Impact of Utility Industry Restructuring
on Power System Planning and Operation
Prepared for:
Tokyo Electric Power Company
1901 L Street NW, Suite 720
Washington, D.C. 20036
Prepared by:
Dariush Shirmohammadi
perotsystems
Farrokh Rahimi
KEMA Cfiisiiltiny
KEMA-ECC Ji Macro C<<r|rratrn
April 4, 1997
KEMA Consulting
Impact of Utility Industry Restructuring
on Power System Planning and Operations
1. EXECUTIVE SUMMARY
The electric utility industry is undergoing a fundamental restructuring that is
expected to deregulate key elements of the business and subject them to new
competitive threats and opportunities. The exact nature of that deregulation is
as of yet unclear. Many different structures for the future of the industry are
possible. Also, different structures may emerge at different points in time. As
an example, emerging structures suitable for competition in the wholesale market
may give way to structures suitable for competitive retail markets at a later
date. We may also see different structures in different regions. Regardless of
the market structures that may emerge in various parts of the world, one fact
seems to hold true: transmission and generation services will be unbundled from
one another. The generation market will become fully competitive with many
market participants who will be able to sell their energy (or demand side
management) services. On the other hand, the operation of transmission
system is expected to remain a regulated monopoly whose function will be to
allow "open, non-discriminatory and comparable" access to all supplies and loads
of electrical energy.
In this report we presents the dominant trends in the utility industry
restructuring and then discusses the impact of restructuring on planning and
operations of the utility system.
The report first provides a survey of prominent restructuring activities
worldwide along with specific examples of emerging electrical energy markets. It
is shown that despite variations in the structure of energy markets that have
emerged in different parts of the world, the transformation process has gone
through practically the same stages. Hence, it is possible to capitalize on the
experience of the previous restructuring processes to better manage or gain from
a market during its transition or its "final" form.
It is also shown the secure and efficient operation of the transmission system
is the key to the efficiency of the emerging electrical energy markets,
regardless of their structures. In this context, we focus on the functionality
of the Independent System Operator (ISO) as the operator of the open access
transmission system.
The report then discusses all the important aspects of power system planning and
operation in the emerging energy markets. For this purpose, we will draw
contrasts between planning and operations practices in traditional and emerging
market structures. The report identifies the profound changes that are likely to
take place in paradigms, procedures, methods, and accountability of planning and
operations in the emerging markets based on these contrasts.
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Finally, we will cover new business functions that the utility industry needs to
adopt in response to changes in the market where it functions.
Although broad and international in its scope, the report mainly focuses on
utility industry restructuring within the U.S. with special attention to
restructuring plans and activities in California as a forerunner of the US
utility restructuring process.
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KEMA Consulting
1. EXECUTIVE SUMMARY ______________________________________________________ 2
2. OVERVIEW OF UTILITY RESTRUCTURING TRENDS ________________________________ 8
2.1 STAGES OF RESTRUCTURING............................................. 10
2.1.1 Stage 1: Transition Market................................... 10
2.1.2 Stage 2: Massive Restructuring............................... 12
2.1.3 Stage 3: System Divestiture ................................. 12
2.1.4 Stage 4: Market Gaming .................................... 13
2.1.5 Stage 5: Reregulation........................................ 15
2.1.6 Stage 6: Industry Consolidation and Reintegration............ 15
2.2 ANCILLARY SERVICES.................................................. 16
2.3 TRANSMISSION PRICING................................................ 17
2.4 PLANNING IN THE RESTRUCTURES UTILITY INDUSTRY....................... 18
2.5 OPERATING PROCEDURES AND TOOLS...................................... 18
3. RESTRUCTURING MODELS ____________________________________________________ 21
3.1 ISO RESPONSIBILITIES............................................... 31
3.1.1 Operations Planning/Scheduling................................ 31
3.1.2 Dispatching................................................... 35
3.1.3 Control and Monitoring........................................ 36
3.1.4 Network Security.............................................. 36
3.1.5 Power and Energy Market Administration ...................... 37
3.1.6 Ownership/Planning of Transmission Assets.................... 37
3.1.7 System Restoration........................................... 37
3.2 CLASSIFICATIONS OF THE INDEPENDENT SYSTEM OPERATORS................. 38
3.3 ELECTRIC UTILITY INDUSTRY RESTRUCTURING IN CALIFORNIA............... 40
3.3.1 Market Participants........................................... 40
3.3.1.1 Energy Supplier (ES).................................... 40
3.3.1.2 California Power Exchange (PX).......................... 41
3.3.1.3 Scheduling Coordinator (SC)............................. 41
3.3.1.4 California Independent System Operator (ISO)............ 42
3.3.1.5 Transmission Owner (TO)................................. 42
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3.3.1.6 Utility Distribution Company (UDC).................... 42
3.3.1.7 Retailers............................................. 43
3.3.1.8 Energy Customer (EC).................................. 43
3.3.1.9 Ancillary Services Provider (ASP)..................... 43
3.3.2 Interaction Among Market Participants....................... 44
4. IMPACT ON POWER SYSTEM PLANNING.......................................... 48
4.1 PLANNING IN THE EMERGING ENERGY MARKETS............................. 48
4.2. GENERATION PLANNING IN THE EMERGING ENERGY MARKETS.................. 50
4.3 TRANSMISSION PLANNING IN THE EMERGING ENERGY MARKETS................ 52
4.4 DISTRIBUTION PLANNING IN THE EMERGING ENERGY MARKETS................ 56
4.5 POWER SYSTEM PLANNING IN CALIFORNIA'S EMERGING ENERGY MARKET........ 58
4.5.1 Generation Planning in California's Emerging Energy Market.... 58
4.5.2 Transmission Planning in California's Emerging Energy Market.. 59
4.5.2.1 Step 1: Determination of Transmission Expansion Needs... 59
4.5.2.2 Step 2: Transmission Planning and Coordination.......... 60
4.5.2.3 Step 3: Studies to Determine Facilities to be
Constructed..................................... 60
4.5.2.4 Step 4: Operational Review of the Transmission
Expansion Projects.............................. 60
4.5.2.5 Step 5: State and Local Approval and Property Rights.... 60
4.5.2.6 Step 6: WSCC and RTG Coordination....................... 61
4.5.2.7 Step 7: Cost Responsibility for Transmission
Expansions or Upgrades.......................... 61
4.5.2.8 Step 8: Ownership of and Access to Expansion
Facilities...................................... 61
5. IMPACT ON POWER SYSTEM OPERATIONS........................................ 62
5.1 ELEMENTS OF POWER SYSTEM OPERATION................................... 62
5.2 REAL-TIME SYSTEM OPERATION IN THE EMERGING ENERGY MARKETS............ 62
5.3 OPERATIONS PLANNING IN THE EMERGING ENERGY MARKETS .................. 66
5.4 MAINTENANCE SCHEDULING............................................... 71
5.5 FINANCIAL SETTLEMENT................................................. 71
5.6 POWER SYSTEM OPERATIONS IN CALIFORNIA'S EMERGING ENERGY MARKET....... 72
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5.6.1 Operation Scheduling by the PX............................... 72
5.6.1.1 PX's Day-Ahead Bidding and Scheduling Procedures....... 72
5.6.1.2 PX's Hour-Ahead Bidding and Scheduling Procedures...... 74
5.6.2 Operation Scheduling by the ISO.............................. 75
5.6.2.1 Receipt and Validation of Preferred Schedules.......... 75
5.6.2.2 Evolution of the Revised Schedules .................... 75
5.6.2.3 Development of the Final Schedule...................... 75
5.6.3 Maintenance Scheduling....................................... 76
5.6.4 Maintenance OutagePlanning................................... 76
5.6.4.1 Maintenance Outage Requests by the ISO................. 76
5.6.4.2 Maintenance Outage Requests by Market Participants..... 76
5.6.4.3 Final Approval......................................... 77
6. NEW BUSINESS FUNCTIONS................................................... 78
6.1 AVAILABLE TRANSMISSION CAPACITY...................................... 78
6.1.1 Definitions.................................................. 78
6.1.2 ATC Calculations Currently used in Different NERC Regions.... 80
6.1.3 Flogate initiative by NERC................................... 85
6.1.3.1 "Key Elements of the Flow-Based Transmission Service
Reservation Methodology................................ 85
6.1.3.2 Power Transfer Distribution Factors.................... 85
6.1.3.3 The Flowgate Concept................................... 86
6.1.3.4 Transfer Capabilities Based on Flowgates............... 86
6.1.3.5 Transmission Service Reservations Based on Flowgates... 86
6.2 BIDDING FUNCTION................................................... 87
6.2.1 Bid Submittal................................................ 87
6.2.2 Bid Collection and Revision.................................. 90
6.2.2.1 Bidding by Computer Link............................... 90
6.2.2.2 Bidding by Bulletin Board.............................. 91
6.2.2.3 Bidding by Fax......................................... 91
6.2.3 Bid Validation............................................... 92
6.2.4 Private Participant Data..................................... 92
6.3 PUBLIC INFORMATION SYSTEM.......................................... 92
6.3.1 OASIS........................................................ 92
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6.3.2 Requirements for the Power Market Publishing Function........ 95
6.3.2.1 Web Server............................................ 95
6.3.2.2 Web Agent............................................. 95
6.3.2.3 Navigation............................................ 95
6.3.2.4 File Transfer......................................... 98
6.3.2.5 Web Server Maintenance................................ 98
6.4 ENERGY METERING.................................................... 98
6.5 SETTLEMENT AND BILLING............................................. 99
6.5.1 Settlement Calculations...................................... 100
6.5.2 Security, Control, and Audit Trail........................... 101
6.5.3 Billing and Credit Function.................................. 101
6.5.4 Credit and Collections....................................... 102
6.6 CALIFORNIA'S EXPERIENCE............................................ 102
7. RESUME OF THE AUTHORS 104
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2. OVERVIEW OF UTILITY RESTRUCTURING TRENDS
Electric power utilities are undergoing significant restructuring in many
countries. The trend started in the 1980's in the UK and some Latin American
countries, and has gained momentum in the 1990's. The motivations and driving
forces for restructuring of the electric power sector in different countries are
not necessarily the same. In some countries, such as the UK and the Latin
American countries, privatization of the electric energy sector has been the key
driver and has provided a means of attracting funds from the private sector to
relieve the burden of heavy government subsidies. In the countries formerly
under centralized control (Central and Eastern Europe), the process follows the
general trend away from centralized government control and towards increased
privatization and decentralization: It also provides a vehicle to attract
foreign capital needed in these countries.
In the U.S. and several other countries where the energy sector has for the most
part been owned by the private sector, the key drivers have been customer
choice, increased competition and reduced regulation. In all cases, proponents
argue that deregulation and competition result in lower energy prices for the
end consumer, and lead to more efficient and environmentally sound utilization
of resources.
A variety of restructuring models are being proposed, considered, and
experimented within different parts of the world. Each structural model has its
main components (participants) such as bulk power generators, independent power
producers (IPPs), transmission owners, distribution companies, dispatching
entities, consumer groups, energy brokers, regulators, etc. Depending on the
business drivers and the governing regulatory framework, some of these
components may remain bundled or even become further consolidated. For example
there are strong sentiments among some utilities that all wires, whether
transmission or distribution, perform the same function and as such need to be
consolidated under, the same function. Another more prevalent example is the
functional consolidation (pooling) of transmission assets of separate and
neighboring utilities to form regional transmission groups (RTGs). This is
schematically shown in Exhibit 2-1.
However, the main trend has been towards desegregation (unbundling) of
traditional utility services. The unbundling of generation, from transmission
and distribution as separate business entities (vertical unbundling) prevails
among majority of the models. In practically all these models, energy supplies
(generation) is left to the competitive market to develop. Transmission is
almost universally regarded as a natural monopoly that shall remain regulated
and open to all market participants in order to permit a competitive environment
for energy supplies. Distribution wire service is also regarded as a regulated
monopoly. However, customer service part of energy distribution business is
another area where competitive forces could replace the traditional utility
operators.
In some restructuring scenarios, vertical unbundling involves only a functional
separation. This is the prescription of the US's Federal Energy Regulatory
Commission (FERC) under Order 888, issued on April 24, 1996. Order 888 mandates
functional unbundling of power marketing (generation) and transmission services,
but does not require institutional breakdown of the utility companies.
Transmission Open Access (TOA) is mandated in order to permit competition for
wholesale generation. In other restructuring scenarios, namely the UK, vertical
unbundling has taken place at an institutional level resulting in the complete
divestiture of transmission assets.
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peroteystems"
KEMA CMSUltlny
KEMA-ECC 1. Macr* Disintegration
Exhibit 2 -1
INDUSTRY RESTRUCTURING
TREND
- - Vertical Dis-integration (Unbundling)
- - Horizontal Consolidation
[GRAPHIC OMITTED]
Finally, it is necessary to note that although vertical unbundling of
traditional utility services and structures is the main trend in the industry
these days, it is expected that utility services will be vertically rebundled
again, however, in a different mechanism via acquisitions and takeovers. Recent
take over of Regional Electricity Companies in UK and Light Distribution Company
in Brazil, are examples of such new wave of vertical rebundling.
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2.1 STAGES OF RESTRUCTURING
Observation of restructuring process in many industries including that of
electric power utility industry in UK, South America and other parts of the
world has generally shown that deregulation of these industries has gone through
six (6) identifiable stages. Of course these stages are not completely distinct
and in many cases they overlap. Often a stage starts even before the previous
stage ends. However, evidence maintains that the system will pass through all
the stages without exception and reach the final stage and that the transition
can take place a lot faster than planned. The six stages of deregulation may be
broadly termed as follows:
Stage 1 - Transition Market
Stage 2 - Massive Restructuring
Stage 3 - System Divestiture
Stage 4 - Market Gaming
Stage 5 - Re-regulation
Stage 6 - Industry Consolidation and Reintegration
2.1.1 Stage 1: Transition Market
This stage represents those dynamics that move the market from regulatory
pressures and responses to competitive market forces and responses. This stage
is just the turning point in a continuous evolution that now lets the market
forces dictate electricity supply and regulatory responses. For example, FERC
Orders 888 and 889 are simply two elements of this stage and not the entire
impetus of restructuring in the U.S. The emphasis of these two FERC orders on
transmission access reflects that fact that transmission provides the last
vestiges of monopoly control. In line with the desire to further "liberate" the
access to the transmission system, an entity named the Independent System
Operator (ISO) is promoted in FERC Order 888. In the meantime, traditional
utilities may initially agree will formation of ISOs as a means of avoiding
institutional unbundling of transmission and generation. Transmission dependent
utilities, on the other hand, see the need for the ISO to avoid the inevitable
market distortion caused by transmission facility owners.
The creation of an ISO becomes an almost legal requirement under the
deregulation. The abundance of operations problems, conflicts among parties,
potential conflict-of-interest transactions, and conflicting legal requirements
find generic solutions only within the confines of a unbiased third party such
as an ISO. The ISO, by its mandate, seeks to most efficiently use the resources
available given costs/prices. The ISO attempts to maintain system functionality,
yet minimizes system costs. This does not, however, mean a minimization of
moment to moment system prices.
The transition stage corresponds to a phase where utilities would give up
control due mainly to outside forces while attempting to remain in control of
the consequences. In the U.S., the compromises
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reflected in all pieces of legislation and regulation (from PURPA, to the Energy
Act of 1992 to the Open Access Orders) are meant to control flow of
deregulation. In this transition period, system operation is dominated by a
"pool" entity that operates a wholesale energy market based on "market clearing
prices". Inevitably, many bilateral direct access transactions will also take
place between market players.
The main characteristic of the transitional market stage is the loss of control
by electric utilities. The ISO (or its equivalent) starts to create solutions to
the new regulatory and operational measures that would make existing utilities
less and less relevant. Hence, utilities will find it less and less advantageous
to hold on to their transmission assets as a means of remaining in control of
events. Given, the limited opportunities to earn from transmission assets, many
utilities may want to divest of the transmission system and most commissions
will probably agree. One possibility is that federal power marketing agencies
like BPA and TVA would eventually take ownership and control of the transmission
system nationwide.
The formation of the ISO is the start of the next set of more dramatic changes.
In fact, FERC Order 889 on Open Access Same-time Information System (OASIS)
offers divestiture as a potential future requirement for the utility industry in
the U.S. Furthermore, PERC's Capacity Reservation Open- Access Transmission
Tariffs Docket (FERC 1996b) is indicating that the approach for transmission
access and pricing in the Open Access Ruling may already need changing.
The absence of a transmission monopoly in the Open Access Ruling means that
ancillary services (see Section 2.2) become important issues. UK experience
indicates that ancillary services are too important to be considered as a side
issue. For example, for some years, some generators in the UK made 20% of their
revenue for just being available and have been making most of their profit by
simply making plants available (in the extreme, not running), than by
generating.
During this stage, although the pool will be in operation, other market dynamics
continue to change the scene as this transition market is not an equilibrium
state. One of the new phenomena that is expected to occur will be the "massive"
introduction of low cost combined cycle generation technologies. For example, in
Norway, massive new generation has been added to a system fraught with excess
generation. The same phenomenon has also happened in the UK where nearly 11GW of
new combined cycle generation has been added to the system since deregulation
took place in 1989. And all this would happen despite a strong anti-risk and
pro-regulatory bias that dominates the utility industry. Finally, accelerated
deregulation makes generation more of a commodity item, capacity expansion
decisions are now based on economic not regulatory need. At the same time, free
market makes regulated demand-side management counterproductive if not
dangerous.
Excess generation capacity will inevitably result in creation of strong forward
markets as generators attempt to maximize their utilization. A forward market is
a hedge, an insurance for both buyers and sellers of electricity.
There is an expectation that as the market move towards greater competition,
prices will fall. A historical analysis of independent power production in the
U.S., however, indicates that limited deregulation through the introduction of
IPPs did not produce lower prices commensurate with theories of marginal cost
pricing. Neither did lower prices come about in places where pools and market
clearing prices were introduced. In the UK, the market clearing prices
essentially never occur mainly due to gaming by market participants (see Section
2.1.5).
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2.1.2 Stage 2: Massive Restructuring
Once any portion of the market place experiences the choices that competitive
economics offer, all other portions of the market place demand the same
treatment. For example, in the U.S. retail wheeling is expected to follow
wholesale wheeling mandated by FERC (e.g., California's restructuring proposal).
Another of these dynamics produces extreme economic pressures to institutionally
break apart the vertical integration of the utility despite strong actions by
many utilities to resist these changes and to maintain control and protect what
they have. However, defensive posturing could prove fatal as portions of the
market will be lost to competition and the utility will have to support all its
costs with fewer resources with is remaining market. Prices rise and yet more of
the service area becomes susceptible to predators; hence, the "death spiral".
New competitive markets do not simply happen by freeing up access to resources
such as transmission and defining basic contractual procedures which are the
main elements of all partial deregulation exercises. It is logical to believe
that open wholesale competition, despite its many virtues, will be merely a
weigh station and testing ground for full retail competition. California's
restructuring plans that are being developed along side FERC actions on
wholesale competition, indicate how quickly full retail competition could take
place and in some instances, such as in California, even preempt wholesale
competition.
Furthermore, deregulation in one state has traditionally put pressure on its
neighbors to follow suit, often as the result of market forces than regulatory
initiatives. Major industrial end-users concerned about losing a competitive
edge through having to pay higher prices have swayed legislators through the
threat of lost jobs, economic growth, and tax revenues.
In the U.S., since the release of the FERC Open Access ruling, practically all
States have become actively involved in investigating restructuring at retail
level. While FERC notes that it has no authority to require divestiture, the
states are requiring such divestiture. Many economists argue that even if
regulators do not force such divestitures, market pressure will. In order to
cope with the threat of divestitures and the realistic threat that the market
will not allow stranded investment recovery, utilities have allocated as many
costs/assets as possible onto the transmission company (e.g., competitive
transition charges in California's restructuring plan). It is realistic to
believe that utilities will attempt to develop strategies for stranded cost
recovery that not only prevents losses for their shareholders but also can be
somewhat profitable.
During this stage, it is expected that utilities will use mergers and
acquisitions in order to strengthen their position in the market place and
better cope with market changes.
2.1.3 Stage 3: System Divestiture
The dawn of retail wheeling creates widening conflicts among generation,
marketing, transmission and distribution entities. Generation becomes risky with
potential for high gains. It will work on the premise of cash flow to cover
capacity financial burdens. It needs to overbook capacity to make sure that
capacity will be utilized as fully as possible, knowing that it may be forced to
go on the spot market itself to meet contract obligations. It needs to inform
the transmission system of its intent without showing its hand to its
competitors. It needs to build cash reserves to cope with price wars and gaming
mishaps. Because transmission is still regulated, it has an obligation to serve
with minimal
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chance to earn significant returns. If transmission expansion is required, the
assets and financial strength of the generation would be needed to secure
investment funds and support the project. The final results would be more
competitive pressures on the generator. This conflict of interest requires the
two to severe all financial and legal ties.
In addition, the distribution portion of the utility experiences regulatory
pressures mainly put in place through Performance Based Rates (PBR) to minimize
cost. If marketing is part of distribution, it must find low cost suppliers to
maximize its retail and wholesale market share. Further, the distribution
company may find the generation supply the transmission topology allows is more
expensive than that from a CCGT plant it could build nearby on its own.
The generators would have advantages marketing its own power without the
dependence on a utility marketing function serving its own interests, especially
when the generator must also sell power in other markets outside its service.
