The
electric power industry has three major components: power generation, the
bulk power transmission grid, and local distribution grids. Power generation
plants produce electric power, bulk power transmission systems route the
electric power to distribution systems, and distribution systems deliver
electricity to retail customers. Power generation is the most expensive
component, representing 55 percent of major investor-owned utilities' plant
investment. Transmission represents 12 percent and distribution 29 percent
(Figure 12). Although power generation is the largest
investment, all components are integral. The bulk power transmission system
is necessary because it enables utilities to deliver power over long distances.
This capability increases the potential for competition by providing electricity
customers an opportunity to purchase less expensive power from distant
suppliers. A market in which customers have a choice of electricity suppliers
is essential for a competitive industry to flourish.
To operate the systems safely and reliably, and to provide dependable electric service to their customers, the interconnections are divided into 152 regional "control areas" that monitor and control a regional transmission grid. Control areas are the primary units responsible for the reliable operation of the transmission system. Among other things, control areas designate the generators to operate (unit commitment), schedule power trades between control areas (transaction scheduling), and schedule electricity generation from each generator (unit dispatch).28 The Eastern Interconnection has 109 control areas, the Western has 33, and the Electric Reliability Council of Texas (ERCOT) has 10, for a total of 152 control areas.29
To improve operating efficiencies, some utilities have created regional power pools to coordinate the operation and planning of generation and transmission among their members. Centrally dispatched power pools achieve increased efficiencies by selecting the least-cost mix of generating and transmission capacity, by coordinating maintenance of units, and by sharing operating reserve requirements.30 Some power pools function as control areas (tight power pools); others have more limited roles (loose power pools). Utility holding companies and other large utilities often use methods similar to tight pools, referred to as affiliate power pools, to improve operating efficiency. The United States has 22 centrally dispatched power pools and large utilities (see box). Through resource sharing and least-cost dispatching, these centrally dispatched pools and large multi-plant utilities are able to reduce operating costs and thus lower the costs to end-use electricity customers (Appendix D contains additional discussion of the control and operation of electric systems).
|
Tight Power Pools
a These utilities are members of the newly created California Independent System Operator, which performs functions similar to those of a tight power pool. Source: Adapted from National Council on Competition and the Electric Industry, The Organization of Competitive Wholesale Power Markets and Spot Price Pools (October 1996). |
The Energy Policy Act of 1992 gave the Federal Energy Regulatory Commission (FERC) authority to order bulk power transmission owners to provide access to their transmission grids to third parties when requested. This helped make the transmission system more accessible to outside customers, but in many instances transmission customers did not receive the flexibility of service that transmission owners retained for themselves. Also, timely permission to use the grid sometimes did not occur, because the FERC had to review requests on a case-by-case basis.
The FERC's Order 888 (issued April 24, 1996) includes provisions to correct these problems. Briefly, it requires utilities owning bulk power transmission facilities to treat any of their own new wholesale sales and purchases of energy over their own transmission facilities under the same transmission tariffs they apply to others. This is called comparable service. To implement comparable service, each transmission-owning utility under the FERC's jurisdiction filed a pro forma tariff, specifying the terms and conditions of transmission service applicable to all eligible customers. Still, some regulators and industry participants believed that this would not be adequate to eliminate favoritism and discriminatory practices of transmission owners, and that stronger approaches were needed. The concept of separating transmission ownership from transmission control was thought by many industry players to be an effective complement to the pro forma tariff.
Separation of ownership from control started in the California restructuring debate. In 1994, two California utilities (San Diego Gas & Electric Company and Southern California Edison Company) proposed a regional company that would have operating control of some or all generators and all transmission facilities.32 This evolved and expanded into the independent system operator (ISO) concept, where the transmission system is independently operated. Since the California proposal, the ISO concept (supplemented by the FERC's endorsement) has gained momentum. ISOs are now being formed in many regions of the United States. The FERC has indicated that a properly structured ISO can be an effective way to eliminate discriminatory practices in transmission and to comply with Order 888.
