and actual system operating conditions (i.e. planned outages). The
factors that impact LMP values are: 1) Demand for Energy, 2) Available Generation
for Dispatch, 3) Economic Dispatch of Generation, 4) Transmission Network
Configuration, and 5) Transmission Constraints. The PJM transmission system
operating conditions are given from the PJM state estimator. From this information,
electricity prices are calculated for each node on the system, which is repeated every
5 minutes. Accounting settlements occur hourly, so the 5 minute LMPs are integrated
at the end of the hour period to determine the hourly cost.
Figure 3-19 shows a system which results in congestion. Generation and loads are
bid. The corresponding power flows (red arrows) shown in Figure 3-20 are above the
thermal capacity of the transmission system specifically on the bus E-to-D line. To
avoid thermal damage to this line, generation will have to be dispatched non-
economically, or more expensive generation will need to be used (Figure 3-21).
73


Loads and Generator Bids
240 MW
I hernial Limit
Brighton -
600 MW
SlO/MW'h
Alta sJLi aUiL
\B \C
110 MW Park City J
$14/MWh ioo MW
$15/MW'h
Sundance
200 MW
i£35v 'iiUJMW h
Loads = 300 MW
oad = 300 MW
Solitude
520 MW
S30/MWH
Figure 3-19 Load & Generator Bids [41]
Dispatched
at 600 MW
Brighton
240 MW
I hernial Limit
600 MW
SI0/.MW h
110 MW
S14/.MW h
Dispatched
at 110 MW
<00 MW
Dispatched
3m
oO MW h
Sundance
ZHi&r
a00 MW
Pari
100 MW
SI5/.M W h
Dispatched
100 MW
1 Solitude
520 MW
S30/MW h
Total Dispatched
900 MW
74
Figure 3-20 Dispatch Solution Ignoring Thermal Limits (of Transmission Line) [41]
74


Actual Dispatched Generation
600 MW
SlOMWh
110 MW
SI4MW h
Dispatched
at 110 MW
1HI iill
" Fa" C i
S2S
(M) MW MW
ilv B C
100 MW
SI5/MW It
Dispatched
at 66 MW
Dispatched
at 124 MW
Sundance
200 MW
S50 \1\\ It
OK) MW
Solitude
520 MW
SJO'MWh
total Dispatched
900 MW
Figure 3-21 Actual Dispatched Generation Accounting for Congestion [41]
Since there is congestion, and more expensive generation needs to be dispatched to
meet the 240MW thermal limit of the E-D line (Figure 3-22), the cost of electricity
will be different on all system nodes or busses (Figure 3-23) as calculated from real-
time data retrieved from the system (Figure 3-24).
Energy Flow
E
240 MW
I hernial Limit
Brighton I"
,600 mw I-
jir
600 MW
SIO/MWh
240
Alta
110 MW
SI4/MW h
100 MW
SI5/MW h
200 MW
S.tO MW
^ Sundance
124 MW
Solitude
520 MW
SJO/MW h
Figure 3-22 Actual Energy Flow Corresponding to Actual Dispatch f411
75