Marketing may want to set prices and play generators against one another to
cherry pick lucrative market segments. Separating retail marketing from the now
passive distribution function and providing generation its own independent
marketing arm maximizes everyone's advantage.
Finally, utility management in the U.S., being adept to cost cutting, is ill at
ease with the revenue volatility of generation and the bewildering issues of
network constraints. Therefore, the majority of U.S. executives, unlike their
counterparts in any other part of the world, would prefer to focus on the
distribution portion of the company where returns are guaranteed and cost
controls remain a known issue. Many companies have begun to break off the
generation portion of the business, but not with the required financial
resources, mandate, and autonomy. One could argue that the generation is moved
out to limit damage to the rest of the utility.
All these point to an outcome where various part of a vertically integrated
utility can not share the same goal. At that time divesting utility assets
starting with generation assets will become inevitable. Distribution appears the
safe haven and last refuge of the "conventional" utility business. And with
possibly contradictory regulatory requirements threatening profitability and
operation control, transmission seems best if owned by someone else.
2.1.4 Stage 4: Market Gaming
Divested companies will attempt to utilize their individual capabilities to
their best advantage and gaming the market is one of the strategies that they
will follow. Some of these games are based on the principle of surprise action
that usually works at least once. However, consistent gaming strategies will be
used on an ongoing basis until the market or its regulators act upon such
strategies.
At this stage, invalid perspectives of covering individual plant costs are
replaced by strategies that maximize the value of the entire company. These
could include bidding high cost plants at $0.00/kWh, as in the British and South
American systems, and still prove profitable under a market clearing price
payment regime. The number and type of strategies appear to have no limit. Some
obvious examples from other countries illustrate the variety:
- Putting a plant on-line below marginal costs to distort dispatch and
make later plants more valuable.
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- Placing big generation online early can degrade transmission so that
other generators can't get on the system.
- Sudden "outages" of capacity that can raise the spot market such that
remaining plants maximize revenue.
- Demand, transmission and generation can be double-booked to insure load
and hedging opportunities.
- Load following plants may now require much higher minimum load that just
happens to increase generation and profits.
Legitimate market gaming will take place at the unclear limits of operational
and legal rules. As a case in point, the initial deregulation of the UK
utilities associated fuel supply and distribution contracts with the generators.
This limited the amount of non-contracted capacity that could game the spot
market. It reduced the spot market power to negligible levels, though not the
generators ability to take advantage of transmission constraints and to game
capacity availability.
In another example of the early UK deregulation market, PowerGen, one of the two
conventional generators, learned to make plants unavailable for maintenance and
then make it suddenly available when its own unavailability had caused the
capacity charges to rise substantially. A regulatory investigation changed the
practice of declaring unavailability one day and then becoming available the
next day, after the previous days' declaration had caused the capacity charge to
rise precipitously. The new rules required a plant to be out seven days before
its absence affected capacity charges. Now a plant that goes off-line because of
failure may be better off to wait until its outage has driven up the capacity
charge before coming back online.
Third example of gaming in the UK market is based on generators gaming the
transmission constraints to increase profits (via increased uplift payments).
Large generators have established teams of expert modelers to devise profitable
market strategies in the best tradition of financial markets. Generators appear
to learn how to improve their ability to produce constraints even in shoulder
peak periods. Because of local transmission constraints, plants that would
minimize overall system generating costs may have to be "constrained-off" and
plants on the other side of the constraint "constrained-on." The constrained-off
plant obtains the revenue equal to the difference between the System Marginal
Price and the bid price. Thus, if the plant expects to be constrained-off, it
will bid in a low price. Conversely, a plant constrained-on receives its bid
price. If a generator expects to be constrained-on, it naturally bids higher
than it would otherwise. During a eonstrained-on situation, a local plant has
monopolistic power.
Examples of gaming can already be found in the U.S. and has been happening
mainly around reservation of transmission capacity without using it. An entity
which can reserve transmission capacity for sale of energy supply to a lucrative
market, preempts the ability of other suppliers to sell into that market. The
entity may not even have the supply to sell, but can use its reservation right
to sell the energy that it would purchase from other suppliers that are
precluded from the demand market with a healthy profit. Another example of
gaming by U.S. entities occurs in non-U.S. markets. It has been verified that
U.S. utility operations in South America with on-site U.S. utility plant staff
unfamiliar with the UK experience, are using zero bid prices to force units
on-line and to move the dispatch order to higher final costs. In South America
generators are also making plants "unavailable"
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on weekends which not only saves money, but insures high prices if it is
"needed" to come on due to "capacity shortages" during the weekends.
Thus, in different regulatory climates, different societies, with different
technologies and different markets, the basic features noted here as inevitable,
appear.
2.1.5 Stage 5: Reregulation
In the market place rules change only when economic or social pressure demand.
The act of threatening a change in regulation can distort the market in the
direction opposite to the intent of the proposed regulation because it changes
expectations. For example, under the threat of new rules, market players may try
to gouge the market as fast and as much as possible before new regulation comes
in. Alternatively, the same market players may cooperate to keep prices or
profit below the "regulatory" action threshold. Competitors can implicitly
signal their commitment to this strategy by notably changing their contract and
bidding activities. Thus, piecemeal regulatory intervention distorts market
processes even more than monopolistic or oligopolistic tendencies might.
Although electric prices fell in the early part of the UK deregulation, they
fell at a rate lower than the decline in fuel costs. Regulatory review led to
price caps. These in turn forced collusion among generators to allow compliance
with the further distortion of pricing to maintain profit margins yet keep new
entrants out. Additionally, the price caps made the strategy of over-contracting
(Contract for Differences) more attractive because generators then recognized
the now limited exposure to spot market prices should they not have enough of
their own generation to serve the executed contracts.
The gaming of stage 4 quickly separates the weak from the strong. The weak
demand fairness (to them) through regulatory and legislative changes. The
inevitable regulatory response forces the strong to act collusively, which
further excludes the weak from market participation. Hence, reregulation will
look different and will have different impacts than the initial regulation.
2.1.6 Stage 6: Industry Consolidation and Reintegration
The forces that even partial deregulation unleashes spread quickly. Even the
Canadian industries are now demanding rapid Canadian utility deregulation and
TransAlta is eyeing U.S. markets. The UK IPP success with gas and electricity
arbitrage are coming to the U.S. in terms of the Houston Light and Power and
Texas Utilities mergers. Utilities become outward looking. The U.S. Southern
Company Service acquired SWEB (a UK distributions company).
In the UK, as the price controls became apparent, the generators quickly made
bids to acquire the distribution companies. This attempt by generators was
rejected by the Regulator. In the long term little can be argued against this
since the deregulated market allows RECs to invest in generation. The economies
of scale remain in the system, and reintegration along economically efficient
lines rather than matching geography of generation and service area, would seem
both rational and inevitable.
Once the market recognizes the increase in certainty, participants would attempt
to lock-in advantageous situations. Many generators would find themselves
selling regularly to selected distribution companies, marketers, or customers.
The economies from reducing uncertainty further or locking in sales force
reintegration. The combined companies then have economies of scope. Because
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the impetus for re-regulation implies that many participants have reached the
"end" of their gaming days, sweep-up acquisitions surge. A handful of national
vertically integrated utilities form, owned possibly by foreign or non-utility
entities. Many small market niche utilities continue in remote areas or in
unique economic conditions.
Many economists claim that a small number of market players may represent the
most efficient market, where economics of scale dominate but sufficient
competition exists to defer monopolistic or oligopolistic pricing. This is the
fact in almost every other market where the 5 or 6 industry leaders can be
quickly identified. Some economist claim that the transition from regulation to
deregulation includes complete divestiture followed by reintegration as the
market pressures evolve throughout the deregulation transition.
2.2 ANCILLARY SERVICES
Ancillary services (A/S) include real or reactive power/energy resources needed
for secure and reliable operation of the transmission system. They include
reactive and voltage support, real power/energy for system control/re-dispatch,
regulating reserve, spinning reserve, operating reserve, energy imbalance, loss
compensation, backup, etc.
Depending on the organizational structure adopted, ancillary services may be
provided in a bundled manner or as an unbundled menu. In some cases, such as the
UK, the transmission system operator procures these services and charges the
users of the transmission system at a bundled rate, through the so-called
"uplift". In the U.S., FERC Order 888 requires the ISO to offer some of the
ancillary services in an unbundled manner under a pro-forma cost based tariff,
giving the transmission users the choice to either self provide or request the
ISO to provide them. California's energy market structure calls for a market
response to the provision of the majority of ancillary services.
The services identified by FERC as ancillary services are:
- Scheduling, system control and dispatch
- Reactive supply and voltage control from generation sources
>> Regulation and frequency response
- Energy imbalance service
- Spinning reserve
- Supplemental (non-spinning) reserve
Four of these services, namely, operating, spinning, and regulating reserves and
energy imbalance, may be self-provided by the user of the transmission system
(generators, aggregators, load serving entities, etc.). In case the transmission
user does not self provide these services (directly or through third party
arrangements), the transmission service provider (TSP), e.g., the ISO, must
provide the service. The transmission service provider may procure the A/S
resources through a competitive auction and charge the users accordingly. Two
other ancillary services, namely reactive power/voltage support and system
eontrol/re-dispatch are procured and provided by the TSP, and the users must
purchase them from the TSP.
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Some other transmission support services, such as loss compensation or backup
support, may or may not be offered by the TSO. For example, in California's
restructuring plans, the transmission users (also known broadly as the
Scheduling Coordinators) are required to submit "balanced schedules", i.e.,
include transmission losses in their schedules based on transmission loss
factors published by the ISO. The transmission users may also be asked to
arrange for their own backup supply if they require continuity of supply in case
of emergencies.
In the U.S., the North American Reliability Council (NERC) uses the term
Interconnected Operations Services (IOS) to refer to transmission support
services, including the FERC mandated ancillary services. According to the NERC,
the IOS fall into four categories and consist of:
- 1. Generation/demand balance category
- Regulation
- Load following
- Operating reserves - spinning
- Operating reserves - supplemental
2. Transmission System Security category
- Reactive supply and voltage control from generators
- Network stability services from generators
3. Emergency Preparedness category
- Black start capability of generators
4. Commercial Services category
- Real power losses
- Energy imbalance
- Dynamic scheduling
- Backup Supply
2.3 TRANSMISSION PRICING
Pricing of transmission services is an important aspect of the restructured
utility environment. All competitive gains attained through opening the
transmission system physically for access by market participants, could be lost
if the transmission system is "improperly priced." At the same time improper
pricing of the transmission services could have serious adverse financial
ramifications for the owners of the transmission facilities and future
investment in transmission facilities.
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Various methods for pricing transmission services have been implemented, are
under scrutiny or under experimentation in different parts of the world. Three
main classes of pricing may be distinguished, namely embedded costs based
pricing, short-run marginal cost (SRMC) based pricing, and long-run marginal
cost (LRMC) based pricing. Prom the transmission owner's point of view the
embedded cost method is suitable when one is mainly interested in recovery of
past investments in the transmission system. The SRMC method is suitable mainly
for non-firm short-term contracts, where the transmission owner is interested to
charge the third party for the use of available transmission capacity. The LRMC
pricing is relevant when longer term contracts are involved, and cost of
transmission capacity additions must be accounted for.
From the regulator's point of view, price signals must aim at a balance between
equitable cost recovery by the transmission owner, and efficient use of
resources by the transmission user. In this respect, the embedded cost methods
do not provide proper economic signals, and the SRMC methods in their basic form
do not guarantee recovery of transmission costs for firm contracts. Exhibit 2-2
summarizes the main cost components used in each category of transmission
pricing methods, along with the main advantages and disadvantages.
2.4 PLANNING IN THE RESTRUCTURES UTILITY INDUSTRY
The market participants, paradigms, procedures, tools and oversight related to
planning of various components of the electric power system, namely generation,
transmission and distribution will be going through fundamental changes in the
emerging energy markets. As we discussed in Section 2.1, it is well understood
by the industry that generation planning will be performed by market
participants other than the current vertically integrated utility companies and
with completely different set of paradigms, procedures and tools. Transmission
planning is expected to be addressed using somewhat different procedures and
tools; although the paradigm for transmission planning is expected to remain by
and large the same. Finally, distribution wire planning is expected to go
through few changes in the emerging electrical energy markets; however, the
retail/customer services aspect of energy distribution business is expected to
experience a thorough change in all its aspects. We will address the planning
issues in Section 4 of this report.
2.5 OPERATING PROCEDURES AND TOOLS
Transmission open access (TOA) has implications on operating procedures and
tools required to ensure secure operation of the transmission system. The latter
include collection, exchange, and processing of real-time and scheduling data
for operations planning, real-time operation, as well as after-the-fact
settlements, accounting and billing. These functions are traditionally performed
in the control centers using the SCADA and EMS facilities. The traditional
SCADA/EMS algorithms and software may have to be modified or amended to varying
degrees to serve the needs of the dispatchers, schedulers, control room
supervisors, engineers, and other control room staff effectively. In addition,
new hardware/software and communication systems may be required to support the
competitive market activities (bidding, publishing, dispute resolution and
settlements/billing). We will cover all these issues in the following sections
of the report.
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KEMA-ECC & MACRO CORPORATION
- --------------------------------------------------------------------------------
EXHIBIT 2-2:
COMPARATIVE ANALYSIS OF TRANSMISSION PRICING METHODOLOGIES
<Table>
<Caption>
- ------------------------------------------------------------------------------------------------------------------------------------
METHOD COST COMPONENTS OVERALL CHARACTERISTICS ADVANTAGES DISADVANTAGES
- ------------------------------------------------------------------------------------------------------------------------------------
EMBEDDED COST (1) BASIC COST ELEMENTS Different variations: o Simplicity of computation (1) Short-Term Contracts:
o Recorded Book Costs (for o Rolled-in or Postage o Relatively low data o Incorrect pricing signals:
past or estimated costs Stamp ($/MW) requirements - Price decreases as
(for future): o Contract path ($/MW o Flexibility to introduce system is loaded to its
- Return on investment or $/MW-Km) more detail based on limits
(interest/equity) additional data availability - Price increases when
- Book depreciation o Boundary flow ($/MW) wheeling customers are
- Property tax o Actual Flow-Km scarce
- Income tax ($/MW-Km) (2) Long-term Contracts:
- Insurance o Potential for inefficient
o Operating & Maintenance siting of new facilities
Costs o Returns may be insufficient
(2) ADDITIONAL COST to encourage construction
ELEMENTS of new transmission
o Average cost of generation capacity for wheeling
to replace transmission o Captive and transit
losses customers are treated
o Average cost of generating equally
reactive power
o Average cost of spinning
reserve
o Average cost of regulating
reserve
- ------------------------------------------------------------------------------------------------------------------------------------
SHORT-RUN (1) BASIC COST ELEMENTS o Possible variations o Efficient economic signal o Relatively heavy
MARGINAL o Incremental cost of on extent of data - SRMC is low when capacity computational
COST (SRMC) incremental losses availability is available requirements(1)
o Incremental cost of o Requires power flow - SRMC is high when o Relatively large data
reactive generation and possibly OPF capacity is scarce requirement(1)
o Incremental cost of o May require Unit o Can provide pricing o Potential for controversy
spinning reserve Commitment advantage in a competitive regarding:
o Incremental cost of o Applicable to short- market - network structure and
regulating reserve term or spot data
o Incremental costs due transactions - opportunity costs(2)
to altering unit - congestion costs(3)
commitment and/or o No guarantee of cost
generation dispatch recovery for existing
(2) ADDITIONAL COST ELEMENTS facilities if applied
o Incremental administrative indiscriminately (may
and support service require supplementary
costs(4) adders)
o Incremental physical
depreciation costs due
to shortened life of
equipment resulting from
wheeling
o Opportunity costs(2)
o Congestion cost
- ------------------------------------------------------------------------------------------------------------------------------------
LONG-RANGE (1) BASIC COST ELEMENTS o Applicable primarily o Efficient economic signals o Relatively heave
MARGINAL COST o Carrying charges on to long-term for long-term transactions computation requirements(1)
(LRMC) estimated costs of transactions o Motivates good investment o Relatively large data
system expansion (future): o Combination of planning decisions requirements(1)
- Return on investment and operations o Captive customers do not o Can distort optimum
(interest/equity) environment subsidize transit clients near-term use of the
- Depreciation o Possible variations network
- Property and income tax based on predominance - Prices may be too high
o Incremental fuel costs of planning or even if capacity is
for: operational considerations: available in short-term
- incremental losses - Planning: refinement of - Prices may be too low
- incremental reactive embedded costs method even if short-term
power - Operations: extension of capacity is scarce
- incremental spinning SRMC method to
reserve incorporate investments
- incremental regulating
reserve
- incremental changes in
economic dispatch
(2) ADDITIONAL COST ELEMENT
o Incremental administrative
and support service costs(4)
- ------------------------------------------------------------------------------------------------------------------------------------
</Table>
SEE NEXT PAGE FOR FOOTNOTES
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- --------------------------------------------------------------------------------
NOTES TO TABLE (SEE PREVIOUS PAGE):
1. The computational and data requirements of SRMC and LRMC methods increase
with increase in the degree of detail, size of network, etc. Short-cuts and
simplifications (e.g., aggregation of data) reduce the computational burden,
but introduce errors. Ultimately, the simplifications in each case can lead
to the Embedded Cost Method in one form or another. A compromise must be
worked out for each system and business environment by simulation studies.
2. Opportunity costs increase with firm contracts, and diminish for
interruptible contracts
3. Congestion costs represent a round-about way of incorporating the impact of
capacity expansion needs.
4. Administrative and support costs include costs of administration,
scheduling, control room, engineering studies, etc.
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3. RESTRUCTURING MODELS
This section provides an overview of the main restructuring models emerging in
the U.S. and a few other countries. A common premise of all of the restructuring
models already implemented or under development is that the operator of the
transmission system must not have any financial interest in the sources of
generation or preferences in treatment of end use customers. Hence, the term
Independent System Operator (ISO) is becoming a common term for referring to the
operator of the transmission system. In some cases, independence of the ISO is
carried one step further, wherein, the ISO has no financial interest in
transmission assets either, and acts as a non-for-profit organization simply
responsible for the operation of the transmission system with the twin goals of
maintaining the reliability and efficiency of its operation. California's
restructuring plans calls for such an independent system operator.
As part of its responsibility for secure and reliable operation of the power
system, the ISO may provide the ancillary services from its own assets, or
procure some or all ancillary services through long-term leasing contracts, or
competitive auction.
The ISO may or may not have the responsibility to facilitate a power and energy
market (sometimes called Power Exchange, and designated by PX). The
responsibilities and scope of activities of the different ISOs emerging in the
U.S. and other countries around the world, vary widely.
Due to its prominent role and importance, in the following we will cover the
scope of the responsibilities of the independent system operator in some detail.
Furthermore, the explanation of ISO structure and operation, as applicable to
different market structures, will help reveal the main features of these markets
including operations planning, system dispatch, control and monitoring, network
security, power market administration, ownership and planning of transmission
assets and system restoration.
Exhibits 3-1 through 3-9 highlight the main features of different restructuring
models adopted or being considered in the U.S. and other parts of the world.
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Exhibit 3-1
ISO Examples - ERCOT
- - ISO just operates the wires (reliability)
- - No ISO control on generation dispatch
- - ISO acts as a coordinator
- - ISO performs security analysis and coordinates control area
operations
- - Moving from two Security Centers (North and South) to one:
- Real-time monitoring
- Response to system contingencies
- Operations coordination
- Outage scheduling
- OASIS functions
- - Datalinks from Control Areas to existing and new Security
Centers
- - Control Areas responsible for their network reliability and
security
- - ISO coordinates regional transmission planning
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Exhibit 3-2
MidWest ISO
- - 18 Control areas
- - No Tower Market
- - TOs will retain physical operation and maintenance
- -- Load/gen balancing and ED by local operators
- - ISO will do regional planning for all transmission owners
- - Local utilities can plan, but must get ISO approval
- - If no TO wishes to build new transmission lines, ISO will
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Exhibit 3-3
IndeGO
ISO will lease transmission facilities (230 Kv and above) from TOs
- - Individual contracts between IndeGO and each TO
- - Local subtransmission and distribution services:
41. General Distribution Access Agreement between IndeGO and owner
-%, Direct arrangement between customer and owner
IndeGO not involved with physical operation of Subtrans. and Dist.