Benefits and Potential Limitations of the ISO
The expected benefits of an ISO are more than just ensuring equal and fair access to the transmission system. By sharing resources, and by having central dispatch, an ISO can achieve efficiencies in system operation similar to what power pools have experienced. Consolidating transmission tariffs provides the ISO an opportunity to employ efficient transmission pricing methods, an issue that has received much attention in the industry recently. Some potential benefits of an ISO include:
Success of the ISO concept may hinge on overcoming the following related issues:
At present, four ISOs are operating and seven ISOs are in different planning
stages (Figure 13 and Table
15). With the exception of the Southeast region, ISOs are planned in
all regions of the United States, although, in most cases, regional coverage
is incomplete. In the Midwest, for example, portions of the transmission
grid in Michigan, Indiana, Ohio, Kentucky, and Missouri will be controlled
by the ISO, while other sections of the grid in the same States will not.
Incomplete regional coverage will limit the gains in efficiency of operation
expected from an ISO-administered, region-wide transmission tariff.35
Following is a summary of the progress of each ISO proposal:
| FERC ORDER 888 PRINCIPLES FOR INDEPENDENT SYSTEM OPERATORS (ISOs) |
|
Note: Principles are applicable only to ISOs that would be control area operators, including any ISO established in the restructuring of power pools. Source: Federal Energy Regulatory Commission, Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Service by Public Utilities, Order No. 888 (Washington, DC, April 24, 1996). |
ISO functions can be classified broadly under two categories: the facilitation
of a wholesale power market, and the control of the transmission grid and
related facilities (Figure 14).
The relative importance of the functions within these two categories, and the details of how they are performed, vary among ISOs. A review of current ISO plans suggests the following general observations:
Need for Independent Governance of ISOs
To be a credible administrator of fair and nondiscriminatory transmission access, the ISO's governing structure must be independent of any individual market participant or class of participants, and the governing rules should prevent control by any class of participants.40 Also, employees of the ISO must be financially independent of market participants. The FERC's ISO principles 1 and 2, which are referred to as the "bedrock"41 upon which an ISO must be built, emphasize these points.
The composition and structure of the Board of Directors is perhaps the key element for ensuring independence of the ISO. The board will have ultimate approval authority over the organization's policy and operating procedures. To establish an independent board, ISOs in the United States have chosen to use two models. One model is the multi-class stakeholder board, where most or all classes of users are represented on the board. Typical stakeholder classes are utilities owning transmission facilities, utilities not owning transmission facilities, independent power producers, power marketers, and end users. The board's independence is maintained by balancing the number of directors representing each class of market participants. A multi-class stakeholder approach, which is being used in California's ISO and Power Exchange, is perceived as "fair" because it gives stakeholders a voice in governance. Also, it ensures direct participation by market participants with experience in power transmission systems. On the other hand, with many different interest groups, the board's voting rules are important. If the voting rules are flawed, the board may fail to achieve independence, or it may be difficult to reach consensus on important issues because of competing interest groups.
The other model, which most ISOs have chosen to use, is the non-stakeholder board, sometimes referred to as an independent board. This model achieves independence by prohibiting board members from having financial interest in any of the market participants. If, when selected for the board, an individual has financial interests in a market participant, the ISO's code-of-conduct will specify that the individual must divest interest by a certain time. The principal problem with this model is that the board may become isolated from the organization because board members have no direct interest in the industry.
Some of the ISOs are designing a two-tier governance structure that
combines the strengths of both models to provide an independent board with
a working knowledge of the transmission system. Under this structure, a
multi-class stakeholder group reports to an independent non-stakeholder
board. The PJM-ISO designed this type of structure, with a members committee
consisting of five stakeholder classes reporting to an independent board.
Creating More Efficient Transmission Pricing Through an ISO
Transmission costs represent about 2 percent of major investor-owned utilities'
operating expenses, which is relatively small compared to power production
expenses (Figure 15).42
The question arises, if transmission prices are relatively small, why are
they important? Transmission prices are important because they provide
price signals that can create efficiencies in the power generation market.
For example, transmission prices, if correctly calculated, send signals
to add transmission capacity, or generation, or where to locate future
load. Adding transmission capacity to relieve transmission constraints
can allow high-cost generation to be replaced by less expensive generation,
which results in savings to consumers. Also, a well-structured transmission
tariff can eliminate "pancaked" prices, lower transmission costs, and open
a region to increased competition. (Pancaked prices are discussed later
in this chapter.)