LMPs
$10.44
24 MW.
$30
200 MW
mo \iwh
S ii >ce
Brighton
^^^00 MW
600-'m $15 A-
SlO/MWh
Alta
110 MW
SI4/MW li
inf
imil? $^1.14 C$23.51
Slim& 1
SOU MW 0)0 \|W
Solitude
520 MW
S30/.MW h
100 MW
S15/.MW h
Marginal Generators
Figure 3-23 Actual LMPs Corresponding to Actual System Conditions [411
Park City and Sundance supply the next increment of load on the
system
Attempt to serve an additional increment of load (1 MW)
Resulting Sensitivity factors determine L.Y1P
Bus 1 itt-ntinn Sensitivity factors for 1 VI Wh nf 1 n:id MinnlitM trnm1 Calculation Details
Park City Sundance it
S15 MWh 530 MWh
A 1.00 MWh 0.00 MWh 1.00(515) ().()()(S30) S15
B 0.59 MWh 0.41 MWh 0.59(515) 0.41(530) = 521.14
Figure 3-24 LMP Costs for Generation f411
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Congestion Revenue Rights
Under LMP, congestion costs will vary based on the price to relieve
congestion and losses. Instead of a system of physical reservations, financial
reservation rights called Congestion Revenue Rights (CRR) will be used.
CRRs are a system of financial rights used to give transmission customers
the ability to protect themselves from uncertain congestion costs. These
rights will be used to pay the RTO offsetting the increased cost of service
due to congestion costs. Initially these CRRs will be available from receipt
point-to-delivery point obligation rights for the available transfer capability
on the grid, but not in excess of the transfer capability of the system. In the
future other CRR like receipt point-to-delivery point options and flowgate
rights may be available in the future. Under CRR there may be a situation
where the RTO owes more CRR than what it receives from increased
revenue for congestion costs. In this case this revenue shortfall will be
charged to the transmission owner whose facilities are out of service. There
will be a secondary market for trading CRRs.
3.12.3.3 Distribution Sector
The RTO customer or LSE purchases electrical service from the TO in accordance
with the pricing provisions of the OATT and then sells to their distribution customers.
These distribution sales can be either cost-based at PUC approved rates in a state
where retail access or deregulation has not been allowed or at competitive rates where
retail access or deregulation is allowed. Deregulation at the distribution level is a
state-by-state issue and is also referred to as retail (where the generation sector is
referred to as wholesale).
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3.12.3.4 Ancillary Services Sector
As defined previously, these six services that are to be provided by the RTO are
included in the tariff pricing mechanisms, if an entity, other than the RTO is to
provide these services, then they would be bid-based, similar to the generation market
mechanism.
3.12.3.5 Demand-Response Sector
The demand response pricing mechanism is bid-based as well. Customers bid to the
RTO for the cost they (the customer) can charge the RTO for interruption of their
electric service in the event that available generation will not meet load requirements
the RTO is required to supply. This is similar to the generation sector in that the
higher the bid for interruption, the less chance you have in your bid being selected.
3.13 Prices since Deregulation 1181
The following chart (Figure 3-25) shows residential prices for electricity since
deregulation efforts began. Overall there is a general rise in prices primarily due to
lack of generation supply and transmission adequacy issues. In states where
electricity costs declined before this rise (e.g. California), state PUCs mandated
service rate reductions for all customers before native utilities could enter into the
deregulated retail choice markets. Many states reported electricity cost savings as a
result of deregulation and the corresponding improved industry operations. In
actuality they werent really savings, instead theses savings were due to
mandated rate reductions by the PUC. In many cases native utilities are asking for
rate increases (e.g., utilities within Texas).
78


In addition, recent reports state that retail choice programs do not reduce electricity
costs for residential customers but may help reduce costs associated with larger
commercial or industrial customers.
Retail choice is discussed in somewhat greater detail within the next section.
----New York
California
----Pennsylvania
Michigan
Florida
Texas
----Colorado
Montana
f / #
& _cp
^ 0? ^
Arizona
Washington
tm