- - TO or trans. customer can commit to fund construction of new facilities in
exchange for Trans. Cap. Res. (TCR) rights
Hierarchical AGC
4- ISO will do congestion management
- - Fixed zone boundaries, subject to annual revision
- - ISO will buy A/S
%. Competitive procurement for Spinning and Regulation Reserve
- Long-term contracts for other A/S
>> ISO non-for-profit__________________________________
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Exhibit B4
NYPP
- - Pool-wide UC and dispatch since 1977; SCLJC contemplated
- - ED every 5 minutes
- - HexiblePOOLCO model; Bilateral Trans. and Central Dispatch
- - Iterative BO/FX scheduling (indudingUC/SCUQ
- - No transfer of ownership of transmission assets
- - TOs responsible for maintenance
- - ISO will plan transmission (230 Kv and above)
- - Local TOs and others hid to build (competitive bidding)
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Exhibit 3-5
PJM
4- Combined ISO/PX
- - No transfer of ownership of transmission assets
- - TOs responsible for maintenance
- - ISO will plan transmission (230 Kv and above)
- - Local TOs and others bid to build (competitive bidding)
- - Single PJM control area as in the past; hierarchical AGC
- - Dispatch based on price rather than system lambda
- - ISO does congestion management
- - ISO conducts system-wide SE and CA
- - Individual utilities conduct their own SE and CA
- - ISO coordinates the operation of local area transmission facilities as
required for reliable operation of PJM control area]
- - ISO is a non-for-profit organization
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Exhibit 3-6
WEPEX
- - Transfer of operational control (not ownership) of trans. facilities
- Wires
- Control Centers
- - Phased Implementation of SCADA/EMS
- - Separate PX and ISO
- - PX holds day-ahead and hour-ahead market for energy and its A/S share; sends
excess A/S to ISO
- - Iterative bidding process
- - ISO holds day-ahead and hour-ahead auction for A/S
- - ISO responsible for congestion management
- - Fixed congestion zone boundaries; subject to change annually
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Exhibit 3 - 7
NGC
- - Owns and operates trans. system
- - Combined ISO/PX functions
- - Schedules generation (including UC and DSM)
- - Dispatches generation, including DSM
- - Purchases and dispatches A/S
- - Operates Pool settlement system
- - Handles funds transfer for the Pool
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Exhibit 3 - 8
Victoria Power Exchange (VPX)
- - Combined ISO/PX functions
- - Procures and dispatches A/S
- - Does not own transmission assets (PowerNet Victoria does)
- - VPX leases trans. facilities from PNV
- - VPX procures network additions competitively from PNV or
others
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Exhibit 3 - 9
Power Pool of Alberta
- - PPA performs power pool administration
- - PPA performs generation scheduling and dispatch
- - PPA performs system control
- - Grid Company of Alberta (GCA) performs transmission
administration
- - GCA is a joint venture agreement between major TOs
- - GCA procures A/S
- - PPA dispatches A/S
- - PPA coordinates security monitoring and trans. congestion
management with GCA
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3.1 ISO RESPONSIBILITIES
To facilitate categorization of ISO structures, it is helpful to consider the
ISO's roles and responsibilities in each of the following areas:
- Operations Planning/Scheduling
- Dispatching
- Control and Monitoring
- On-line Network Security Analysis
- Power and Energy Market Administration
- Ownership/Planning of transmission Assets
- System Restoration
3.1.1 Operations Planning/Scheduling
The responsibilities of the ISO in this area could include scheduling of
generation, transmission, and interchange.
The ISO is fundamentally responsible for scheduling of transmission facilities.
To ensure fair treatment of the transmission users, the ISO must maintain an
"Open Access Same-time Information System" (OASIS) facility. The overall
requirements for OASIS are specified in the FERC Order 889, issued April 24,
1996. The ISO is also responsible for coordinating interchange schedules to
ensure they do not cause transmission system congestion.
Generation scheduling may or may not be included among ISO responsibilities. It
may be limited to scheduling of ancillary services. In case the energy market
structure does not include a power and energy market, ISO's role in generation
scheduling will be limited to ensuring that the submitted schedules do not cause
transmission congestion. This is the situation in ERCOT, IndeGO, and the Mid-
West ISO, and is schematically demonstrated in Exhibit 3-10.
The same situation applies if a power and energy market exists, but another
entity is responsible for its administration. The California ISO is an example,
where another independent entity (namely, California Power Exchange) is handling
the power and energy market administration. This is schematically illustrated in
Exhibit 3-11 (a).
In cases where the ISO is also responsible for the power and energy market
administration, e.g., in UK, generation scheduling falls within ISO's area of
responsibility. This is the situation contemplated by PJM and partly by the New
York Power Pool (NYPP); although the actual scheduling in the NYPP will be done
by the Power Exchange branch of the organization. These conditions are
schematically illustrated in Exhibit 3-11 (b), and Exhibit 3-12.
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Exhibit 3 -10
ISO WITH NO POWER EXCHANGE
[GRAPHIC OMITTED]
SC = Scheduling Coordinator:
CInternal Control Areas (performing UC)
CBilateral Contracts
CWheeling Requests
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Exhibit 3 -11
POWER EXCHANGE SEPARATE FROM ISO
[GRAPHIC OMITTED]
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Exhibit 3 -12
COMBINED ISO & POWER EXCHANGE
[GRAPHIC OMITTED]
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The main difference between NYPP and California markets (WEPEX) in this respect
is that in the case of NYPP the entity responsible for scheduling of generation
resources will deal simultaneously with bilateral contracts and supply/demand
bids into the Power and Energy Market. In this sense the generation scheduling
problem for NYPP and PJM are similar, although it is carried out by two
different entities (ISO in the case of PJM and Power Exchange in the case of
NYPP). It is worthwhile noting that the separation of ISO and Power Exchange in
the case of NYPP is based on governance and membership considerations. As far as
exchange of scheduling information is concerned the security firewall that
exists between the California ISO and PX is not present in the case of NYPP.
In cases where generation scheduling is included among ISO's responsibilities,
the ISO may or may not be responsible for Unit Commitment. If bidding protocols
for generation resources allow for multi-part bids, (i:e., not only the price
per MWh, but also start-up prices and no-load prices), and if there are no
provisions for continuous bidding, the ISO scheduling process must take into
account Unit Commitment type data including start-up price, no-load price,
minimum up and down times, ramp rates, etc. In fact, in such case often the use
of a Security-Constrained Unit Commitment (SCUC) methodology is desired. This is
the situation for the NYPP power exchange and the PJM ISO.
However, in case power and energy market participants are allowed only
single-part bids (i.e., the price per MWh quoted is to include a portion of the
bidder's start up and no-load cost), then a simple merit order scheduling will
apply. (In this case the bidder is taking the risk based on its own estimate as
to how long the unit will be scheduled to operate.) Moreover, the scheduling
method will be of a static type (no correlation between successive time steps)
if there is provision for continuous bidding by the participants. This is the
situation in the California Power Exchange, where it is expected that through a
number of bidding and price determination iterations with market participants
before the closure of the day-ahead market, the bidders will adjust their hourly
bid prices so that the resulting schedule at market closing time is feasible
from a unit commitment point of view.
3.1.2 Dispatching
The scope of real-time dispatching of generation resources depends on whether or
not the ISO is responsible for administration of the power and energy market,
and whether a single-settlement or multiple-settlement system is in place. In a
single-settlement system involving mainly bi-lateral contracts, or where a pool
structure for only energy surplus is in place, the ISO may perform actual
generation dispatch.
In general, however, the ISO performs real-time dispatch only for energy
imbalances, ancillary services, and congestion management. This is particularly
true in a multiple settlement system. For example, NYPP is contemplating a
two-settlement system, in which day-ahead schedules are binding, and must be
settled as contractual commitments. The difference between the contractual
commitments and actual generation and consumption are settled after the fact
(ex-post settlement). In the case of WEPEX, a three-settlement system prevails,
namely, day-ahead, hour-ahead, and ex-post. In these situations, the real-time
dispatch will aim at alleviating the imbalance between actual and scheduled load
and generation. The ISO will select the "least-cost" resources to meet these
imbalances.
The ISO will also redispatch generation in case of transmission congestion.
Congestion management may involve changes in generation or load (through
demand-side management) based on incremental and decremental prices quoted by
the users of the transmission system. This is the case for WEPEX.
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Congestion management protocol may also involve curtailment of transactions,
based on established priorities. This is how MAPP handles congestion management
(Line Loading Relief procedure) at present, and contemplates to continue the
process in its emerging ISO.
The boundaries of the "congestion zones" may be fixed or adjusted dynamically as
a function of system conditions. For example, in the case of WEPEX, four
congestion zones are defined initially. New zones may be defined, and the
boundaries of the initial zones may change only if intra-zonal congestion
becomes a persistent problem over a length of time (on the order of a few months
to a year). In the case of the Nordic system (Scandinavian Countries), the
boundaries of the congestion zones change dynamically during a day as system
conditions change.
3.1.3 Control and Monitoring
The ISO may or may not have the authority and the means for supervisory control
and/or actual real- time control of generation.
The ISO's role in real-time control of generation may be limited to coordination
and monitoring of the operation of control areas under its jurisdiction. In that
case, each control area will perform its own automatic generation control (AGC).
For example, this is the situation contemplated in the Mid-West ISO. In the case
of WEPEX, the ISO is responsible for AGC. Initially, it will employ a
hierarchical AGC from a new control center, using the existing SCADA/AGC
facilities of the three California Investor-Owned Utilities (lOUs) as the second
level in the hierarchy. Shortly thereafter, it will have direct control of
generation facilities which it needs for regulation, congestion management, etc.
3.1.4 Network Security
The ISO will be responsible to ensure security of system operation against
occurrence of credible contingencies. The ISO may attempt to perform this task
by using estimated operating data and off-line power flow and contingency
analysis programs. But this is not adequate for most emerging ISOs. The ISO will
generally need to perform on-line contingency analysis.
To perform on-line contingency analysis, the ISO may collect real-time
information from the field (as in tine case of WEPEX), or collect snapshot data
from member SCADA systems periodically (as contemplated by MAPP). Alternatively,
the ISO may use states estimated by its transmission providers, if the latter
have working state estimator functions. Whether the ISO receives real-time or
estimated data, it is generally contemplated that the ISO will have its own
state estimator. ISO's state estimator would treat any state estimates from its
members as if they were telemetered data. This will allow the ISO to determine a
consistent base case for network security analysis.
For systems where dynamic security and/or voltage stability are potential
problems, the ISOs presently will have to rely on prior off-line studies, and
look up tables to determine operating limits. However, as the new players emerge
in the use of the transmission system, it is expected that the difficulty in
finding a close match between actual operating conditions and prior studies may
lead to the need for on-line Dynamic Security Analysis (DSA) and/or Voltage
Security Analysis (VSA) functions.
Congestion management by the ISO is expected to be fully dependent on the use of
Security Constrained Optimal Power Flow (SCOPF) models.
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3.1.5 Power and Energy Market Administration
As mentioned earlier, the ISO may or may not be responsible for administration
of the power and energy market. The relationship between the ISO and the
associated power and energy market (if this market clearly exists) may vary as
explained in Section 3.1.1. above, and schematically demonstrated in Exhibits
3-11 and 3-12.
The price determination mechanism used in the power and energy market will
depend on market rules. The bidding process may allow iterations with the market
participants before the market closing time without establishing any contractual
commitment. In that case, the latest bids received before market closing for
each market are considered valid. This is the process adopted in WEPEX. In some
other structures, the participants may submit and change bids before market
closing, but will know the market clearing price (and whether or not their bid
is accepted) only after market closure. This is the case in the majority of the
emerging Power and Energy Markets. In practically all cases where a market
clearing price is established, all generators in a congestion zone are paid the
same price (regardless of their bid price), usually with corrections for losses.
There are cases where the power and energy market acts as a bid matching
facility (matching buyers and sellers) without establishing a market clearing
price. The ISO will treat these as bilateral contracts.
Even where the ISO is not responsible to facilitate the power and energy market,
it usually does administer a market for ancillary services to procure the
ancillary services it needs.
ISO's involvement in the settlement process depends on the scope of its
responsibilities and degree of interaction with other entities (transmission
users, suppliers, schedule coordinators, etc.). The ISO usually settles with the
users of the transmission system for the costs it incurs to perform congestion
management, and for provision of ancillary services. Depending on the market
rules and number of markets (day-ahead, hour-ahead, etc.) multiple settlements
may be involved with the same participant for a given transaction for a given
period.
3.1.6 Ownership/Planning of Transmission Assets
As mentioned earlier, the ISO may or may not own transmission assets. In many
cases, it is a non-for- profit organization with no asset ownership. It is,
however, responsible for coordinated planning of the transmission facilities to
a different degrees. If the initial transmission owners and service providers or
other market participants do not plan for and invest to build the needed
transmission facilities, the ISO generally becomes involved, identifies these
facilities and arranges to have them built. Costs of such investments are
recovered from the transmission users based on approved protocols. In those
cases where several candidates would offer to build a particular facility, the
ISO would conduct an auction.
3.1.7 System Restoration
The ISO is responsible for coordination of system restoration in the event of
major outages or blackout conditions.
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3.2 CLASSIFICATIONS OF THE INDEPENDENT SYSTEM OPERATORS
Exhibit 3-13 summarizes the categories of ISO responsibilities listed in the
preceding section. Not all of the responsibilities listed are required for an
entity to be considered a legitimate ISO.
A brief survey of the existing and emerging ISOs reveals that as a minimum the
responsibilities of the ISOs emerging in the US would include coordination of
the operations planning of the transmission owning entities within the ISO's
area of jurisdiction. Such "minimalist ISO" does not perform generation
scheduling. It only intervenes in case schedules it receives from market
participants (control areas. Scheduling Coordinators, etc.), would result in
transmission system congestion. Its role in the operations scheduling time frame
is to inform the transmission system users about potential system congestion,
including the transmission paths in question.
The minimalist ISO does not perform real-time control of power system
facilities. It does, however, monitor the operation of the power system to
ensure adequacy of available reserves, and other pertinent ancillary services.
It will also coordinate measures to alleviate transmission system congestion. It
will perform contingency analysis to ensure system security against credible
contingencies.
Examples of minimalist ISOs in the U.S. include ERCOT, MAPP, Mid-West ISO and
IndeGO.
At the other end of the scale, some existing or emerging ISOs have a wide range
of responsibilities and authority. The so-called "maximalist ISO" would perform
generation scheduling (possibly including Unit Commitment), and scheduling of
ancillary services (possibly simultaneously with energy/power scheduling). It
would also perform scheduling and pricing of transmission facilities. It would
dispatch generation for imbalance and ancillary services, as well as congestion
management, possibly with varying congestion zone boundaries. It would perform
real-time control of generation, transmission, and ancillary resources. It would
perform state estimation and security analysis based on acquired real- time
data. It would facilitate a Power and Energy Market either directly, or in close
coordination with a Power Exchange (if separate). It would plan and execute
transmission system expansion (although it may or may not own the transmission
assets).
The emerging PJM and NYPP ISOs are examples of maximalist ISOs. NGC in the UK is
another example, where the ISO also assumes ownership of transmission assets.
Other ISOs may fall somewhere in between the minimalist and maximalist ISO
categories. WEPEX is an example where the ISO has all the responsibilities of
the maximalist ISO with some exceptions (no power/energy market administration
responsibilities).
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Exhibit 3 -13
ISO RESPONSIBILITIES
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3.3 ELECTRIC UTILITY INDUSTRY RESTRUCTURING IN CALIFIRNIA
California's planned utility industry structure is aimed at a total separation
of the market administration and system operation. Market administration for
power and energy will be provided by an independent body called the Power
Exchange and system operation by another completely independent entity called
the Independent System Operator. In the following we will provide a brief
description of the planned California energy market structure by identifying the
its market participants and their interactions.
3.3.1 Market Participants
The major participants in the California restructured electrical energy market
will be:
- Energy Suppliers (ES)
- Power exchange (PX)
- Scheduling Coordinator (SC)
- Independent System Operator (ISO)
- Transmission Owner (TO)
- Utility Distribution Company (UDC)
- Retailers
- Energy Customers (EC)
- Ancillary Services Provider (ASP)
3.3.1.1 Energy Supplier (ES)
The Energy Supplier will supply power and energy to the California market. Major
energy suppliers are expected to be the existing Investor Owned Utilities (lOUs)
in California including the Pacific Gas and Electric Company (PG&E), Southern
California Edison (SCE) and San Diego Gas and Electric Company (SDG&E), out of
state utilities such as Bonneville Power Administration (BPA) and Independent
Power Producers (IPPs) such as Mission Energy. Despite serious efforts by the
regulators through various incentive programs. Demand Side Management service
providers may not play a substantial role here.
In order to mitigate market power by anyone energy suppliers in California,
California lOUs have been strongly encouraged by the regulators in to divest out
of 50% of their fossil powered generation assets. PG&E and SCE are complying
with this "request" and are heavily divesting (beyond 50%) out of their existing
fossil powered generating assets,
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3.3.1.2 California Power Exchange (PX)
Also known as the Power Market Administrator or the Spot Market Operator in
other parts of the world, the Power Exchange is an independent entity that will
manage the spot energy market on daily and hourly basis. PX will provide a
forward competitive market for electrical energy, conduct day- ahead and
hour-ahead auctions for generation and demand and will ensure
non-discriminatory, transparent bidding interfaces and protocols. PX will match
generation and load for those market participants (bidders) that choose to
participate in its spot market and will set the market clearing price for energy
purchased and sold.
PX will submit the balanced load and generation schedules that it develops to
the Independent System Operator (see below) for its verification and acceptance
from system reliability point of view. PX will then notify bidders of accepted
schedules and provide settlement of the day-ahead and hour-ahead schedules and,
finally, bill PX customers and administer payments to PX suppliers.
The existing lOUs in California must sell all their generation through the PX
between the years of 1998 and 2002 and buy energy for their bundled retail
customers (see below for the definition of bundled retail customers) from PX for
the same time period.
3.3.1.3 Scheduling Coordinator (SC)
Scheduling Coordinators (SCs) are entities that will arrange for direct and
bilateral energy transfer between energy suppliers and customers outside the
spot energy market. Any customer in California, subject to proper protocols,
will be able to deal directly with an energy supplier for provision of its
energy needs (Direct Access Customer). Scheduling Coordinators provide the
interface, directly or through a retailer (see below), for direct access
customers to access energy supplies, based mainly on long-term contracts. The
Transmission Owners and Utility Distribution Companies (UDCs) (see below for
definitions) will provide "wire service" to direct access customers.
Scheduling Coordinators will comply with all provisions of the ISO operating
protocols and tariff. This includes compliance with technical requirements, for
example covering computer and communications systems, and the financial criteria
necessary to cover the risk of late payment or default of certain payments to
the ISO for settlement with other scheduling coordinators. In return all
scheduling coordinators, including the PX, will be treated comparably by the
ISO.
Scheduling Coordinators will perform the following mandatory functions: (1)
coordinating schedules between energy suppliers (supply aggregators), direct
access customers (retailers), other scheduling coordinators and traders; (2)
settling with the ISO for imbalance energy, ancillary services and congestion
charges; (3) providing preferred balanced schedules for deliveries into and out
of the ISO controlled grid; (4) acting as the designated representative of
generators; (5) responding to ISO changes in schedules to address
overgeneration; (6) providing settlement quality meter data; and (7) settling
with other parties on mutually agreed terms.
A prominent example of an SC in California is expected to be ENRON Corporation.
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3.3.1.4 California Independent System Operator (ISO)
The ISO in California is an independent entity that will operate the
transmission system to ensure the integrity and "efficiency" of system
operation. Specifically, the ISO will act as a super control area operator and
will control the power dispatch and the transmission system. The ISO will own no
transmission, generation, or distribution facilities and will have no financial
interest in the energy market. All transmission services, whether through the PX
or the SCs, or the existing contracts, will be provided and managed by the ISO
on a non-discriminatory basis.
The ISO will coordinate the day-ahead and hour-ahead scheduling and balancing
for all transmission grid users including the Power Exchange and the Scheduling
Coordinators. It will also coordinate and schedule the maintenance of
transmission system facilities. The ISO will procure the needed ancillary
services and will manage the financial settlement between the actual and
scheduled deliveries.
The ISO will meet all the North American Electricity Reliability Council (NERC)
and Western System Coordinating Council (WSCC) reliability standards and will
coordinate the "energy information exchange", e.g., the OASIS, in an open
market. The ISO will post non-confidential information such as status of
transmission facilities, projected transmission constrained paths and
transmission losses for all transmission users.
In addition to its responsibilities as the control area operator, the ISO will
have an active role in transmission planning, which will entail close
coordination with transmission owners, transmission project sponsors, regional
reliability organizations and other neighboring control areas.
3.3.1.5 Transmission Owner (TO)
Also known as the grid company. Transmission Owners in California will own and
operate the transmission "wires" (transmission facilities) in the State of
California. The existing California lOUs are expected to be the main TOs. TOs
will be responsible for maintenance of the transmission facilities in
coordination with the ISO. They will also be responsible for construction of new
transmission facilities in coordination with the ISO, the WSCC, Regional
Transmission Groups (e.g.. Western Regional Transmission Association - WRTA),
and other market participants.
TOs will have no role or interest in managing the energy market in California
except for provision of physical access to the transmission system. Their main
source of income will be collection of transmission access charges from the
users of the transmission grid. Transmission access charges will be charged to
energy customers (collected through PX and SCs) based on the energy extracted
from the transmission system. Transmission access charges will be determined on
an annual basis and are fixed for the entire year. Transmission access charges
will vary from one utility service territory to the next and are meant to cover
the TO's annual transmission revenue requirement. Other sources of income for
TOs will be wheeling charges and congestion fees that will be used to pay down
the TQs' transmission revenue requirements.
3.3.1.6 Utility Distribution Company (UDC)
Also known as the Local Distribution Company (LDC), Regional Electricity Company
(REC), or the Load Serving Entity (LSE) in other parts of the world, the UDCs
will own and operate the distribution
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system facilities ("wires") and connect all energy customers, whether direct
access customers or bundled retail customers, to the distribution system. UDCs
may also provide the essential retail customer services (such as meter reading)
to their bundled retail customers and to some direct access customers.
One of the prime responsibilities of UDCs will be to operate and maintain
distribution facilities, in accordance with applicable safety and reliability
standards, regulatory requirements, applicable operating guidelines and prudent
utility practices. The UDCs will inform the ISO and the TOs if their planned
maintenance activities has a potential of impacting the ISO controlled grid. In
the event of system emergency, the UDCs will comply with all directions from the
ISO concerning the management and alleviation of the system emergency and will
abide by the ISO system emergency protocols. The ISO will have the authority to
direct a UDC to disconnect loads, if necessary, to avoid an imminent system
emergency or allow the ISO to regain operational control over the ISO controlled
grid during an actual system emergency.