The FERC, through its transmission pricing policy and approval authority,
recognizes the key role of transmission prices in a competitive industry
(see box). The FERC's pricing objectives indicate that while meeting revenue
requirements is an important objective, transmission prices should also
promote economic efficiency. Most of the ISOs have designed transmission
pricing methods that are more efficient than those used in the past.43
| FERC's Principles for Transmission Pricing |
|
Source: Federal Energy Regulatory Commission, Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act; Policy Statement, 18 CFR PART 2.22. |
Transmission Pricing To Meet Revenue Requirements: Utilities
have historically used the "contract path" concept for transactions. Under
the contract path concept, the transacting parties assume that power flows
over a predefined path, and that transmission prices are based on the predefined
path. This technique is straightforward and easy to administer. In reality,
however, power flows are rarely confined to a predefined contract path;
instead, according to physical laws, power flows in a network over multiple
parallel paths that may be owned by several utilities not on the contract
path. Under the contract path, therefore, a transmission owner may not
be reimbursed for use of its facilities (Figure 16).
The contract path method fails to deal with parallel path flows (also
called loop flows), and it facilitates the pancaking of transmission rates
as power moves across any region with two or more transmission owners (Figure
17). Each time the contract path crosses a boundary defining transmission
ownership, additional transmission charges are added to the transaction.
This pancake effect can double or triple the price of the transaction,
depending on the number of systems it crosses.
To eliminate pancake transmission rates, most ISOs have proposed zone pricing. With zone pricing, the transmission grid under ISO control is divided into zones, and the transmission customer pays one rate based on the zone where the energy is withdrawn, regardless of how many other zones are crossed in the ISO's region. For example, PJM-ISO has defined 10 zones corresponding to the service areas of the transmission owners in its region. The customer pays the rate of the zone where the load is located. The rates for a particular zone are based on the revenue requirements of the transmission owners in the zone.
Zone rates are considered, in some instances, an interim method. Ultimately, the ISOs may implement a system-wide uniform rate without zones, which was recommended by the FERC. A system-wide transmission rate would be based on the average revenue requirements of transmission owners across the entire ISO region. One problem with this approach, however, is that an average uniform price may result in "cost shifting" when the revenue requirements of high- and low-cost transmission owners are averaged. Some cost shifting may be unavoidable if a uniform system-wide rate is the ultimate objective. PJM-ISO was ordered by the FERC to file a uniform system-wide rate proposal by July 2002. The FERC's guidance was that PJM-ISO should eventually move to pricing based on electrical characteristics and power flows instead of corporate boundaries, although no schedule was given to complete the transition. Zone pricing or a system-wide uniform rate does not account for or resolve parallel power flows.
Two regions planning to create ISOs—MAPP and SPP—have proposed using a megawatt-mile methodology for transmission pricing. This approach is a distance-based method that takes into account parallel power flows. Using power flow modeling techniques and appropriate software, actual energy transactions are modeled to identify the power flow over all paths from the generating source to the load. Transmission line charges will be calculated for each line where power flowed, based on the results of the model. This approach eliminates the problem using the contract path method where transmission owners are not reimbursed for using their facilities. However, critics claim that this approach does not correctly measure usage because it gives no credit for counterflows on transmission lines. The method is also administratively more complicated than other methods, because every change in transmission lines or transmission equipment requires recalculation of the flow simulation. Some market participants prefer the simplicity of a system-wide uniform transmission price.
Pricing Transmission Congestion: Congestion in the transmission system occurs when a transmission line reaches its transmitting capacity, limiting the system operator from dispatching additional power from a specific generator. Congestion may be caused by generation or power grid outages, increases in energy demand, or loop flow problems. When congestion occurs, the transmission system operator may have a number of options it can use to solve the problem. For example, it can curtail power from certain generators, or it can dispatch another generator outside the congested area to supply power. Curtailment of power from a generator may be referred to as redispatch, and the use of another generator to supply power is called out-of-merit dispatch.
Whatever option the operator uses to relieve congestion has costs, which are called congestion costs. They consist of the following items: the increase in operating costs from dispatching units out-of-merit, and savings or profits forgone when a transmission customer cannot use the system because of constraints. The difference in operating costs between the high-cost generator, which was dispatched out-of-merit, and the lower cost generator equals the transmission congestion cost. It can be significant, depending on the relative operating costs of the generators. Congestion costs are measured by the difference in generation costs between locations.