Figure 3-25 -Residential Electricity Costs Since Order No.s 888 & 889
79


3.14 Status of Retail Choice Within the United States [181
This topic is outside the scope of this document. A brief summary however, follows
to familiarize the reader its general terms and concepts.
Presently, the status of deregulation in states across the US is quite varied (Figure 3-
26). Retail choice is state-based and occurs within the distribution sector of the
industry.
Figure 3-26 Status of Retail Choice Within the United States [181
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Retail choice in simple terms, works this way: first, the customer, industrial,
commercial or residential, selects their GENCO only from the list of competing
GENCOs. Transmission costs will be issued through the regional RTO and the native
utility will be responsible for the distribution sector related costs. At the end of the
day, utility bills will have three separate charges for the various components of their
electrical service. One line will be correspond to the GENCO charges for generation,
one charge will be for the servicing RTO ands finally the native distribution company
will charge for the distribution-related costs associated with the electrical services
received.
That is all that will be discussed regarding state-based, retail-choice programs as they
relate to industry deregulation.
In chapter 3, we covered the reasons why certain legislation and policy was enacted
and the results. During these times of uncertainty, electric utilities have kept the
nations electric system functioning and America running. However, transmission
infrastructure investment is declining due to delays in creating a final restructuring
plan. Presently, NERC reports that system capacity appears to be adequate.
The US electric utility industry is mired in politics and regional debates, yet the
demands on the electricity system continue to grow. Our nation depends on a viable
electric utility system for its security, economy and way of life. While these debates
and political discussions continue, its viability hangs in the balance.
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Chapter 4.0 A Restructuring Model for the United States Bulk
Power System
4.1 General
The deregulation and restructuring process is constantly changing. At the time of
completing this thesis, the direction of the deregulation and restructuring process
remains unknown. In fact, the deregulation and restructuring process is beginning to
be questioned. Some states have suspended retail choice programs and others have
reversed these programs, ending deregulation efforts.
What can be done to resolve this unrest and uncertainty within the industry? If
deregulation efforts continue, a restructuring model must efficiently and effectively
transition the industry from one of vertically integrated utilities to one where the
generation sector is deregulated and the transmission sector is restructured to address
open access issues. The model must meet the needs of the nation, states and
companies which comprise it. The model must be fair to consumers and industry
participants. The model must result provide heavy oversight of the deregulated
generation sector to prevent greed. Finally, and perhaps most important, at the end
of the day, the new model must result in a viable electric utility industry that
continues to deliver reliable, cost-effective electricity to consumers.
4.2 Thesis Statement
An essential service is at stake (Figure 4-1) and it is the intent of this thesis to
introduce a restructuring model for the electrical transmission system of the United
States electric utility industry to ensure this essential industrys infrastructure is
viability now and into the future.
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Figure 4-1 An Essential Service is at Stake (Earth at Night) [71]
4.2.1 Overview of Restructuring Architecture
This thesis proposes that the present-day, non-continuous patchwork of many RTOs
be reduced to two large Independent Transmission Operators (ITO) (Figure 4-2)
under the oversight of a newly created federal agency called the National Power
Administration (NPA) (Figure 4-3). One ITO (ITO-East) would be given oversight
responsibility for the Eastern interconnected transmission system (to include ERCOT)
and the other ITO (ITO-West) over the Western interconnected transmission system.
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Figure 4-3 Federal Agency Architecture Power System Sector
84


Both ITO-East and ITO-West would be federal government entities operating under
the authority of the newly established National Power Administration (NPA) under
DOE. This approach centralizes oversight functions, hence improving coordination
issues to ensure a reliable bulk power system. This architecture is a continuation of
the philosophy used for the creation of the Department of Homeland Security (DHS)
and its role in consolidation of vital infrastructure under one entity for coordination
and response improvement. FERCs jurisdictional authority would expand to include
all transmission (wholesale, unbundled and bundled) with input from states regarding
issues of local concern. This expansion or shift needs to occur to ensure the
viability of the transmission system.
To maximize national transmission system reliability and use of resources for
generation, ERCOT would be combined within the eastern interconnection. Studies
would need to be performed to ensure acceptable system performance, but the DOE
National Transmission Grid Study states a 30 percent reserve margin for generation
exists within ERCOT. This margin, combined with recent transmission additions,
would lead one to believe integration with the Eastern Interconnection would be
feasible. ERCOT might be better suited for inclusion within the Western
Interconnection, but studies would confirm this.
Inclusion of Canada and Mexico would most likely be made during this same time
period.
85