The UDCs are expected to be the existing lOUs in California. They will procure
energy from PX at spot market prices and supply their bundled retail customers
and collect annually determined Performance Based Rates from these customers for
the energy provided. They will also bear the cost of stranded investments of the
existing lOUs and will collect for such costs from all energy customers, whether
direct or bundled, via the Competitive Transition Charge (CTC) rate component.
3.3.1.7 Retailers
Also known as the Retail Marketers and Retail Aggregators, the retailer will be
independent and registered entity that would sign up retail energy customers for
provision of energy or customer services. Retailers could procure energy for
their customers via the UDC, PX or the SCs.
3.3.1.8 Energy Customer (EC)
In California, any retail energy customer will have the right to receive service
from the UDC at rates that change once a year based on a Performance Based
Ratemaking mechanism. Such customers, called Bundled Retail Customers (BRCs),
are expected to mainly consist of residential and small commercial customers;
although small customers can band together through a retailer to attain all the
necessary qualifications of a direct access customer (below).
Alternatively, subject to proper protocols, an energy customer may become a
Direct Access Customer (DAC) and purchase energy directly via a Scheduling
Coordinator or at spot prices from the PX. DACs are expected to mainly consist
of large commercial and industrial customers.
3.3.1.9 Ancillary Services Provider (ASP)
Ancillary services for the California's energy market will consist of:
- Spinning Reserve
- Non-Spinning Reserve
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- Regulating Reserve
- Replacement Energy Reserve
- Supplemental Reactive Power
- Black Start
ASPs are expected to mainly consist of the same entities that will provide
energy supplies. PX or Scheduling Coordinators may purchase all or part of their
ancillary services needs directly from ASPs (self provision) or from the ISO. PX
and ISO will procure the required spinning reserve, non-spinning reserve and
regulating reserve ancillary services via daily and hourly competitive auctions
and will procure their supplemental reactive power and black start ancillary
services mainly via long-term competitive auctions. SCs can procure self
provided ancillary services under any terms that are mutually agreeable between
the SCs and ASPs. Finally, the ISO, will procure the needed supplemental energy
reserve ancillary service through a "real-time" auction.
Regardless of the procurement mechanism, the ASPs must register their ancillary
services bids through the PX or SCs. The PX and SCs will forward to the ISO all
bids that they receive for ancillary services in accordance with the ISO tariff
except for those bids that the PX or SCs have accepted in order to self-provide
ancillary services.
3.3.2 Interaction Among Market Participants
Exhibits 3-14 and 3-15 schematically demonstrate interactions among various
market participants in California restructured market. These interactions are
mainly related to power system operations need.
Exhibit 3-16 presents the interactions among the same market participants in
further detail by showing other aspects of market operation, namely, the flow of
power and energy (shown with kW and kWh), energy related funds (shown with $),
market related information (shown with i) and operating information and commands
(shown with ).
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Exhibit 3-14
Overview of Market Participants Interactions for System Operation in
the Restructured California Energy Market
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Exhibit 3-15
Information Exchange among Market Participants in the Restructured
California Energy Market
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4. IMPACT ON POWER SYSTEM PLANNING
In this chapter we describe the impact of restructuring on power system planning
by comparing the players, paradigms, procedures, tools and accountability for
power system planning in the traditional and the emerging energy market
structures. We will go through this exercise for each segment of utility market,
namely, generation, transmission and distribution planning. When referring to
traditional energy markets, we imply vertically integrated, fully regulated
utility companies with obligation to serve and a guaranteed rate of return on
"prudent" investment.
4.1 PLANNING IN THE EMERGING ENERGY MARKETS
Exhibit 4-1 compares the main aspects of power system planning for the
traditional and emerging energy market structures. This exhibit is self
explanatory and is meant as a preamble to presentation of planning for
individual segments of electrical energy markets.
Perhaps the most prominent conclusion that can be drawn from the comparison
presented in Exhibit 4-1 is that the focus in planning will, in general, shift
from long-term reliability of service to short-term "profitability" of market
participants. Experience in some restructured energy markets, particularly in
South America, has shown that such short-term focus on profitability can result
in resource shortages or excesses. However, the regulators can intervene in the
process (as they have done on several occasions), to the extent that they can,
by tying profitability of market participants to the reliability of service and
mitigate swings in supply availability.
Hence, the question of resource adequacy in the emerging electrical energy
markets will be highly dependent on whether or not the new utility structures
include an entity (or mechanism) responsible for producing the correct economic
signals for investment. For example, in a pool structure, the pool may be
assigned such a role and engage in long-term agreements with generators and
distribution companies. In general, however, the question of ensuring adequate
supply will probably be addressed by a combination of regulatory directives and
rules, together with the suppliers, the grid company (operator) and the LDCs
forming some form of a cooperative to ensure adequate communication of the
future needs and plans of all participants.
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4.2 GENERATION PLANNING IN THE EMERGING ENERGY MARKETS
The unbundling of generation, transmission and distribution will alter the
nature of the traditional planning approaches used by the vertically integrated
utility. The largest effect will be the result of the free market for
generation. Essentially, the generation market will consist of a large number of
independent producers and unregulated utility affiliates who will provide the
supply under free market investment and risk rules. They will compete for
capital with other investments and it is likely that long-term supply contracts
(in addition to short-term contracts) will be an essential feature for the
industry.
Exhibit 4-2 compares the main aspects of generation planning in the traditional
and emerging energy market structures. Many similarities to the results
presented in Exhibit 4-1 should be expected and can be observed. Here again the
main conclusion is the shift in focus away from long-term reliability of service
towards short-term "profitability" of market participants and shift in process
away from central planning to decentralized modular planning.
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4.3 TRANSMISSION PLANNING IN THE EMERGING ENERGY MARKETS
The expansion of the transmission network will ideally require that the grid
company or some similar agency provide locational pricing, congestion pricing
and long term and short term marginal costs to guide expansion decisions. The
expansion of the transmission network is expected to be coordinated within each
region. The entity responsible for the building of the new facilities could be
the grid company, a regional transmission group or any independent entity.
An important consideration in planning and investment decisions in the new
utility environment is the need to adopt a new approach for transmission
planning. While fundamentals such as load forecasting will not change, load
forecasts may need to be developed by the local distribution companies and
communicated to the transmission grid planners. Moreover, long-term bilateral
transactions play an important role. Forecasting the location of the resource
where the load is to be supplied from is as important as forecasting the load
itself.
Since the operation of the transmission system is expected to remain as a
monopoly and regulated, it is expected that there will provisions for a
transmission planning role in the restructured markets as well. However, this
role is expected to be played collectively by several
organizations/institutions. Institutions that are expected to be involved in
transmission planning include the regulators, the ISO, transmission
owner/operator, energy suppliers, energy marketers, local distribution companies
and direct access customers. Each of these institutions will advocate their own
objectives when planning transmission expansion.
Transmission planners in the new markets are expected to use many of the
historical transmission planning techniques, albeit with modifications.
Techniques such as power flow, optimal power flow and transient stability models
will continue to be used. However, many of these models are expected to use
probabilistic techniques to account for the many uncertainties that the
transmission planner will be facing in the emerging markets. Noteworthy
uncertainties include:
- Lack of information on future resources (in-service date, size,
location, technologies, availabilities)
- Insufficient and fragmented information on future load growth
- Stronger environmental barriers to transmission expansion
- Uncertainty of recovering investment costs
- No incentive to trade operating and investment costs, as these are
borne by different business entities
- Increased and uncertain "loop flows"
- Daily variation in load and resource portfolios
- Complex transmission rights including resell rights
- Conflicting federal and state regulatory oversights and goals
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Transmission system has often been modeled in a deterministic and scenario
oriented manner (single or double contingency criteria). The deterministic
approach does not explicitly take into account the probability of failure of the
transmission component and the related value of service to the customers. In the
new utility environment, the investors would be hesitant to overbuild the
transmission system to withstand low probability events. In fact, the criteria
presently used for evaluating the reliability of the transmission systems is
expected to be re-examined.
With the transmission open access, more simultaneous transactions are expected
to be going across the transmission network. The task of keeping track of these
transactions will be very challenging. New techniques will have to be developed
to evaluate and monitor the impacts of these transfers through the utility
transmission network and their impacts on network reliability.
Exhibit 4-3 presents a comparison of transmission planning in traditional and
emerging energy market structures.
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4.4 DISTRIBUTION PLANNING IN THE EMERGING ENERGY MARKETS
Since distribution "wire" service is expected to see the least structural
change, it may be conjectured that distribution planning will also face the
least change. Local distribution companies are expected to remain more or less
intact under the same overall structure and regulatory oversight.
However, distribution planners will need to cope with new realities mainly due
to the presence of direct access retail customers, penetration of small modular
generators onto distribution feeders and different rules for ratemaking. Direct
access customers translate into uncertainty about the location, amount,
consumption patterns and "quality" of loads belonging to direct access customers
(particularly the new ones). Distributed generation will bring with itself the
uncertainty about power flow directions and magnitudes. Furthermore, the
proliferation of distributed generation using non-traditional technologies and
special loads with high harmonic contents are expected to add serious challenge
for distribution planners trying to ensure long-term power quality of the
distribution systems.
Retail service offerings which are expected to go through fundamental changes
will also introduce additional challenges for distribution system planning. Some
potential retail service offerings will force the distribution system to be used
in ways for which they are not designed. For example, special high reliability
service offerings to a "sensitive" energy customer may require frequent
switching of the distribution feeder which would require planning for
specialized automatic switches and dynamic load transfers.
The utility distribution companies will face intense competition from new
entrants into the market. They will experience greater demand from their
customers for expanded and faster services. The distribution customers will be
differentiated according to the quality and level of services they demand. The
distribution companies, as load serving entities, will expand the range of their
products and services. The distribution infrastructure and right of way will be
planned not only to provide energy to the end consumer, but also to provide a
variety of information and communication services.
Exhibit 4-4 presents a comparison of distribution planning in traditional and
emerging energy market structures.
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4.5 POWER SYSTEM PLANNING IN CALIFORNIA'S EMERGING ENERGY
MARKET
In general, expansion planning for all segments of electrical energy market in
California will be decentralized and left to market participants. However, there
will be a backstop process in order to discourage or prevent long-term capacity
shortages due to the inaction of market participants.
In this section we will discuss generation and transmission planning protocols
planned for California's restructured energy market. It must be noted that this
presentation will only cover the planning protocols as they are conceived at
present, and may not correspond to the actual future market behavior.
4.5.1 Generation Planning in California's Emerging Energy Market
Generation planning will be fully decentralized and left to market forces.
Market participants will make their investment decisions based only on their own
needs by taking into account, among others, the following factors:
- minimum lead time
- use of small modular technologies
- ensure high availability when supplies are most valued
- allow for provision of ancillary services-
- locate where there are resource shortages due to transmission
congestion by relying on transmission price signals
The backstop process for generation planning will work as follows:
The ISO will collect from Scheduling Coordinators (including the PX) the
forecast weekly peak demand on the ISO controlled grid and compare the forecast
peak demand with the Scheduling Coordinators' forecast generation capacity.
These collated forecasts are expected to cover a period of twelve months (on a
rolling basis) and be posted on the public information network.
If the collated forecasts show that the applicable WSCC/NERC reliability
criteria can be met during peak load periods, then the ISO shall take no further
action. However, if the collated forecasts show that the applicable WSCC/NERC
reliability criteria cannot be met during peak load periods, then the ISO shall
facilitate the development of "market mechanisms" to bring the peak periods into
compliance with the applicable reliability criteria. The ISO will solicit bids
for load curtailment contracts giving the ISO the right to reduce the loads of
those parties that win the contracts when there is insufficient generation
capacity to satisfy those loads in addition to all other loads. The contracts
will provide that the ISO's curtailment rights can only be exercised after all
available generation capacity has been fully utilized, and the curtailment
rights will not be exercised to stabilize or otherwise influence prices for
power in the energy markets.
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If, after receiving all curtailment bids, the ISO is still unable to comply with
the applicable reliability criteria, the ISO will take any steps that it
considers to be necessary to ensure compliance, including the negotiation of
contracts through processes other than competitive solicitations.
The ISO may, in addition to the required annual forecast, publish a forecast of
the peak loads and generation resources for two additional years. This forecast
would be for information purposes to allow market participants to take
appropriate steps to satisfy the applicable reliability criteria.
4.5.2 Transmission Planning in California's Emerging Energy Market
In this section we will discuss the steps prescribed for transmission planning
in California's emerging energy market.
4.5.2.1 Step 1: Determination of Transmission Expansion Needs
The ISO, a Transmission Owner (TO), or any other market participant may
determine the need for, and propose a transmission system addition. A
transmission addition or upgrade is deemed to be needed where it would promote
economic efficiency or maintain system reliability as defined below.
Economically driven projects could fall in one of the following categories:
- Transmission addition or upgrade projects that their sponsor, other
than the TO, commits (and is able) to pay the full cost of the
project.
- Transmission addition or upgrade projects that are claimed to be
economically beneficial by the ISO or by the project sponsor, but
that the project Sponsor is unwilling to commit to pay the full cost
of the addition or upgrade. Such projects will be considered to be
promoting economic efficiency if the economic benefits of the
proposed transmission additions or upgrades would exceed their
costs; the pricing methodology used for the transmission projects
would, to the extent practicable, assign their costs to their
beneficiaries in proportion to their net benefits; and no market
participant or the ISO disputes the project.
- Transmission addition or upgrades projects in the category above
that are disputed by any market participant or the ISO will go
through a dispute resolution process before being considered as
promoting economic efficiency.
Reliability driven projects are determined as follows:
- The ISO or the TO, in coordination with the ISO and market
participants, through the coordinated planning processes for
California, WSCC and the relevant RTGs, will identify the need for
any transmission additions or upgrades required to ensure system
reliability. In making this determination, the TO and the ISO will
consider lower cost alternatives to the construction of transmission
additions or upgrades, such as acceleration or expansion of existing
projects, demand-side management, remedial action schemes,
interruptible loads or reactive support.
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- The TO will perform the necessary studies or provide information to
the ISO or any market participant as part of the coordinated
planning process to enable them to perform the necessary studies and
to determine the facilities needed to meet all applicable
reliability criteria.
4.5.2.2 Step 2: Transmission Planning and Coordination
The ISO will actively participate with each TO and the other market participants
in the ISO controlled grid planning process. Each TO will develop annually a
transmission expansion plan covering a minimum five-year planning horizon for
its portion of the ISO controlled grid. The TO will coordinate with the ISO and
other market participants in the development of the plan. The TO will be
responsible for ensuring that its transmission plan meets all applicable
reliability criteria.
The ISO will review the TOs' transmission expansion plans and projects to ensure
that each TO's expansion plans meet the applicable reliability criteria. The TO
will provide the necessary assistance and information as part of the coordinated
planning process to the ISO to enable it to carry out its own studies for these
purposes. If the ISO finds that the TO's plan or projects do not meet the
reliability criteria, the ISO will provide comments on the plans, and the TO
will reassess its plans, as appropriate. The ISO may also propose new projects
or suggest project changes (e.g., timing, project size) for consideration by the
TO. Changes or additions made by the ISO and accepted by the TO will be included
in the TO's expansion plan.
4.5.2.3 Step 3: Studies to Determine Facilities to be Constructed
If a TO is obligated to construct or expand facilities or if the ISO or any
market participant requests that a facility study be carried out, the TO (in
coordination with the ISO or the relevant market participants as the case may
require), will perform studies or provide information to the ISO or the relevant
market participant to enable it to perform studies.
4.5.2.4 Step 4: Operational Review of the Transmission Expansion Projects
The ISO will perform an operational review of all transmission expansion
projects to ensure that the facilities being proposed provide for acceptable
operating flexibility and meet all its requirements for proper integration with
the ISO controlled grid. If the ISO finds that such facilities do not provide
for acceptable operating flexibility or do not adequately integrate with the ISO
controlled grid, the TO will reassess its determination of the facilities
required to be constructed.
4.5.2.5 Step 5: State and Local Approval and Property Rights
The TO will be obligated to make a good faith effort to obtain all approvals and
property rights under applicable Federal, State and local laws that are
necessary to complete the construction of transmission additions or upgrades
required to be constructed.
If the TO cannot secure any such necessary approvals or property rights and
consequently is unable to construct a transmission addition or upgrade, it will
promptly notify the ISO and the project sponsor to convene a technical meeting
to evaluate alternative proposals. The ISO will take such action as it
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reasonably considers appropriate, in coordination with the TO, the project
sponsor and other market participants, to facilitate the development and
evaluation of alternative proposals.
If a third party can obtain all approvals and property rights to complete the
construction of transmission additions or upgrades, the ISO may confer on such
third party the right to build the transmission addition or upgrade which a TO
has decided not to proceed with or has unreasonably delayed.
4.5.2.6 Step 6: WSCC and RTG Coordination
The project sponsor will have the responsibility for completing any applicable
WSCC or RTG regional coordination and rating study requirements to ensure that a
proposed transmission addition or upgrade meets regional planning requirements.
The project sponsor may request the TO to perform this coordination on its
behalf and at its expense.
4.5.2.7 Step 7: Cost Responsibility for Transmission Expansions or Upgrades
Cost responsibility for transmission additions or upgrades constructed will be
determined as follows:
- If the project sponsor commits to pay the full cost of a
transmission addition or upgrade, the full costs will be borne by
the project sponsor,
- If the need for a transmission addition or upgrade is determined by
the ISO or as a result of the ISO dispute resolution process, the
costs will be allocated to the beneficiaries, in the approximate
relative proportions by which they benefit from the project.
- If specific beneficiaries cannot be reasonably identified, then the
cost of the transmission addition or upgrade borne by that TO will
be reflected in its access charge.
4.5.2.8 Step 8: Ownership of and Access to Expansion Facilities
All transmission additions and upgrades constructed will form part of the ISO
controlled grid and will be operated and maintained by an appropriate TO. A TO
which owns or operates transmission additions and upgrades will provide access
to them to all market participants.
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5. IMPACT ON POWER SYSTEM OPERATIONS
Profound changes are expected in the operation of the power system in the
emerging market structures. The magnitude of these changes can be best
understood by the fact that completely new institutions (e.g., the power
exchanges, the pool operators, the ISOs) independent from the existing utilities
are being created to manage and oversee power system operation.
In this section we will discuss the impact of utility system restructuring on
power system operation much in the same fashion that we discussed the impact on
system planning. Our focus will be solely on the operation of the bulk power
system (not the distribution operation).
5.1 ELEMENTS OF POWER SYSTEM OPERATION
Power system operation consist of three main elements:
1. Real-time system operation
2. Operation scheduling (or planning)
3. Financial settlement
In the following, we will discuss the broad impact of utility industry
restructuring on these three' elements of power system operation.
5.2 REAL-TIME SYSTEM OPERATION IN THE EMERGING ENERGY MARKETS
Among the three operational areas mentioned above, real-time operation of the
power system is expected to experience fewer changes from that of the
traditional energy markets, even in those cases where a new institution such as
the ISO will be operating the system. This is specially true for operation under
emergency conditions.
Detailed discussion of real-time operation will depend on specific operating
structures and practices, and is outside the scope of this report. Exhibit 5-1
presents the broad functional representation of real- time operations in the
emerging market structures. A brief description of the steps involved in real-
time system operation are as follows:
- Step 1: Acquisition of real-time data on system operation and
"static" information on market participants and facilities.
- Step 2: Estimation of a consistent and accurate picture of the power
system operating condition.
- Step 3: Economic dispatch analysis to update generation dispatch in
response to load or other system changes. This analysis will adjust
generation base points based on real-time telemetered changes and
events in the power system.
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- Step 4: On-line "power system optimization" process to determine the
"appropriate" dispatch of all system resources and controls (energy
supplies and demands, ancillary services, transmission control,
etc.) to ensure security and efficiency of system operation under
its existing operating condition; also to determine "binding
constraints" and penalty factors for economic dispatch analysis. All
dispatchable resources and controls (subject to their constraints),
including curtailment of supplies, loads, bilateral transactions,
and ancillary services are included in this dispatch. The power
system optimization process can also evaluate real-time Available
Transfer Capabilities (ATCs), where applicable.
- Step 5: On-line voltage security assessment to verify that power
system operation is secure from voltage stability standpoint. If
insecurity is detected, this process should calculate and send an
updated set of power system operating constraints to the power
system optimization process for that process to update the dispatch
of all system resources and controls.
- Step 6: On-line dynamic security assessment to verify that the
transitory operation of the power system is secure. If insecurity is
detected, this process should calculate and send an updated set of
power system operating constraints to the power system optimization
process for that process to update the dispatch of all system
resources and controls.
- Step 7: A conventional AGC that monitors the deviation of frequency
from standard (reference frequency) and the deviation of net
interchange from its schedule. Frequency, and frequency deviation
measurements, are well known technologies; the schedule of net
interchange for each control area must be calculated knowing the
total load in a control area, and the net generation in the control
area. Generator set points and participation factors are used along
with the control error signal to keep frequency at its reference
value, keep net interchange on its schedule and active transmission
limits within their bounds at all times.
- Step 8: Calculation of "locational" marginal costs based on the
actual system operation to assist with the ex-post pricing and
settlement of energy supplies and services.
- Step 9: Posting of information related to real-time system operation
(including locational marginal costs) on the Public Information
System (e.g., the OASIS). Each piece of information must be properly
"encoded" for access by a specific participant (private
information), or all market participants (public information).
Note that while the steps involved for real-time operations in the restructured
industry seem by and large to be the same as those of a modern control center in
a vertically integrated utility, there are important differences in the system
operation paradigm. This shift in paradigm is mainly related to the importance
of following pre-determined operating schedules to the maximum extent possible
and in the use of "power system optimization" process for dispatching all system
resources and supplies in a coordinated and "optimal" manner. In fact this shift
in paradigm is expected to bring about an integration of on-line power system
optimization and economic dispatch functions to better coordinate and "optimize"
the dispatch results. Exhibit 5-2 compares the major aspects of real-time
operation in the traditional and emerging energy market structures.
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Exhibit 5-1
Functional Representation of Real-time System Operation
in Emerging Energy Markets
[GRAPHIC OMITTED]
[GRAPHIC OMITTED]
KEMA Consulting
5.3 OPERATIONS PLANNING IN THE EMERGING ENERGY MARKETS
Traditionally operations planning deals with commitment and scheduling of
generating units and transactions for the next few hours to a few weeks into the
future. With unbundled transmission services, there is a need to also schedule
transmission services explicitly. These include scheduling and costing of
ancillary services (spinning reserves, regulating reserves, reactive reserves,
etc.) as well as transmission system availability.
Operations planning will see the biggest change in the restructures utility
industry. Traditionally, operations planning has been a "back room" internal
function of the utilities where operations planners have determined "loose"
schedules mainly for energy supplies (generators) and net interchanges based on
disjoint unit commitment and network studies. Also determined through operations
planning process, have been the operating nomograms.
In the restructured utility industry, operations planning (or perhaps better
termed, "operations scheduling") will turn into an open process with
participation by many market participants. The process will be used to determine
"tight" schedules for all system resources and controls. System resources and
controls considered here include:
- all energy supplies and loads;
- bilateral transaction levels;
- ancillary services;
- curtailable loads and transactions; and
- transmission control settings.
For the emerging energy markets, operation schedules for a specific time
interval are often developed through multiple scheduling processes. Often there
is a day-ahead process in which a set of schedules are developed for system
resources and controls for each hour of the next day based on interaction
between the system operator and market participants based on "day-ahead bids" by
the market participants. Then there is the hour-ahead process whereby hourly
schedules are updated based on hour-ahead bids from market participants.
Finally, occasionally there are "last-minute scheduling refinements" based on
supplemental energy bids by some market participants.
Exhibit 5-3 presents a functional representation of power system operations
planning process. This process is by and large valid for day-ahead, hour-ahead
and last-minute scheduling processes. The general steps involved in operations
scheduling in the restructured utility industry is expected to include:
- Step 1: Collection and validation of market data such as prices,
magnitudes and operating limits for energy and ancillary services
supplies from market participants.
- Step 2: Unit commitment process to determine the supply and load
schedules for the scheduling period while accommodating the
bilateral transaction schedules. This process usually ignores the
detailed security concerns of the transmission system.
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- Step 3: "Power system optimization" process to determine the
dispatch of all dispatchable system resources and controls for the
individual time intervals of the scheduling time period (e.g., each
hour of the next day). This process would verify the security and
efficiency of power'system operation for each of the time intervals
as determined by the unit commitment process (step 2). If insecurity
is detected, the process would redispatch system resources and
controls for the specific time interval being studied. The
redispatch requirements may be shared with market participants to
allow them to revise schedules. If so, the process will restart from
Step 1 based on new information from market participants. This step
is also known as the "congestion management" process.
- Step 4: Voltage security assessment to verify that the operation of
the power system will remain secure from voltage stability
standpoint for each time interval of the scheduling time period. If
insecurity is detected, the process should dispatch additional
resources to alleviate voltage security concerns, or alternatively
determine new operating constraints for use by the power system
optimization process.
- Step 5: Dynamic security assessment to verify that transitory
operation of the power system will be secure for each time interval
of the scheduling time period. If insecurity is detected, the
application would attempt to dispatch additional resources to make
power system operation secure. If power system operation remains
insecure, this process should identify new operating constraints for
use by the power system optimization process.
- Step 6: Calculation of "locational" marginal costs based on the
scheduled system operation to allow ex-ante pricing and settlement
of energy supplies and services.
- Step 7: Posting of scheduling related information (including
locational marginal costs) on the Public Information System (e.g.,
the OASIS). Each piece of information should be properly "encoded"
for access by a limited number or all market participants.
Note that while the steps involved for operations scheduling in the restructured
industry is by and large the same as those used by a more advanced vertically
integrated utility, the main difference comes from the fundamental shift in
operation planning paradigm. This shift in paradigm is reflected in formal and
"strong" interaction with market participants when determining operating
schedules and the in the use of a "power system optimization" process to
dispatch all system resources and supplies in a coordinated and optimum manner.
In fact, this shift in paradigm will propel the industry to integrate the power
system optimization capability and the unit commitment function for results that
are better coordinated and "optimized". Another important factor to remember is
that depending on the market rules, and regulatory directives, the objective
function used in the unit commitment algorithm may be different. For example, if
all generators receive the market clearing price rather than their bid price,
the objective function must minimize the marginal price rather than the sum of
bid prices.
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Exhibit 5-3
Functional Representation of Operations Planning
in Emerging Energy Markets
[GRAPHIC OMITTED]
perotsystems"
KEMA Consulting
KEMA-ECC & Macro Corporation
Exhibit 5-4
Potential Configuration of the Unit Commitment Process to Account
for Transmission Constraints
[GRAPHIC OMITTED]
[GRAPHIC OMITTED]
KEMA Consulting
KEMA-ECC & Macro Corporatian
5.4 MAINTENANCE SCHEDULING
Traditionally, long-term and short-term maintenance scheduling of generation and
transmission facilities are performed in a disjoint manner with little regard to
their interaction and other factors such as the criticality of specific
components under specific operating conditions.
In the emerging electrical energy markets, long-term maintenance scheduling of
generation and transmission facilities is likely to be left to their owners to
be developed and implemented as desired. However, these owners will be highly
encouraged to account for market signals received from the system operator
(e.g., the ISO) in order to make sure that their facilities are available when
these facilities are valued the most.
Short-term maintenance scheduling will need to be very closely coordinated with
the system operator. For many emerging markets, there are provisions to allow
the operator to override a scheduled maintenance (e.g., postpone it) based on
system operating needs. Of course such a provision will obligate the system
operator to become accountable to market participants when making such
decisions.
We will discuss the maintenance scheduling in further detail when we discuss
power system operation in California's restructured utility industry below.
5.5 FINANCIAL SETTLEMENT
Traditionally the financial function of a vertically integrated utility related
to energy transactions (system operation) has been limited to:
- Payment for fuels and other energy purchase and transmission
contracts mainly determined as a result of long-term
contracts;
- Collection for energy sales to retail and wholesale customers
based on regulated rates; and
- Collection for provision of transmission services to wholesale
customers based on regulated rates.
Financial settlement for energy transactions in the emerging energy markets will
be substantially more complex and, at the minimum, would include:
- Payments to energy suppliers based on day-ahead, hour-ahead
and last minute supply schedules;
- Payments for all energy purchase and related transmission
contracts;
- Collection from energy customers (usually through their
agents) based on their demand schedules in day-ahead,
hour-ahead and last minute markets;
- Settlement of differences between scheduled and actual energy
supplied and consumed;
- Payments to ancillary services providers and collection from
energy customers (usually through their agents) for the
procured ancillary services; and
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- Collection of congestion fees from energy customers (usually
through their agents) and payment of such fees to the
Transmission Owners (or Transmission Congestion Contract
holders) or equivalent.
A more detailed account of financial settlement is provided in Section 6.5 of
this report.
5.6 POWER SYSTEM OPERATIONS IN CALIFORNIA'S EMERGING ENERGY MARKET
The most noteworthy aspect of system operation for California's planned emerging
energy market is the process of operations scheduling by the power exchange (PX)
and the ISO. In the following we will briefly discuss the prominent features of
the PX and ISO operations scheduling protocols.
5.6.1 Operation Scheduling by the PX
The PX will develop energy schedules for its own market based on all bids
received from PX Participants (PX participants include energy suppliers, or
their agents, energy customers, or their agents, and ancillary services
providers). The PX will match supply and load for each hour of the scheduling
time period based on the price bids for energy, and thereby clears the market.
The PX will then develop the schedule for ancillary services based on the prices
bid for such services. In addition, the PX will calculate the prices at which
trades in Energy and Ancillary Services are transacted in the PX day-ahead
market and the PX hour-ahead market.
5.6,1.1 PX's Day-Ahead Bidding and Scheduling Procedures
There are four major steps in PX's development of day-ahead schedules. These
are:
1. Collection and validation of bids from PX Participants
2. Conducting the energy auction
3. Developing the PX Initial Preferred Schedule
4. Developing the Final PX Schedule
5.6.1.1.1 Collection and Validation of Bids from PX Participants
Each PX Participant will submit its day-ahead bids in the bid format specified
by the PX for supply and demand price/quantity bids. Price may be different for
each energy block subject to specific rules. Bids submitted into the auction
that leads to the PX's initial preferred schedule need not be attributed to any
particular generating unit or physical scheduling plant - such a bid is referred
to as a portfolio bid. Furthermore, supply bidders should internalize all their
costs (e.g., start-up, ramping, etc.) and provide a single energy bid price in
$/kWh. PX will validate each bid for completeness, and eligibility of the
bidder.
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5.6.1.1.2 Conducting the Energy Auction
The PX will create aggregate supply and demand curves in accordance with its
bidding and bid evaluation protocol. The PX will determine a day-ahead
Market-Clearing Price (MCP), total demand and resulting schedules for each hour
and communicate that price, along with the resulting tentative schedules, to all
PX Participants by posting on WEnet (California's Public Information System).
The PX will assess the potential for overgeneration for each hour in the
day-ahead market and communicate any overgeneration conditions to the PX
Participants.
Using an iterative process, the above procedure may be repeated up to four more
times. The PX Participants may revise their bids as they see fit in this
iterative process. Information on any revisions to submitted bids will be
processed by the PX, and revised hourly market-clearing prices and tentative
schedules for each iteration will be posted on WEnet for all PX Participants to
consider.
The PX will close the energy auction when a prescribed maximum number of
iterations has been performed or when the time allotted by the PX for the energy
auction has elapsed or, prior to that time, if the auction process has resulted
in convergence to a schedule such that no supply or demand bid revisions were
submitted. The PX will then determine the unconstrained hourly Market-Clearing
Price, total demand, and the resulting schedules for each settlement period and
communicate the Market-Clearing Price and resulting schedules to the PX
Participants. At this point, any successful PX Participant that has previously
used portfolio bidding will be asked to submit individual unit schedules from
its portfolio. All PX Participants will be invited to submit ancillary services
bids and adjustment bids for use by the ISO to relieve congestion. The PX will
determine if overgeneration exists or is likely to exist and calculate the
amount and hours of overgeneration.
5.6.1,1.3 Developing the PX Initial Preferred Schedule
The PX will determine to what extent, if any, it wishes to self-provide
ancillary services and will procure them through its own ancillary services
auction. The PX will submit the resulting day-ahead ancillary services schedules
and any unselected ancillary services bids, together with all scheduling
information for energy, such as adjustment bids, to the ISO as part of the PX's
Initial Preferred Schedule. The PX will communicate to PX Participants if its
Initial Preferred Schedules are unbalanced due to an overgeneration condition
that requires ISO action.
5.6.1.1.4 Developing the Final PX Schedule
If the ISO determines that overgeneration exists given the Initial Preferred
Schedules that it has received from Scheduling Coordinators (including the PX),
it will require the PX to implement necessary reductions in its schedule. The PX
will determine whether to submit revised Initial Preferred Schedules and revised
bids to address the overgeneration. Once overgeneration has been addressed, if
the ISO finds that inter-zonat congestion1 exists the PX may: 1) iterate with
the PX Participants to develop revised schedules and price bids to relieve the
inter-zonal congestion, 2) accept the ISO's Advisory Redispatch Schedule, or, 3)
elect to resubmit the original Initial Preferred Schedules. Upon receipt of a
revised Preferred Schedule, the ISO will reapply its Congestion Management
protocols.
Inter-zonal congestion refers to the condition where collective energy and
ancillary services schedule result in insecure system operating condition based
on flows between the California's Congestion Zones.
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The ISO will complete final hourly schedules and transmission prices for energy
and final schedules and prices for ancillary services. This information will be
provided to the PX who will then notify all PX Participants of the final supply
and demand schedules, zonal Market-Clearing Prices for energy, and final
ancillary services schedules and prices.
5.6.1.2 PX's Hour-Ahead Bidding and Scheduling Procedures
The following are the steps in the major steps adopted by the PX for the
hour-ahead scheduling process:
1. Receipt and validation of bid data
2. Hour-ahead bid evaluation
3. Calculation of hour-ahead schedules
4. Submission of schedules and bids to the ISO
5.6.1.2.1 Receipt and Validation of Bid Data
Each PX Participant will submit its bid information using the bid format
specified by the PX for supply and demand price/quantity bids. All bids will be
validated to ensure that the bid format has been followed. No portfolio bids
will be accepted in the hour-ahead market.
5.6.1.2.2 Hour-Ahead Bid Evaluation
The PX will evaluate the bids it receives for the Hour-Ahead Market for
eligibility, completeness, and compliance with market rules. However, unlike
day-ahead bidding, there will be no iterations in the Hour-Ahead Market.
5.6.1.2.3 Calculation of Hour-Ahead Schedules
The output from the PX hour-ahead bid evaluation will be the supply and demand
deviations from the corresponding hour in the final day-ahead schedule. The PX
will calculate the hour-ahead schedules by summing the output from the
hour-ahead bid evaluation with the final day-ahead schedule for each unit. The
PX will determine to what extent, if any, it wishes to self-provide ancillary
services and will procure them through its own ancillary services auction.
5.6.1.2.4 Submission of Schedules and Bids to the ISO
The PX will submit the resulting hour-ahead schedules and any unselected
ancillary services bids, together with all scheduling information for energy
such as adjustment bids, to the ISO. In case the schedules lead to transmission
congestion, the ISO will make the necessary schedule changes, based on
adjustment bids. No iteration will take place with the PX in the hour-ahead
market. Upon notification by the ISO that the PX hour-ahead schedules have been
accepted, or of any required adjustments to
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relieve congestion, the PX will communicate to all the PX Participants which
submitted bids to it that have been accepted.
5.6.2 Operation Scheduling by the ISO
The ISO, similar to the PX, will perform its operations scheduling for the two
markets: The day-ahead market and the hour-ahead market. In addition, the ISO,
will perform limited scheduling activities on "real-time" basis (30 minutes
ahead of the actual operating hour) for some ancillary services (supplemental
energy, spinning and non-spinning reserve).
For both daily and hour scheduling, the steps involved in the ISO's scheduling
activities are as follows:
1. Receipt and validation of Preferred Schedules
2. Evaluation of the Revised Schedules
3. Development of the Final Schedule
5.6.2.1 Receipt and Validation of Preferred Schedules
A Preferred Schedule will be submitted by each Scheduling Coordinator (including
the PX) on a daily and/or hourly basis to the ISO which will represent its
preferred mix of generation (including transmission losses) to meet demand. The
ISO will validate the schedules for eligibility, internal consistency, and cross
consistency (an energy purchase in the schedule of a SC, must match an energy
sale in the schedule submitted by the other party). The Preferred Schedule will
also include an indication of which resources (generation or demand) if any may
be adjusted by the ISO to eliminate Congestion. If the ISO notifies a Scheduling
Coordinator that there will be no congestion on the ISO controlled grid, the
Preferred Schedule will become that Scheduling Coordinator's Final Schedule.
5.6.2.2 Evolution of the Revised Schedules
If the sum of Scheduling Coordinators' Preferred Schedules would cause
congestion across any Inter- Zonal Interfaces, the ISO will issue to the
Scheduling Coordinators whose Schedules contribute to the congestion, suggested
Adjusted Schedules that will reflect adjustments made by the ISO to each
Scheduling Coordinator's Preferred Schedule to eliminate congestion, based on
the initial adjustment bids submitted in the Preferred Schedules. Following
receipt of a suggested Adjusted Schedule, a Scheduling Coordinator may submit to
the ISO a Revised Schedule, which will be a balanced schedule and which will
reduce or eliminate congestion.
5.6.2.3 Development of the Final Schedule
If the ISO notifies a Scheduling Coordinator that there will be no congestion on
the ISO controlled grid, the Revised Schedule will become that Scheduling
Coordinator's Final Schedule. If no Scheduling Coordinator submits any changes
to the suggested Adjusted Schedules, all of the suggested Adjusted Schedules
will become the Final Schedules. The Final Schedules will serve as the basis for
settlement between the ISO and each Scheduling Coordinator.
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5.6.3 Maintenance Scheduling
For reasons mentioned earlier, maintenance scheduling in the California's
emerging energy market will be codified and highly coordinated, m the following,
we will describe the general protocols prescribed for maintenance scheduling in
California.
5.6.4 Maintenance Outage Planning
Each Market Participant (e.g.. Transmission Owner) will on annual basis provide
the ISO with a schedule of all maintenance outages which it wishes to undertake
during the following calendar year. The ISO Outage Coordination Office will
evaluate the requested maintenance outage or change to an approved maintenance
outage. If the ISO Outage Coordination Office determines that the requested
maintenance outage is not likely to have a detrimental effect on the efficient
use and reliable operation of the ISO controlled grid, the ISO will authorize
the maintenance outage and will notify the requesting market participant and
other entities who may be directly affected. Otherwise, the ISO may reject the
requested maintenance outage. The determination of the ISO Outage Coordination
office will be final and binding.
5.6.4.1 Maintenance Outage Requests by the ISO
The ISO Outage Coordination Office may at any time request a maintenance outage
or a change to an approved maintenance outage from a market participant in order
to secure the efficient use and reliable operation of the ISO controlled grid.
The affected market participant may: (1) refuse the request; (2) agree to the
request; or (3) agree to the request subject to specific conditions. The market
participant will have to make every effort to comply with requests by the ISO
Outage Coordination Office. In the event that the market participant refuses the
ISO's request, it will have to provide written justification for its position to
the ISO Outage Coordination Office.
In response the ISO may: (1) overrule any refusal of a maintenance outage by the
market participant, in which case the ISO's determination will be final; (2)
accept any changes or conditions proposed by the market participant, in which
case the maintenance outage request will be amended accordingly; or (3) reject
the change or condition, in which case the ISO Outage Coordination Office and
the market participant will determine if acceptable alternative conditions or
changes can be agreed. If the market participant and the ISO Outage Coordination
Office cannot agree on acceptable alternative conditions or changes to the ISO
Coordination Office's request for a maintenance outage, the ISO's determination
will be final.
5.6.4.2 Maintenance Outage Requests by Market Participants
The ISO Outage Coordination Office will provide notice to market participants of
the approval or disapproval of any requested maintenance outage. Additional
approval notification will be provided by the ISO Outage Coordination Office to
any market participant that may be directly affected by the maintenance outage.
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5.6.4.3 Final Approval
On the preceding day of an approved maintenance outage, the market participant
will confirm its requirements with the ISO Control Center. On the day of an
approved maintenance outage, the market participant will contact the ISO Control
Center for final approval of the maintenance outage. No maintenance outage will
start without ISO's final approval.
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6. NEW BUSINESS FUNCTIONS
In the new utility environment there are new categories of market participants
(Transcos, Energy Aggregators, etc.) each pursuing different business
objectives. The new operators of the power system (the ISO, and where relevant
the Power Exchange) must remain impartial towards the various market
participants in order to ensure a level playing field. At the same time the
ISO/PX must conduct their business such that the power system continues
functioning without degradation in reliability and without economic burden to
the end users. In fact, the main justifications set forth by the proponents of
power industry restructuring has been the belief that the restructured
environment will lead to lower energy prices to the end users without
undermining system reliability. Various market participants in the new
environment need their own tools to plan and manage their business effectively
In this section we limit the discussion to the main new business functions and
tools that the ISO/PX must have in order to conduct their business effectively.
The new business environment must facilitate trading of both energy supply and
transmission rights. In the U.S., an important new concept in trading and usage
of the transmission rights is the Available Transmission Capability (ATC). We
will first explore the ATC concept and its variations as currently applied,
along with the relevant concept of Flow-based Transmission Service Reservation.
We will then address the key new functions and tools that the ISO/PX need in
order to facilitate trading and settlements in the new business environment.
6.1 AVAILABLE TRANSMISSION CAPACITY
The transmission capability of a transmission network depends on the pattern of
usage of the network. In many cases where point-to-point transmission service is
envisaged (delivery of certain number of MWs from point A to point B) the term
transfer capability is used. Available Transfer Capability (ATC) is obtained by
subtracting from the so-called Total Transfer Capability (TTC) the existing
transmission commitments, along with some safety margin. The TTC calculations
are deterministic, and are based on a host of assumptions about the loads,
generation and interchange transactions for a specific point in time, e.g. next
24 hours, next month or next year. The safety margins account for the many
inherent uncertainties in .the assumptions, which become bigger, the farther
into the future ATC is calculated.
The following subsection offers specific definitions of these and other
pertinent terms, according to NERC.
6.1.1 Definitions
Available Transfer Capability (ATC) is a measure of the transfer capability
remaining in the physical transmission network for farther commercial activity
over and above already committed uses. Mathematically, ATC is defined as the
Total Transfer Capability (TTC) less the Transmission Reliability Margin (TRM),
less the sum of existing transmission commitments (which includes retail
customer service) and the Capacity Benefit Margin (CBM). These terms are defined
below.
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Total Transfer Capability (TTC) is defined as the amount of electric
power that can be transferred over the interconnected transmission
network in a reliable manner while meeting all of a specific set of
defined pre- and post-contingency system conditions.
Transmission Reliability Margin (TRM) is defined as that amount of
transmission transfer capability necessary to ensure that the
interconnected transmission network is secure under a reasonable range
of uncertainties in system conditions.
Capacity Benefit Margin (CBM) is defined as that amount of transmission
transfer capability reserved by load serving entities to ensure access
to generation from interconnected systems to meet generation
reliability requirements.
The treatment of ATC with respect to requests for the usage of the transmission
systems may depend on the firmness of the transmission rights stipulated in each
contract. The following terms are defined accordingly:
Curtauability is defined as the right of a transmission provider to
interrupt all or part of a transmission service due to constraints that
reduce the capability of the transmission network to provide that
transmission service. Transmission service is to be curtailed only in
cases where system reliability is threatened or emergency conditions
exist.
Recallability is defined as the right of a transmission provider to
interrupt all or part of a transmission service for any reasons,
including economic, that is consistent with PERC policy and the
transmission provider's transmission service tariffs or contract
provisions.
Non-recallable ATC (NATC) is defined as TTC less TRM, less
non-recallable reserved transmission service (including CBM).
Recallable ATC (RATC) is defined as TTC less TRM, less recallable
transmission service, less non-recallable transmission service
(including CBM). RATC must be considered differently in the planning
and operating horizons. In the planning horizon, the only data
available are recallable and non-recallable transmission service
reservations, whereas in the operating horizon transmission schedules
are known.
ATC and related terms are depicted graphically in Exhibit 6-1. They form the
basis of a transmission service reservation system that will be used to reserve
and schedule transmission services in the new, competitive electricity market.
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Exhibit 6-1: Related Terms in the Transmission Service Reservation System
[GRAPHIC OMITTED]
Source: NERC Publication Entitled Available Transfer Capabitiy
Definitions and Determination, June 1996
6.1.2 ATC Calculations Currently used in Different NERC Regions
As explained above, ATC depends on the existing transmission commitments, TTC,
CBM and TRM. A summary of approaches for computing these elements in different
NERC regions is given in Exhibits 6-2, 6-3, 6-4 and 6-5. For a given forecast of
area and bus loads, generation pattern and interchange transactions, TTC
represents the most restrictive of thermal, voltage or stability limits on a
given path or interconnection.
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Exhibit 6-2: TTC Calculation Methods
Region
[GRAPHICS OMITTED]
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Exhibit 6-3: ATC Calculation Methods
Region
[GRAPHICS OMITTED]
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Exhibit 6-4: CBM Methods
Region
[GRAPHICS OMITTED]
PEROTSYSTEMS(TM) KEMA CONSULTING
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EXHIBIT 6-2: TTC CALCULATION METHODS
REGION
ECAR TTC is the sum of Firm ATC, TRM, CBM, and Firm reservations and/or
schedules
ERCOT By Regional task force composed of all stakeholders and ISO
FRCC The nonsimultaneous transfers between two areas with all
facilities available and existing firm longterm commitments
modeled
MAAC Network response - limits are reflected to the appropriate control
area contract path
MAIN Regional calculation of network response (TTC = CITC + base
schedules)
MAPP Regional constrained paths - Transmission provider calculates base
on NERC principles and modeling
NPCC Rated path (interface limits) based
SERC First 31 days, will use on-line and off-line power flow and the
VAST/VST for FCTTC calculation for month 2 through year 10
SPP Seasonal calculations made by SPP, member companies make
recalculations during intervals between seasonal calculations for
operating changes
WSCC WSCC rated system path procedure calculated by control area or
capacity owner
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EXHIBIT 6-3: ATC CALCULATION METHODS
REGION
ECAR Distributed calculation/coordination methodology requires each
Transmission provider to calculate ATC values which are then
coordinated on a wide area basis TTC.
ERCOT By Regional task force composed of all stakeholders and ISO
FRCC ATC = TTC - TRM - CBM - (existing firm long-term commitments).
Note: In the operation time frame, non-recallable scheduled
transmission service is also subtracted from the
MAAC Network response - limits are reflected to the appropriate control
area contract path
MAIN Regional calculation with optional updates by transmission
providers. ATC calculated from CITC with adjustments made for TRM
and CBM.
MAPP Regionally constrained paths - MAPP calculates decrements from
TTC using flow-based method
NPCC Contract path, and actual flow based
SERC Will follow NERC "ATC Definitions and Determination" document
SPP Seasonal calculations made by SPP, member companies make
recalculations during intervals between seasonal calculations for
operating changes
WSCC WSCC rated system path procedure calculated by control area or
capacity owner
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EXHIBIT 6-4: CBM METHODS
REGION
ECAR Determined by each transmission provider as defined by their own
criteria within broad Regional Guidelines
ERCOT Not included
FRCC To be calculated using loss of load probability analysis with the
portion which flows through a particular interface, determined and
reserved by the individual utility
MAAC Allow for preservation of pool emergency import capability
MAIN Regional implicit calculation based on input from transmission
providers. Each transmission providers CBM considered separately.
MAPP Regionally constrained paths MAPP calculates for MAPP operating
reserve or emergency energy requirements
NPCC Allow for long-term reserve margin and generation planning
SERC By subregion and control area
SPP Control areas provide an explicit TRM and CBM consistent with
provisions of individual tariffs
WSCC Implicitly considered in establishing TTC calculated by control
area or capacity owner
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Exhibit 6-1: TRM Calculation Methods
Region
ECAR Determined by each transmission provider as defined by their own
criteria within broad Regional Guidelines
ERCOT Not explicitly included because of conservatism in calculation
FRCC A. The reduction in transfer capability resulting from modeling
the utility's operating reserve requirements and the most
critical generating unit off-line
B. The reduction in transfer capability resulting from modeling
the utility's operating reserve
MAAC Allow for uncertainty in weather and load forecasts, loop flows,
generator loss replacement, and loss of transmission facilities
under forecast extreme weather conditions
MAIN Regional and local implicit calculation of TRM. TRM determined
using percent ratings reduction and cnnfiricn<'f" factor
nmltinlier
MAPP Regionally constrained paths - Transmission provider may
calculate an auditable method, the default is 5%
NPCC Allow for uncertainty in load forecasts, loop flows, reserve
SERC By subregion and control area
SPP Control areas provide an explicit TRM and CBM consistent with
provisions of individual tariffs
WSCC Implicitly considered in establishing TTC calculated by control
area or capacity owner
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6.1.3 Flogate initiative by NERC
Because point to point transactions are hard to implement without widespread use
of flow control devices (phase shifters and/or FACTS), the actual flows seldom,
if ever, fully comply with the contracted electric paths. In response to this
situation, NERC has been developing a so-called flow- based transmission service
reservation methodology, which recognizes this reality and attempts to maintain
the principle of open access. Excerpts from NERC report: "Transmission
Reservation and Scheduling", December 12, 1996, are provided below in
subsections 6.1.3.1 through 6.1.3.5, to explain the key elements of this
initiative.
6.1.3.1 "Key Elements of the Flow-Based Transmission Service Reservation
Methodology
The Flow-Based Transmission Service Reservation Methodology (PLOBAT) makes use
of two very familiar elements (sources and sinks), one somewhat familiar element
(power transfer distribution factors), and a new element (flowgates). The terms
sources and sinks have been used for some time to describe in concise network
language the locations where power is injected and extracted from the electrical
grid. Their use and meaning is exactly the same in FLOBAT. A source is the
location where electric power is produced by a generator and injected into the
transmission network. A sink is the location where electric power is extracted
from the transmission network and consumed by a load. Power flows on the
interconnected transmission network from the set of all sources to the set of
all sinks. On an incremental basis, a load reduction could function as a source,
and a generation reduction could function as a sink.
6.1.3.2 Power Transfer Distribution Factors
Power transfer distribution factors (PTDFs) have been in use for many years to
predict distributed flow effects on interconnected electric power networks.
Fundamentally, a PTDF describes the proportion of power which will flow on the
facility or subset of facilities for which it was derived due to a power
transfer on the transmission network from a source to a sink. PTDFs are
numerical values derived from the impedance characteristics of components in the
interconnected electrical network using the laws of physics. They remain
essentially unchanged unless the physical network is reconfigured by such events
as transmission element outages and transformer tap changes. Even then, such
changes usually only have a minimal effect on PTDFs for more distant facilities.
Since FLOBAT is proposed primarily as a transmission reservation methodology,
the PTDFs are calculated for the normal planned interconnected network
configuration. (Transmission reliability margins (TRMs) may be used to account
for significant effects of local network variations encountered during
operation.) The period when transmission service is being reserved may be
anywhere from hours and days to months and years in advance of the actual
operation. Although the interconnected transmission network will remain largely
unchanged for these future periods, new construction additions, upgraded
facilities, and major long-term maintenance outages will warrant periodic
updates. PTDF predictions of power flows, even based on a slightly out-of-date
network calculation, are likely to be much more accurate than the current
contract path methodology.
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6.1.3.3 The Flowgate Concept
The new element proposed for the FLOBAT method is the flowgate. Flowgates are
designated as proxies for power flows, transmission service usage, and
transmission constraints on subsets of the interconnected electric power
network. Flowgates mark the locations in the grid where electric power transfer
capability may be defined, offered, reserved, scheduled, and utilized. They are
most likely to be located astride 1) known constraining transmission facilities,
2) transmission interfaces with adjoining systems, and/or 3) other subsets of
facilities not otherwise represented, which are useful for commercial or
modeling purposes. Each flowgate has a set of PTDFs calculated to predict the
direction-specific impact from all commercially significant source/sink pairs in
the Interconnection.
6.1.3.4 Transfer Capabilities Based on Flowgates
Each flowgate has a definable Flowgate Transfer Capability (FTC). The PTC is
analogous to the Total Transfer Capability (TTC) currently being applied to
defined interfaces or groups of transmission elements. The FTC is fundamentally
determined by local subset transfer conditions. Thermal, voltage, and stability
limits are all locally reflected in setting FTC. (Transfer capabilities in other
areas and systems are accounted for by flowgates and PTDFs pertinent to those
other subsets of facilities. Transmission providers need only be concerned about
their local facilities as represented by flowgates designed by themselves.
FLOBAT is a decentralized transmission reservation methodology only. Operation
of the interconnected grid is likely to become more centralized and will be more
effective with the transmission service reservation information developed by
PLOBAT.)
The reservation commitments at each flowgate are accurately predicted by
considering all standing transmission reservations and applying the relevant
PTDFs. Thus, the Flowgate Available Transfer Capability (FATC) is decremented by
the flowgate reservation commitments. The FATC for each flowgate is posted on
the OASIS for transmission customers' consideration.
It is recognized that different TTC and ATC calculation methods exist among
transmission providers and reliability Regions. In Interconnections where the
PLOBAT method is applied, the flowgate transmission reservation approach would
require that the TTCs and ATCs calculated using a network approach (network TTCs
and ATCs) be translated into an interface or flowgate based TTCs and ATCs.
Various methods exist to allow easy translation of network TTCs to flowgate
TTCs. Subtracting the amount of TRM, CBM, and committed flowgate transmission
service yields the flowgate ATC.
6.1.3.5 Transmission Service Reservations Based on Flowgates
Under FLOBAT, a reservation of flowgate ATC is required if a proposed set of
power transfers has a "significant affect" on the flowgate. A flowgate is
considered "significantly affected" if either 1) the associated PTDP exceeds the
established 0.03 minimum threshold, or 2) the associated flow predicted for the
set of transfers exceeds the established 5% minimum percentage of the FTC.
Either condition triggers the "significantly affected" criteria. The amount of
transfer capability that must be reserved at each "significantly affected"
flowgate is determined by summing the products of the contemplated source-sink
transfers and their relevant PTDFs in each time interval."
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6.2 BIDDING FUNCTION
This section addresses the bidding function for trading, supply, or procurement
of energy products and, where relevant, ancillary services. The trading of
transmission capacity is usually carried out using the OASIS as described in
Section 6.3.
Depending on the organizational structure and responsibilities of the ISO and
the Power and Energy Market, the bidding function may serve as a means to either
match bids (bilateral arrangements) or establish a market clearing price (pool
structure).
The market rules for bid matching are generally simpler than those for market
clearing. The supplier bids a quantity and minimum price below which it will not
sell. The buyer bids a quantity and a maximum price above which it will not buy.
The bidding function in this case provides a mechanism to match individual
offers from the providers of energy or transmission support services to those
bidding to purchase them. The price is established individually for each
supply-demand pair. A number of products and tools are available on the market
from large and emerging small vendors which facilitate bid matching.
The market rules in the case of pool operation are generally more stringent and
the process is more complicated. The bid structure may be simple as described
above for bid matching, or it may involve multiple parts and attributes.
Generally a single market clearing price is established that applies to all
sellers and buyers. The market clearing price may be established at
predetermined regular time intervals or on a continuous basis. In most
structures emerging in the U.S. market clearing prices are to be established at
regular time intervals. The following subsections describe typical functional
requirement to support such a bidding environment for power and energy.
One of the greatest challenges bidding software design must conquer concerns the
uncertainties resulting from communication network behavior and human behavior.
These uncertainties pervade an operating arena where time is of the essence
persistently. Furthermore, after the fact it must be possible to reconstruct
events surrounding system anomalies and to show unambiguously that the anomalous
event in question did, in fact, produce the originally observed results. Energy
trading involves such a high volume of funds created and depleted over such
extremely short time periods, that the ability to positively verify the cause of
errors is a crucial element of the entire bidding process.
6.2.1 BidSubmittal
Bidding packages typically provide a range of methods for participants to submit
bids. A participant generally chooses a method most suitable to the
participant's size, location, and budget, as the participant's primary means of
trading. A different method is then adopted for use (usually bidding by fax)
during the periods that the primary means of trading is unavailable. The
following bidding methods are typical:
- Computer file submittal
- Computer Bulletin Board or WEB site
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- Fax (or Phone)
This flexibility provides backup capability for the participants. For example,
if a participant who normally submits bids by computer file suffers a site
disaster, the participant can fall back to bidding by fax, even over a cellular
system.
Exhibit 6-6 illustrates how the various bidding methods are integrated into a
flexible bidding function.
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6.2.2 Bid Collection and Revision
All of the existing bid strategies call for biding in a cyclic manner. Of
course, there are various flavors of the basic cyclic approach such as:
1. Participants submit a bid for the day and later submits a
revised bid if the original bid was rejected. The bid may also
be revised hourly based on the day's actual operating
experience.
2. Participants submit bids repeatedly as the participant watches
changes in the energy market. With this strategy there is
usually a cut off time. Also, hourly revisions may be
provided.
The cyclic nature of these strategies requires the bidding module to:
1. Institute an identification system designed to ensure that the
bidding function can always distinguish a new bid from a
revised bid, and can group bids together to support such
options as hourly updates.
2. Keep precise and detailed records of bid transitions through
the system.
3. Communicate with participants regarding errors, the progress
of the process, schedules, consistency exceptions, etc.
These requirements are not influenced by any particular bidding strategy. The
bidding method, on the other hand, strongly influences the design of bid
collection. Influences are exerted in the following ways:
1. The medium (passive server, error checking, frequency of
receipt, storage).
2. The size of the market in terms of participants.
3. Geographical distribution of participants.
6.2.2.1 Bidding by Computer Link
There are many ways to provide bid submittal by computer-to-computer link. Some
of the methods include:
1. File transfer via FTP over a Wide Area Network (WAN).
2. Having the ISO/PX provide the capability to act as a file
server for participants..
3. Providing switched phone lines for participants to use to
legacy file transfer protocols such as ZMODEM, etc. This is
particularly useful for small systems having access only to
traditional analog phone services.
The first method (file transfer by FTP) provides the best flexibility for
participants of all kinds. This method gives the participant a wide-ranging
choice in the selection, of software tools. It also allows the
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participant to choose to make the connection using a dedicated or switched
communication circuit. It also supports access over either a private network or
the Internet.
Method 2 generally requires that the Participant maintain a dedicated phone
line. However, this method supports full integration of ffle transfers with
desktop office tools. For example, a spreadsheet that links to a client database
could be copied (or saved) to the ISO/PX, and this copy would serve as the
participant's bid. Any application that can access any file can access the bid
file on the ISO/PX. This allows very powerful bid programs to be developed at
extremely low cost.
Method 3 supports rapid deployment of the bidding function in an environment
where existing infrastructure must be retained, and that infrastructure has been
supporting file transfers among desktop computers, and between desktop computers
and on-line services.
6.2.2.2 Bidding by Bulletin Board
Bidding by bulletin board provides the participant with an interactive
capability to create new bids, and update existing bids. For the participant,
this method of bidding appears much like working with bid information locally at
the ISO/PX facility. The participant actually works with a copy of the forms
that exist in the ISO/PX database rather than having direct access to the
database itself.
Using the bulletin board, the participant has the following bid edit
capabilities:
1. Add new bids
2. Edit existing bids that apply to future time periods
3. Delete existing bids that apply to future time periods
4. Copy prior bids so that they can be modified to create new bids.
One of the significant advantages to preparing bidding information this way is
that the computer interacts with the participant as the bid is being prepared.
Help files answer questions and invalid field entries are made known to the
participant as they occur. This bidding method is particularly suitable to
advanced training. However, filling in forms manually is a time-consuming effort
and will be found impractical in many organizations,
6.2.2.3 Bidding by Fax
In almost all market systems, the bidding strategy includes the capability for
participants to submit bids by fax. Phone bidding has also been seen but it is
for very small systems and would be used for backup purposes also.
There are several ways that faxes are being processed. Some involve having
operators read submitted bids and enter the data into the system. Others take a
fax directly into a desktop computer and convert the image to text. Naturally,
bidding by fax is restricted to backup use only because of the intense labor
required to process it.
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6.2.3 Bid Validation
For each of the methods of bid submittal, the bidding function must verify the
current qualification status of a participant before the participant's bid is
subject to any subsequent processing. For example, the participant status must
be examined to ensure the participant's eligibility to bid.
If the information maintained in the system database includes technical
information about the resources identified in a participant's bid, the bid must
be checked against the technical information. This check will ensure that the
bid parameters are consistent and within the boundaries of the technical
capabilities of the resource bid. All inconsistent data must be identified in
the form of a transmittal to the participant, and the participant must be
notified accordingly. If a notification is generated for a participant who is
logged into the BBS, the participant must be notified interactively via the BBS.
6.2.4 Private Participant Data
The bidding function processes private data. In particular, the following
information is deemed as private:
1. All information received from a participant
2. All notifications and confirmations transmitted to a participant.
The bidding function must ensure that all private information is safeguarded
from public view. It must not by error, omission, or other reason, allow private
information to enter the public domain.
6.3 PUBLIC INFORMATION SYSTEM
The Public Information System must facilitate posting of information for
comparable access by the market participants. The Open Access Same-time
Information System (OASIS) is an example. It is used to post network data
pertinent to transmission reservation. This includes information regarding
forecasted network conditions. Available Transmission Capacity, ancillary
service requirements, curtailments and interruptions, etc.
Depending on the structure adopted, the OASIS facilities or an entirely separate
system may be used for posting the Power and Energy Market public information.
This includes load forecasts, market clearing prices, congestion mitigation
prices, etc.
6.3.1 OASIS
The specific architectural, communications, and posting requirements of OASIS
are specified in PERC Order 889, dated April 24, 1996 and are not restated here.
The purpose of this subsection is to provide an overview of the current
implementation status of OASIS in the U.S.
The OASIS, now in operation since the beginning of 1997, started as a concept
discussed and developed during FERC's July 27, 1995 Technical Conference on
Real-Time Information Networks. The system was developed in a two pronged
approach, through a "what" activity, sponsored and
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coordinated by NERC, and "how" activity sponsored and coordinated by EPRI,
through several "strawman" implementations, and through a wide industry
participation.
Implementation of OASIS is currently foreseen in two phases. The Phase 1 system
was developed and made operational in 1996. It is currently implemented at a
number of sites. The following excerpts from the minutes of a recent OASIS
Workshop (New Orleans; March 3-4, 1997) provides a brief summary of the status
of OASIS in Phase 1:
1. Pacificorp
- OASIS node was developed internally
- Operational since 1/3/97
- System is somewhat active - over 7000 reservations to date -
most from Pacificorp (95%) - over 200-300 hits per day, but
still use telephone
- Database access times seem reasonable - "simple" queries
complete within one second
- Post hourly, daily, weekly, and monthly
- Schedules are updated hourly
- Ancillary services posted per FERC 889
2. Salt River Project - SWOASIS
- Implemented: Postings, transaction process, ancillary
services (not used), want ads, secondary postings
reassignments (used extensively), curtailments (not really
used).
- 208 paths (from 4 to 82 paths per provider), 2000 requests
(10 re-sales. 70% business is affiliate), no ancillary
services being sold
3. NYPP
- TTC is calculated on a seasonal basis. ATC upon reservation.
4. PJM
- About 600 Registered Users, now about 2000 hits per day, with
about 100 user sessions and 500 transactions per week
- OASIS backend function - can load 8000 ATC records in about 30
seconds
5. ECAR
- Have 1031 registered users (255 providers and 776 customers),
559 posted paths, 253 different service types (193
transmission and 60 ancillary services), 31 average database
user connections, about 3 million entries in the audit log.
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- ECAR has tremendous traffic, being in the middle of the
country.
6. CP&L on VACAR node (which supports 7 providers)
- Share operation and maintenance with NEPOOL - Has handled 3800
requests to date.
7. MAIN
- 67,000 hits per week, 500 Mbytes of data requests, 4.6 million
entries of various ATC and TTC values for 850 paths from 11
providers, over 18,000 transmission service requests have been
processed
- Daily ATC and TTC calculations, but are planning eventually to
calculate these 4 times a day
- Have achieved 98.996% availability (10 hours down total; 8
hours with loss of Internet access). So are evaluating having
a second Internet access link.
- One third party vendor is responsible for 50% to 75% of hits,
by asking for information every 4 seconds.
8. MAPP
- OASIS node for all MAPP members, started in November 1996.
Have growth in number of providers.
- Now have 23 providers, and also have the regional provider.
- Have an automated process using a load flow to analyze
requests for ATC.
9. Southern Company
- Developed in-house - Operational since Jan 3
- No real performance problems: just two software problems
caused a I'/i hour outage. Some customers have had problems
accessing the node.
- Frequent ATC calculations are automated on a Sun system, but
don't have any performance problems
- Southern is the only node which is taking ancillary service
requests through OASIS. Waiting for the industry to determine
if this is really how ancillary services should be handled.
- Most business is next hour business, which is done on the
OASIS.
- About 60 registered customers, of whom 15 are active. Hundreds
of thousands of hits, mostly from Southern schedulers.
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OASIS Phase 2 will incorporate transmission reservations and MWh scheduling
using either point to point or "PLOBAT" methodology (see Section 6.3.1).
6.3.2 Requirements for the Power Market Publishing Function
In this subsections, a typical set of functional requirements for a publishing
function to support the Power and Energy Market are stated. The publishing
function used to support the Power and Energy Market may use OASIS, the Bidding
function facilities, or a separate function.
The publishing function provides participants access to public information that
will be needed by the participants to make bidding decisions. Comparability of
access to public information is essential. The publishing functionality
generally requires a World Wide Web Server and a Web Agent as illustrated in
Exhibit 6-7. The Web Server should be a standard web server product to
facilitate its use by the public without requiring specialized software.
6.3.2.1 Webserver
The Web Server is to provide an Internet (and where relevant, private network)
interface for information requests by participants. This server should provide
all display and download capabilities required to provide public information to
participants in graphical or file transfer format as needed.
Although the information maintained in the publishing system is labeled as
public information, participation may be confined to qualified participants.
Therefore, anonymous login to the Web Server may have to be prevented.
The Web Server should provide a firewall for implementing Internet security to
protect the server and the ISO/PX systems from security threats from both the
public Internet and the private network users. Access to the system computing
facilities must be strictly limited to the Web Server itself, while still
providing access to public market information in the Web Server to any
authorized participant via the public Internet or the private network.
6.3.2.2 Web Agent
The Web Agent is to provide applications to respond to requests received from
the Web Server. The Web Agent should also provide participant information to the
database files to support the Web Server's participant verification
requirements.
6.3.2.3 Navigation
The Web Server is to provide the HTTP protocol for standard web access. The
purpose of this capability is to permit the use of either standard web browsers
or participant-developed programmatic browsers to view and download data.
Provisions for a home page should be provided using HTML. Hotlinks should be
provided on the home page to support both graphical and textual information
display and file downloads. Other pages should provide hotlinks to return to the
home page.
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6.3.2.4 File Transfer
The Web Server is to provide the FTP protocol for file download access. Hotlinks
on the information pages should be provided to access the FTP capability. Public
directories and files should be shown. The files should be selectable by the
participant, and download initiated by command button selection.
6.3.2.5 Web Server Maintenance
It should be possible to add, modify, and delete HTML pages, including the home
page, using standard HTML editing tools. These editing tools should be provided
with the Web Server functionality. In addition to the HTML editing tools, Web
Server maintenance tools should be provided to support participant login account
management, and Web Server configuration management.
6.4 ENERGY METERING
In the restructured environment the price of energy is established on a much
shorter time increment than in the past (usually hourly). All settlement and
billing should generally take place based on hourly prices. However, this would
require hourly meter reading. Deployment of such a capability is not conceivable
in a short time period. In fact, in most emerging structures this capability is
foreseen only for the large consumers. In many cases, hourly revenue metering
capability is not available even at the interface between the transmission
company and the distribution companies resulting from functional unbundling of
the vertically integrated utilities; its implementation may require a long time
and entail major costs. In many situations "load profiling" is adopted, whereby
pre-defined hourly load patterns are used to partition the energy consumption
over a longer period into hourly quantities.
At the retail level, the consumers may in principle have the choice of having an
hourly meter, be billed based on load profiling, or agree upon a flat rate,
which would generally be higher since the supplier or the distribution company
would take the price fluctuation risk.
Some argue that a customer must have a time-of-use meter in order to take
advantage of direct access opportunities. But the majority of energy providers,
customers and utilities maintain that load profiles could be used to determine
the billing patterns for customers that do not have time-differentiated metering
capability.
Another controversy centers on the provision of services and costs related to
metering, billing and other information services. These are sometimes referred
to as Revenue Cycle Costs. Some say that these costs should be included in the
bundled charge for distribution services. Others argue that these costs should
be separately identified to allow some customers to elect not to buy these
services from the distribution company.
Many energy suppliers see an opportunity to add value to the products they sell
if they can bill the customer directly and if they can offer a meter or metering
communication service that provides the opportunity to exchange information and
offer products in addition to retail electric service.
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The question is whether or not energy suppliers should be allowed to provide
their customers with retail services that include consolidated billing, metering
and related services and, if so, whether the distribution utility should reduce
its charges to reflect any resulting savings.
A specific model proposed is to allow suppliers to choose among three billing
options:
1. Consolidated Supplier Billing - under which the distribution
company would bill the energy supplier for the services
provided directly by the distribution company to the customer
and the supplier in turn would provide a consolidated bill to
the customer,
2. Consolidated Distribution Company Billing - under which
distribution company would place the supplier's energy charge
on a distribution bill, or
3. Dual Billing - under which the energy supplier and the
distribution company would bill separately for their own
services.
In either event, certain conditions would apply:.
First, only one meter would be needed at each point of service connection.
Second, only one entity would read the meter. The energy supplier and the
distribution company would share data-base level information about usage. Third,
the entities should cooperate in the development of open architecture, or
interoperability standards, which would allow meters with varying levels of
functionality to connect to the network communications and data infrastructures.
Finally, the use of load profiling (i.e., the use of template load shapes) to
provide direct access for residential customers that do not have an hourly
meter.
6.5 SETTLEMENT AND BILLING
Depending on the underlying market structure, there may be single or multiple
settlement cycles. In multiple settlement processes, contractual commitments
resulting from different temporal markets (e.g., day-ahead, hour-ahead, and
real-time) will have to be settled separately. This does not necessarily mean
that there will be separate billing for each market. A single bill may be
produced for the net amount of contractual commitments and deviations over a
billing cycle. In that case the bill will have to be supported by settlement
statements for each market.
The Settlements process involves collection of information regarding schedules
(day-ahead and hour- ahead commitments, if relevant), market clearing prices and
metering as required in order to: execute contract and real-time settlements;
provide a preliminary settlement run for validation of the results by
participants; provide a final settlement addressing any disputes by
participants, and establish the transfer of funds due.
A possible timeline for the settlement process is illustrated in Exhibit 6-8. A
period between the settlement day and the preliminary settlement will allow time
for metering information from the many different sources to be collected, made
"settlement ready," and transferred to the Settlements function. Market clearing
prices, energy management system records, and other information also will be
captured during this period.
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Once this information has been collected, the preliminary settlement run may be
made and statements produced to be sent to the market participants. Market
participants will review their statements and have an opportunity to raise any
disputes concerning the settlements. A period between the preliminary and final
settlements is expected to allow time for resolution of most settlement
disputes. On the last day of the settlement cycle, a final settlement will be
prepared and final statements sent to market participants.
Exhibit 6-8: Settlements Timelines
[GRAPHIC OMITTED]
The cycles for billing and payment may vary by the type of customer and certain
other factors. In some cases, participants may make or receive payments for
individual settlement days. Settlement amounts also may be aggregated and netted
for a billing period (e.g., monthly).
The Settlement function must provide the software applications necessary to
calculate settlement details for each trading participant based on scheduled
commitments, market clearing prices and validated metering information.
Administrative fees, charges for ancillary services capacity, reservations, etc.
must be applied. Energy accounting reports for each trading interval must be
produced. The Settlement function must support necessary security, control and
audit trail requirements, and provide for support of settlement dispute
resolution.
6.5.1 Settlement Calculations
The settlement software must provide the following capabilities:
I. Calculate the credit and debit amounts for both buyers and sellers for
each hourly trading interval for each market as relevant:
A. Day-ahead forward energy, ancillary services, and congestion
commitments
B. Hour-ahead forward energy, ancillary services, and congestion
commitments and deviations
C. Energy imbalances (Loss compensation, replacement energy,
congestion)
D. Ancillary services capacity reservations, and Transmission Access
charges
II. Recalculate settlements based on changed data after final settlement.
III. Maintain data and information on an hourly, basis to support validation
of accounts.
IV. Produce summary billing information for multiple billing cycles as
relevant:
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A. Day-ahead commitments (energy, ancillary services, and
congestion)
B. Hour-ahead commitments and deviations (energy, ancillary
services, and congestion)
C. Real-time Energy Imbalances
D. Ancillary services capacity reservation
E. Congestion charges
P. Transmission Access charges
G. Administrative fees
H. Net debits / credits (funds transfer due)
V. Identify and report on any settlements which cannot be completed because
of incomplete information or other problems.
VI. Track real-time settlements based on estimated meter data and to flag
such settlements as "conditional".
VII. Accommodate transitions to and from Daylight Savings Time.
VIII. Provide for Year 2000 transition.
6.5.2 Security, Control, and Audit Trail
The Settlement function must provide the following security, control and audit
trail capabilities:
1. Provide accurate, time-sequenced, end-to-end traceability of the
settlements processes so that participants may verify their invoiced
amounts.
2. Provide the ability to specify and accept data that is specifically
needed for audit trail requirements such as time and date of bid
submission, and other user specified data.
3. Access to settlement data must be strictly controlled by user
password.
4. Provide archiving.
6.5.3 Billing and Credit Function
The Billing and Credit function will be used to process credit and debit
invoices, prepare and execute payments to market participants, and manage
accounts receivable.
The Billing and Credit function will process summary information produced by the
Settlement function regarding net settlements for different markets such as:
- Day-ahead commitments for energy and ancillary services
- Hour-ahead commitments for energy and ancillary services
- Real-time deviations, including
- Energy balancing
- Ancillary services (capacity and energy)
- Transmission Access charges
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- Congestion charges
- Administrative fees
The settlement results received from the Settlements function may be
consolidated into a single invoice for all settlement days falling within each
billing cycle.
Based on the credit invoice information, payments will be prepared and sent to
participants on a regular cycle. Payments might be made by electronic funds
transfer (EFT) and hardcopy checks. Details of payments to participants should
be posted to the Accounts Receivable and Participant accounts. EFT transactions
may be administered by a third-party banking institution. The Billing and Credit
function must provide the functionality for banking and check reconciliation.
Market participants should have the flexibility to remit their payments through
hardcopy checks and by electronic funds transfer transactions. More than one
bank will likely be used to handle the receiving and recording of participant
payments. The Billing and Credit function should provide for interaction with
the banks' systems so that participant payments are efficiently matched to the
appropriate accounts.
Accounts receivable accounting and participant accounting make up the central
functionality of the billing function. The accounts receivable accounting
process should provide for recording detailed and summary transaction
information including billing debit and credit transactions, credit payment
postings, payment receipt and credit memo postings, and accounts receivable
balances.
Disputes arising from the debit and credit billing process will be addressed and
resolved through a dispute resolution process. Complete audit trail and display
of transaction history at the participant level must be available to support
this process.
6.5.4 Credit and Collections
Credit and collections involves the identification and reporting of late
payments and tools that support collection activities. Summary reporting of aged
receivables will provide an overall view of the performance in managing the
credit and collections process. Collection reports for individual participants
will provide information on contacts, outstanding invoices, aging, and amounts.
This process also includes the application of finance charges to accounts and
automated preparation of dunning notices and collection letters.
6.6 CALIFORNIA'S EXPERIENCE
In California the business processes for bidding, publishing, metering,
settlement, and billing are somewhat more complicated than other emerging
structures in the U.S. The PX must interact with the PX participants for bidding
on energy and ancillary services. The PX must also interact with the ISO as any
other Scheduling Coordinator. The PX will forward ancillary service bids to the
ISO, and will have the option of using ancillary services bid into the PX for
self provision. In case of congestion, the PX will interact with the ISO on
behalf of its participants, and may also have direct interaction with the
participants before responding to ISO's schedule change recommendations for
congestion mitigation. There are three concurrent settlement processes for each
billing cycle, namely, settlements for the day-
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ahead commitments, hour-ahead changes, and real-time deviations. The PX must
settle on the one hand with the ISO and on the other hand with the PX
participants.
An extensive communications infrastructure is being implemented in California so
that every market participant can have access to a point of presence (POP) on
the communications backbone system within a 50 mile radius. The backbone
communications bandwidth is very high (OC3) to accommodate the large
communications traffic anticipated based on a large number of potential
participants.
The California regulatory bodies require that the California ISO and the Power
Exchange, along with their communications infrastructure, basic technical
support hardware/software, and business systems be made operational by January
1, 1998. California has adopted a phased approach to the implementation of
various features and functions of the technical and business systems. The
infrastructure will be in place by January 1, 1998. However, some of the
features required from the technical and business systems are delayed until
mid-1998.
Regarding the metering options, the California Energy Commission supports the
unbundling of Revenue Cycle Costs and Services. However, it would require the
utilities to separately identify the costs for the various components of Revenue
Cycle Services initially, and would allow firms other than the distribution
utility to compete for the provision of these services only at some later date.
The distribution utilities would be required to facilitate three billing
options: Consolidated Energy Supplier Billing, Consolidated Distribution Company
Billing, and Dual Billing.
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7. RESUME OF THE AUTHORS
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DARIUSH SHIRMOHAMMADI, Ph.D.
Perot System Corporation
WORK EXPERIENCE
1996 - Present Associate, Perot Systems Corporation. Dallas, Texas.
Developing and implementing information systems (procedures,
protocols, infrastructures, systems and applications) to
assist with the deregulation of the utility industry.
1995 - 1996 President and Principal Consultant, Shir Power Engineering
Consultants, Inc.. San Ramon, California. Consulting on
technical aspects of utility industry restructuring (PX/ISO
formations and operation, transmission costing and pricing),
on automation technologies (DA/SCADA, AMR, communications and
operations decision support systems), and on analysis,
modeling and optimization of transmission and distribution
systems.
1991 - 1995 Director (final position). Energy Systems Automation Group.
Pacific Gas and Electric Company (PG&E). San Francisco,
California. Developing, implementing and integrating
state-of-the-art computer, communications and automatic
equipment technologies for the automation of PG&E's energy
services including DA, SCADA and AMR systems.
1985 - 1991 Senior Systems Engineer, Systems Engineering Group, PG&E.
Developing and implementing advanced computational
methodologies and tools to analyze, optimize, cost, price,
plan and operate transmission and distribution systems.
1982 - 1985 Transmission Planning Engineer, Ontario Hydro. Toronto,
Canada. Analyzing electromagnetic transients for planning and
design of Ontario Hydro's transmission system; responsible for
the development of the EMTP application.
1977 - 1979 Research Assistant, Hydro Quebec Institute of Research (IREO).
Montreal, Canada. Studying electrical discharges in air,
insulation of high voltage systems and field calculation
techniques.
EDUCATION
1982
1978
1975
Ph.D.. (Electric Power Engineering), University of Toronto
M.S. (Electric Power Engineering), University of Toronto
B.S. (Electrical Engineering), Sharif University of Technology
MAJOR PROJECTS. RESPONSIBILITIES AND ACCOMPLISHMENTS
Technical Aspects of Utility Industry Restructuring - Transmission Access and
Wheeling:
- Technical project leader for the development of the California's
Independent System Operator (ISO) information system infrastructure and
applications; 1997
- Principal investigator for a joint EPRI/EDF project to define and specify
the analysis tools required for the emerging energy market structures;
1996.
- Principal investigator for a joint EPRI/EDF project to define and specify a
transmission dispatch and congestion management system for the operation of
emerging energy market structures; 1996.
- Developed strategies for metering and settlement of unbundled utility
services including the "Ancillary Services" for EPRI; 1996.
- Developed transmission pricing methodologies for Ontario Hydro and BC
Hydro; 1995-ongoing.
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- Participating in the utility industry restructuring deliberations in
California and the US through involvement in California's WEPEX and FERC's
Mega-NOPR activities; 1995-ongoing.
- Developed paradigms, methodologies and computer models for competitive
resource acquisition process for PG&E; 1989-91.
- Developed paradigms, methodologies and computer models for evaluating
transmission access requirements and costing and pricing transmission
services for PG&E; 1986-95.
- Presented and advocated paradigms, methodologies and computer models for
evaluating transmission access requirements and costing and pricing
transmission services in technical and regulatory arenas at state, national
and international levels; 1987-96.
- Participated in the preparation of filings and testimonies on the technical
aspects of transmission access issues for various regulatory proceedings;
1988-91.
- Participated, as a technical expert, in negotiations on transmission and
power purchase contracts between PG&E and Independent Power Producers;
1988-90.
Automation Technologies:
- Developed applications and marketing strategies for PG&E's WinSCADA
software; 1995-1996.
- Directed a company wide effort at PG&E to develop the complete
functionality for PG&E's SCADA systems including the requirements for the
master station, telecommunication link, remote terminal units, data access
models and economic evaluation; 1994-95.
- Directed the roll-out of an operations decision support system for PG&E's
DA system in Santa Rosa; 1994-95.
- Directed the technical/economic aspects of a DA roll-out project for PG&E
in Santa Cruz; 1994-95.
- Participated in the development of PG&E's current AMR strategy and
technology implementations plans; 1994-95.
- Participated in the development of an AMR roll-out plan for PG&E's San
Francisco Peninsula, 1994- 95.
- Directed PG&E's efforts to manage DA implementation cost via partnership
with DA technology vendors and streamlining of the SCADA evaluation and
implementation processes; 1993-95.
- Performed the complete economic evaluation study for PG&E's $10M project to
roll out a CellNet based DA system in Silicon Valley, California; 1992-93.
- Designed and lead the implementation of a data access scheme for making
real-time SCADA data available on PG&E's LAN/WAN Computers; 1992-93.
- Managed a major research project at PG&E with participation at technical
level on the development and deployment of distribution operations decision
support systems; 1992-96.
- Developed planning support tools for PG&E's distribution systems;
1986-1992.
Power System Planning and Operations (including Electromagnetic Transient
Studies):
- Studied Transient Recovery Voltages (TRVs) for the oil circuit breakers
(OCBs) at one of PG&E's 115 kV substation at Sacramento; 1996.
- Studied capacitor switching transients at one of PG&E's 115 kV substation
at Sacramento; 1996.
- Provided consulting to several engineering consulting firms on various
Electromagnetic Transients studies particularly on the impact of capacitor
switchings on industrial plant operations including solid state motor
drives; 1985-ongoing.
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- Performed transmission planning studies both in systems and
transients/control areas for Ontario Hydro and PG&E; 1982-95.
- Conducted power system studies using power flow, reliability evaluation,
transient stability models and the Electromagnetic Transients Program
(EMTP) for Ontario Hydro and PG&E; 1982-89.
- Provided consulting to transmission and distribution planners on the use of
advanced planning and operations computer models; 1985-95.
Computer Applications, Systems and Services:
- Designed and implemented general computer architecture including hardware
platforms, operating systems, networking scheme, gateways and applications
for specific work functions.
- Evaluated and selected commercial computer models for transmission system
planning and operations.
- Designed and provided consulting in the deployment of relational databases
for transmission line and power flow data.
- Conducted negotiations on software contracts with several software vendors.
- Developed numerous advanced analytical methodologies and computer
applications for the analysis, optimization, costing and pricing of large
scale transmission and distribution systems:
- LOCATION: Evaluation of the incremental transmission costs of new
resources.
- MAXFLOW: Evaluation of the transmission network maximum use for
firm transactions
- MW-MILE: Transmission pricing based the evaluation of
transmission network capacity use for wheeling
transactions
- VCMARGIN: Evaluation of voltage collapse operating margins
- SILCON/DYSCREEN: Static and dynamic contingency screening for
transmission networks
- RADIAS: Real-time application for distribution automation
systems including distribution power flow analysis,
distribution state estimation, distribution feeder
reconfiguration, distribution feeder voltage and VAR
control, distribution short circuit analysis, and
intelligent load management
- PICKUP/DISTOP: Distribution system service restoration and optimization
- TLPARM: Transmission line parameter calculation
- TUNES: Transmission lines electromagnetic field (EMF) effect
calculation
- EMTP: Electromagnetic Transients Program's enhancement by
adding the induction machine model, an MOV arrester
model and the machine shaft fatigue analysis model
SAMPLE INDUSTRY ACTIVITIES
1997 Chair, 1997 IEEE Winter Power Meeting Panel Session, New York
Topic: Technical Issues Related to ATC Evaluation
1997 Panelist: 1997 IEEE Winter Power Meeting Panel Session, New
York Topic: ISO/Congestion Management Using OFF
1996 Panelist, 1996 IEEE Summer Power Meeting, Denver Topici:
Technical Issues Related to the Independent System Operator
TopicZ: Ancillary Services in Deregulated Markets
1996 Invited Speaker, Light Power Company, Rio de Janeiro, Brazil,
and Ontario Hydro, Toronto, Canada Topic: A Tutorial on
Distribution Automation
1996 Invited Speaker, Ontario Hydro, Toronto, Canada
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Topic: Electric Utility Industry Restructuring: Institutional,
Engineering and Economic Issues
1995 Invited Speaker, National Kaohsiung Institute of Technology,
Taiwan Topic: Telecommunication Technologies for Distribution
Automation Systems
1995 Panelist, 1995 IEEE Power Meeting, Portland Topic:
Distribution Automation: Survey of Recent Advances
1991 - 1992 Panelist, 1991 and 1992 IEEE Power Meetings, San Diego
and New York Topic: Transmission Impacts Related to Siting
Locations of Non-Utility Generation
1990 Invited Speaker, IEEE Power Engineering Society, San Francisco
& Sacramento Topic 1: Transmission System Capacity Use for
Wheeling Transactions Topic 2: Optimum Reconfiguration of
Electric Distribution Networks
1986 Invited Speaker, IEEE Power Engineering Society, San Francisco
Topic: Corona Phenomenon and Effects
1989 - Present Visiting Faculty, University of Wisconsin (Madison,
Wisconsin), California Polytechnic University (San Luis
Obispo, California), Helsinki Institute of Technology
(Helsinki, Finland) and ABB Power Systems (Ludvika, Sweden).
Topic: Power System Analysis Using the EMTP
1981 - 1985 Visiting Faculty, University of Toronto, Toronto, Canada
Topic: Circuit Analysis for AC Power Transmission Systems
1975 - 1982 Teaching Assistant, University of Toronto and McGill
University, Canada Topics: Several graduate and undergraduate
courses in Mathematics, Physics and Engineering. Also ran the
high voltage and machines laboratories for two semesters.
PROFESSIONAL ASSOCIATIONS
Senior Member of the Institute of the Electrical and Electronics Engineers
(IEEE). Member of task forces and working groups on Distribution Automation,
Transmission Access and Transients Analysis. Professional Engineer in the
Province of Ontario, Canada.
HONORS AND AWARDS
PG&E's Highest Award in Electric Supply, 1993: For the development of the
methodology and computer models for evaluating the incremental transmission cost
of new generating resources. Electric Power Research Institute's Award, 1992:
For the successful application of the Electromagnetic Transients Program to
study of capacitor switching in a major transmission station. PG&E's Highest
Award in Electric Supply, 1989: For the development of the methodology and the
computer model for optimizing distribution system configuration. Academic
Awards, 1972-1982: Received numerous academic awards and scholarships at
undergraduate and graduate levels.
PUBLICATIONS
Technical Aspects of Utility Industry Restructuring - Transmission Access and
Wheeling:
1. "Transmission Dispatch and Congestion Management in the Emerging Market
Structures", will be presented in the 1997 IEEE Summer Power Meeting in
Berlin and published in the IEEE Transaction on Power System.
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2. "Technical Issues, Methods and Tools in Emerging Energy Market
Structures", Electric Power Research Institute (EPRD Report
TR106786. November, 1996.
3. "Transmission Dispatch and Congestion Management System", EPRI
Report TR107571. November, 1996.
4. "An Overview of Ancillary Services", Proceedings of the 5th
Symposium of Specialists in Electric Operational and Expansion
Planning (invited paper), Brazil, May 1996.
5. "Some Fundamental Technical Concepts about Cost Based
Transmission Pricing", IEEE Transactions on Power Systems.
April 1996.
6. "Transmission Pricing: Paradigms and Methodologies",
Proceedings of the 4th Symposium of Specialists in Electric
Operational and Expansion Planning (invited paper), Brazil,
May 1994.
7. "Voltage Collapse Operating Margin Analysis using Sensitivity
Techniques", Proceedings of the Athens Power Technology
Conference. Greece, 1993, pp. 332-336.
8. "Short-Term Economic Energy Management in a Competitive
Utility Environment", IEEE Transactions on Power Systems.
February 1993, pp. 198-206.
9. "An Engineering Perspective of Transmission Access and
Wheeling", Proceedings of the 3rd Symposium of Specialists in
Electric Operational and Expansion Planning (invited paper),
Brazil, May 1992.
10. "Cost of Transmission Transactions: An Introduction", IEEE
Transactions on Power Systems. November 1991, pp. 1546-1560.
11. "Valuation of the Transmission Impact in a Resource Bidding
Process", IEEE Transactions on Power Systems. February 1991,
pp. 316-323.
12. "A Multi-Attribute Evaluation Framework for Electric Resource
Acquisition in California", Electric Power and Energy Systems.
Vol. 13, No. 2, April 1991, pp. 73-80.
13. "Optimal Power Flow Sensitivity Analysis", IEEE Transactions
on Power Systems. Vol. PWRS-6, No. 3, August 1990, pp.
969-976.
14. "Evaluation of Transmission Network Capacity Use for Wheeling
Transactions", IEEE Transactions on Power Systems. Vol.
PWRS-4, No. 4, November 1989, pp. 1405-1413.
Distribution System Analysis and Automation:
1. "Telecommunication Media Technologies for Distribution
Automation Systems", Main feature of the Utility Automation
Journal. November/December 1996.
2. "Transformer and Load Modeling in Short Circuit Analysis for
Distribution Systems", Paper No. 96 SM 567-8 PWRS, to be
published in IEEE Transactions on Power Systems.
3. "Distribution Feeder Reconfiguration for Service Restoration
and Load Balancing", Paper No. 96 SM 488-7 PWRS, to be
published in IEEE Transactions on Power Systems.
4. "Distribution Feeder Reconfiguration for Cost Reduction",
Paper No. 96 SM 512-4 PWRS, to be published in IEEE
Transactions on Power Systems.
5. "An Integrated Real-Time Analysis Tool for Distribution
Automation Systems", Computer Applications in Power. April
1996.
6. "Estimation of Switch Statuses for Radial Power Distribution
Systems", Proceedings of the IEEE International Symposium on
Circuits and Systems. Seattle, 1995.
7. "A Distribution Short Circuit Analysis Approach Using a Hybrid
Compensation Method", IEEE Paper 95 WM 221-2 PWRS. to be
published in IEEE Transactions on Power Systems.
8. "A Three-Phase Power Flow Method for Real-Time Distribution
System Analysis", IEEE Paper 94 SM 603-1 PWRS. to be published
in IEEE Transactions on Power Systems.
9. "Service Restoration in Distribution Networks Via Network
Reconfiguration", IEEE Transactions on Power Delivery. April
1992, pp. 952-958.
10. "Reconfiguration of Electric Distribution Networks for
Resistive Line Losses Reduction", IEEE Transactions on Power
Delivery. Vol. PD-4, No. 2, April 1989,-pp. 1492-1498.
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11. "A Compensation-Based Power Flow Method for Weakly Meshed
Distribution and Transmission Networks", IEEE Transactions on
Power Systems. Vol. PWRS-3, May 1988, pp. 753-762.
Electromagnetic Transients Analysis:
1. "Modelling Guidelines for Slow Transients: Part in
Perroresonance", Task Force paper to be submitted to the IEEE
Transactions on Power Delivery.
2. "Modelling Guidelines for Slow Transients: Part II Controller
Interactions; Harmonics Interactions" IEEE Paper 96 WM 091-9
PWRD. Task Force paper to be published in IEEE Transactions on
Power Delivery.
3. "Modelling Guidelines for Slow Transients: Part I Torsional
Oscillations, Transient Torques, Turbine Blade Vibrations and
Fast Bus Transfer" IEEE Paper 95 WM 247-7 PWRD. Task Force
paper to be published in IEEE Transactions on Power Delivery.
4. "Induction Machine Modelling for Electromagnetic Transient
Program", IEEE Transactions on Rotating Machinery. Vol. EC-2,
December 1987, pp. 615-621.
5. "Improved Evaluation of Carson Correction Terms for Impedance
Calculations", Proceedings of the Canadian Electrical
Association Transaction on Power System Planning and
Operation. April 1985. Also EMTP Newsletter. Vol. 5, No. 2,
April 1985, pp. 28-39.
6. "Universal Machine Modelling in EMTP". Proceedings of the
Canadian Electrical Association Transactions on Power System
Planning and Operation. April 1985. Also EMTP Newsletter, Vol.
5, No. 2, April 1985, pp. 5-28.
7. "Synchronous Machine Modelling in EMTP", EMTP Newsletter. Vol.
4, No. 4, August 1984, pp. 7- 16.
8. "Infinite Phase Order Modelling of Multi-Phase Transmission
Lines", Canadian Electrical Engineering Journal. Vol. 9, No.
2, April 1984, pp. 55-62.
9. "Modelling Zinc Oxide Arresters in EMTP", EMTP Newsletter.
Vol. 4, No. 3, February 1984, pp. 18-29.
10. "Calculation of Induction and Magnetic Field Effects of Three
Phase Overhead Lines above Homogeneous Earth", IEEE
Transactions on Power Apparatus and System. Vol. PAS-101,
August 1982, pp. 2747- 2754.
High Voltage Engineering:
1. "Practical Application of Conductive Barriers to Field
Controlled Air Gaps", IEEE Transactions on Power Delivery.
Vol. PWRD-1, April 1986, pp. 169-181.
2. "Field Optimization of Nonuniform Field Gaps", IEEE
Transactions on Power Apparatus and System. Vol. PAS-104,
March 1985, pp. 718-726.
3. "Some Observations on the Positive Impulse Breakdown of
Reduced Point-to-Plane Air Gaps", Paper 42.01, Proceedings of
the 4th International Symposium on High Voltage Engineering.
Greece. 1983.
4. "Conductive Barrier: A Measure to Improve the Dielectric
Strength of Air Gaps", Ph.D. Dissertation, University of
Toronto, 1982.
5. "Growth of a Positive Leader in Long Nonuniform Air Gaps",
Journal of Applied Physics. July 1978, pp. 3804-3806. "Impulse
Voltage Behavior of Reduced Scale Air Gaps", M.S. Thesis.
University of Toronto, 1978.
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KEMA Consulting
KEMA-ECC & Macro Corporate
A. FARROKH RAHIMI, Ph.D.
Senior Principal Consultant
KEMA Consulting
Professional Experience
27 Years in Power System Analysis, Planning, and Operation
31 Years in Overall Energy and Control Systems
Highlights of Experience
A KEMA Consulting/Macro Corporation employee since 1989, Dr. Farrokh Rahimi is a
Senior Project Manager who specializes in planning power systems' futures. His
years of experience encompass all aspects of electric utility automation and
control, and he is a recognized industry expert in transmission open access
issues, industry restructuring, security assessment and network analysis
applications for power control centers.
Dr. Rahimi most recently has been the project manager for the California Power
Exchange (PX) Systems and the California ISO Business Systems, leading a team of
consultants from Macro/KEMA- ECC and Coopers & Lybrand. He is also a project
consultant to MAPP to assist in upgrading MAPP's security center system and to
develop a strategic plan for implementing ISO functions and other operations
requirements to meet the new reorganization plans of the pool and reliability
council. He has also conducted studies for several large electric utilities in
Europe, investigating the impacts of alternate electric industry structures and
transmission open access on power system planning and operation. These studies
provided guidelines for energy contract management, optimal resource scheduling,
pricing strategies, and real time dispatching under plausible industry and
regulatory scenarios (models) in the changing utility business environment.
Dr. Rahimi also participated as a lecturer in industry-wide courses on Utility
Restructuring (Operation, Institutional, & Economic Issues) and System Planning
in the Context of Competition and Restructuring. He also conducted seminars on
various issues related to power industry restructuring to a wide spectrum of
power industry participants in Hungary, and Poland, where the vertically
integrated national utilities are in the process of privatization and
restructuring.
Other recent major power industry projects include project management for
implementation of EMS and communication systems for the Egyptian National Energy
Control Center; the definition and specification of EMS and telecommunication
requirements for the Power Grid of India; a study of requirements for
telecommunications and substation automation on the high-voltage network in
Poland; the Swiss Federal Railways (SBB) EMS procurement project; the B.C. Hydro
System Control Centre Redevelopment Project; and the definition of a
hierarchical EMS/SCADA control system for the Hungarian Power Companies Ltd.
Dr. Rahimi was the principal investigator on three recent EPRI-fimded research
programs, involving State Estimation and External System Modeling; on-line
Dynamic Security Assessment in EMS; and
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KEMA Consulting
KEMA-ECC & Macro CoipoiatlSn
Evaluation of the Transient Energy Function (TEP) Method. He is currently the
liaison between Macro/KEMA-ECC and EPRI within the framework of a Memorandum of
Understanding to investigate potential use of EPRI products and standards in the
emerging utility environment (ISOs and Power Exchanges).
Prior to joining KEMA Consulting/Macro Corporation, Dr. Rahimi was the Manager
of Energy Modeling and Analysis Department at System Europe (SE), Brussels,
Belgium. Prior to that, at Brown Boveri in Baden, Switzerland, he was
responsible for research and development in the area of advanced EMS
applications. Previously, he was a tenured. Full Professor of Electric
Engineering. His teaching and research activities embraced electric power system
analysis, planning, operations and control, electric machines, industrial
measurements and process control, control and communication systems, and
supervision of several graduate theses. Simultaneously, he collaborated with
Systems- Europe, Brussels, Belgium in joint projects in Iran and Europe. He was
a consultant to the Iranian Ministry of Energy and to the Commission of European
Economic Communities (EEC). In early 1970's Dr. Rahimi was a Senior Research
Engineer at Systems Control Inc. (now ABB Systems Control) Palo Alto,
California. His activities and responsibilities included power systems control,
stability analysis, and transportation systems simulation.
Education
M.S.E.E. - Massachusetts Institute of Technology (M.I.T.), 1968
Ph.D. - Massachusetts Institute of Technology (M.I.T.), 1970
Publications
1. F.A. Rahimi, "On-line Dynamic and Voltage Stability Assessment in the
Transmission Open Access Environment", Proceeding of Arab Electricity
'97 Conference, Bahrain, March 1997.
2. F.A. Rahimi, "Resource Scheduling in Transmission Open Access
Environment," presented at the 14th Biennial IEEE/PES Control Center
Workshop, Minneapolis, October 21-23, 1996.
3. F.A. Rahimi, "International Trends in Deregulation and Privatization";
presented at the Utility Restructuring Course, San Francisco,
California, March 25-27, 1996.
4. F.A. Rahimi, "Operation and Management of the New Transmission
Company"; presented at the Utility Restructuring Course, San Francisco,
California, March 25-27, 1996.
5. F.A. Rahimi, "Emerging Transmission Costing Framework"; presented at
the Course on Planning in the Context of Competition and Deregulation";
San Francisco, California, March 27-29, 1996.
6. F.A. Rahimi, K. Kato, S.H. Ansari, V. Brandwajn, G. Cauley, D.J.
Sobajic "On External Network Model Development," IEEE Transactions on
Power Systems, Vol. 11, No. 2, May 1996, Pages 905-910.
7. M. Christoforides, B. Awobamise, R. Frowd and F.A. Rahimi, "Short-term
Hydro Generation and Interchange Contract Scheduling for Swiss Rail";
IEEE Transactions on Power Systems. Vol. 11, No. 1, February 1996,
Pages 274-280.
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KEMA Consulting
KEMA-ECC & Macro Corporate
8. M. Christoforides, M. Aganagic, B. Awobamise, S. Tong, and F.A. Rahimi,
"Long-tenn/Mid- term Resource Optimization of a Hydro-Dominated Power
System Using Interior Power Method"; IEEE Transactions on Power
Systems, Vol. 11, No. 1, February 1996, Pages 287- 294.
9. P.A. Rahimi, "External Model Development Issues and Guidelines";
presented at the Panel Session on New Developments' in State
Estimation, IEEE PES Winter Meeting, Baltimore, Maryland, January 1996.
10. F.A. Rahimi, "Engineering Consulting Services Abroad," presented at the
Panel Session on U.S. Companies in International Marketplace, July 26,
1995, IEEE PES Summer Meeting, Portland, Oregon.
11, P.A. Rahimi, "Cost/Benefit Analysis of Parameter Estimation as an EMS
Function", presented at the American Power Conference, Chicago, April
18-20, 1995.
12. I. Benko, L. Kiss, and P.A. Rahimi, "New EMS/SCADA Functions in the
Unbundled Power System"; presented at CIGRE Colloquium, Study Committee
39, September 1995.
13. P.A. Rahimi, L.P. Hajdu, J. Piotrowski, and M. Jaworski, "The Evolving
Telecommunication strategy and Infrastructure at the Polish Power Grid
Company"; Utility Communications Seminar, The Hague, March 16-17, 1995.
14. J.Piotrowski, M. Jaworski, F.A. Rahimi and L.P. Hajdu, "Electric
Utility Use of Fiber Optic Communication Systems in Poland"; Europe '94
Transmission and Distribution Conference, Amsterdam, October 10-14,
1994.
15. F.A. Rahimi, L.P. Hajdu, L. Kiss, and L. Balogh, "A General
Cost-Benefit Analysis Methodology for Evaluation of EMS/SCADA
Procurement Alternatives"; Paper APT 446-02- 02, Proceedings of Joint
IEEE/NTUA International Power Conference, APT '93, Athens Greece,
September 5-8, 1993, Pages 384-389.
16. F.A. Rahimi, M. G. Lauby, J. N. Wrubel and K. L. Lee, "Evaluation of
the Transient Energy Function Method for On-line Dynamic Security
Analysis," IEEE Transactions Power Systems, Volume 8, No. 2, May 1993.
17. D.L. Brown, J. W. Skeen, P. Daryani and F.A. Rahimi, "Prospects for
Distribution Automation at Pacific Gas and Electric Company," IEEE
Transactions on Power Delivery, Vol. 6, No. 4, October 1991.
18. F.A. Rahimi, "Evaluation of Transient Energy Function Method Software
for Dynamic Security Analysis," Final Report to EPRI, Report No.
EL-7357, July 1991.
19. F.A. Rahimi, N. J. Balu, and M. G. Lauby, "Assessing On-line Transient
Stability in Energy Management Systems"; IEEE Computer Applications in
Power, Vol. 4, No. 3, July 1991.
20. A. Debs, J. Kirn, G. Maria, P.A. Rahimi, and C. Tang, "On-line Dynamic
Security Assessment Using Stability Transient Energy Function
Analysis," EPRI Research Project 2206- 07 Course, Atlanta, Georgia,
September 1991.
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KEMA-ECC & Macro Corporation
21. F.A. Rahimi, "Generalized Equal-Area Criterion: A Method for On-line
Transient Stability Analysis," 1990 IEEE International Conference on
Systems, Man, and Cybernetics, Los Angeles, California, Nov. 1990.
22. F.A. Rahimi, "Electric Power Systems Planning within the Framework of
the Overall Energy System," paper presented at the Energy Modeling
Conference, Rio de Janeiro, Brazil, December 1988.
23. F.A. Rahimi and G. Schaffer, "Power System Transient Stability Indexes
for On-line Analysis of Worst-case Dynamic Contingencies," IEEE
Transactions on Power Systems, Vol. PWRS-2, No. 3, Aug. 1987.
24. F.A. Rahimi, "A Unified Approach to Sectoral Technology Assessment of
Industrial Energy Demand and Energy Conservation," presented at the
Third Latin-American Seminar on Long Term Energy Demand, Analysis and
Forecasting, Caracas, Venezuela, July 1987.
25. H.J. Kushki and F.A. Rahimi, "A New Algorithm for Automatic Testing of
Single- Contingency-Connectedness of Electric Power Networks," IASTED
International Symposium on Modeling, Identification, and Control,
Innsbruck, Austria, Feb. 1984.
26. F.A. Rahimi and A. Novin, "Security Cost-Effectiveness Priority Indexes
for Use in Power Systems Planning," AFRICON '83, Nairobi, Kenya, Dec.
1983.
27. A. Rahimi, A.A. Bakeshloo, and C. Lucas, "A New Approach to Saturated
Growth Processes with Application to Oil Reserve Estimation," MELECON
'83, Athens, Greece, May 1983.
28. F.A. Rahimi, "Dynamic Braking Control of Electric Power Systems," IEEE
Winter Power Meeting, New York, Feb. 1978.
29. P.A. Rahimi, H. D'Hoop, R. Rubin, and D. Finon, "An Energy Model for
Europe," International Conference on Information Sciences and Systems,
Patras, Greece, Aug. 1976.
30. J. Peschon and F.A. Rahimi, "Computer Control in the Electric Utility
Industry," First International Congress of Electrical Engineering in
Iran, Shiraz University, Shiraz, Iran, May 1974.
31. Rahimi, K.N. Stanton, and D.M. Salmon, "Dynamic Aggregation and the
Calculation of Transient Stability Indices," IEEE Transactions on Power
Apparatus and Systems, Vol. 91, No. 1, Jan./Peb. 1972.
32. A. Rahimi and R.W. Brockett, "Homotopic Classification of Minimal
Periodic Realizations of Stationary Weighting Patterns," SIAM Journal
on Applied Mathematics, Vol. 22, No. 3, May 1972.
33. R.W. Brockett and A. Rahimi, "Lie Algebras and Linear Differential
Equations," Ordinary Differential Equations, Academic Press, 1972.
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