In the past, congestion costs were either unaccounted for or bundled into the transmission rate and therefore hidden. This approach has shortcomings: it provides no price signal for efficient allocation of transmission resources, it allocates congestion costs to transmission customers who are not causing the congestion, and in the short term, it provides no economically efficient way for relieving congestion.
All the ISOs are developing methods to measure congestion costs and charge their transmission customers for these costs. Three methods for computing congestion charges have been proposed. A basic overview of these methods follows:
| Example of Congestion Charges Computed by the PJM-ISO and New York ISO |
If an energy supplier owns 100 megawatts of generation at
point A and needs to serve 100 megawatts of load at point B, it can either:
Source: S. Pope and J. Chandley, "Locational Marginal Cost Pricing Theory and Calculation," Conference on Congestion Pricing and Tariffs (January 23, 1998). |
The PJM and New York ISOs have developed an innovative program based
on the concept of "financial rights." Financial rights can be equivalent
to physical rights, but with financial rights, trading is easier and less
costly because usage of the transmission system need not be tied to ownership
rights. A financial right, defined for two points on the transmission grid,
entitles the holder to receive payment when the cost of energy between
the two points varies (Figure18). The initial allocation
of financial rights will go to transmission customers with existing transmission
contracts and to transmission owners on the basis of their need to serve
native load. The ISO will also sell financial rights in a centralized auction.
Holders of these rights are free to trade their rights.
This brief overview of transmission rights shows how they can be used in a competitive electricity industry; however, the concept of tradeable transmission rights has never been tested in the United States, and its effectiveness as a financial tool in the industry remains to be seen. The California ISO is currently designing a transmission rights program, and other ISOs may follow if the concept proves feasible.
Power Exchanges and the ISO
Most financial energy transactions in the industry today are bilateral. Buyers and sellers contract individually for power under prices, terms, and conditions they agree upon. The time frame of the transaction can be short- or long-term. Although bilateral trading is the primary trading method, over the past few years the power industry has seen the emergence of power exchanges, a new approach to selling energy. A PX, also called a spot price pool, is a trading center where utilities, power marketers, and other electricity suppliers submit price and quantity bids to sell energy or services, and potential customers submit offers to purchase energy or services. A few commercial exchanges are already operating: California-Oregon Border; Palo Verde, and a few other locations.46 Abroad, England and Wales, Norway, Chile, and portions of Australia use power exchanges to trade electrical energy. Now, some regions with ISOs under development are also planning to establish nonprofit power exchanges (California ISO, ISO-New England, PJM-ISO, and maybe the NY-ISO).
Some industry observers have criticized the idea of an energy power exchange. They say that a centralized energy market is unnecessary and that, with an increasing number of market participants, bilateral markets will achieve the same efficiencies expected of a power exchange. On the other hand, proponents of power exchanges claim the following advantages:
Some ISO designs now being proposed have the power exchange directly under ISO control, while other proposals create an independent power exchange. This issue has also been debated extensively throughout the industry.47 Some say a power exchange controlled by an ISO would have a competitive advantage over other electricity trading markets in the region because, as the regional transmission system operator, it would have information about the transmission system that would not be available to its competitors. On the other hand, proponents of an ISO-controlled power exchange claim that the ISO will operate the market only and will not trade on its own account or make a profit and, therefore, will not be competing against other energy markets.
Further, because of the need for energy balancing and other complexities of operating a transmission system, close coordination between the system operator and the power exchange is required. A power exchange directly under the ISO's control is an efficient way to achieve close coordination.
The California PX will be independent of its ISO, while PJM-ISO will operate its PX within the same organization. New York is seeking eventually to create a PX independent from the ISO. With different regions using different approaches, it will be interesting to see which approach produces the most favorable results.
Monitoring Wholesale Power Markets Through an ISO
With new wholesale energy markets being started, regulators and others have raised concerns about the potential for market power or market manipulation by participants. (Market power refers to the ability of a supplier to profitably raise and maintain prices above competitive levels.) One example would be an owner of a must-run unit selling energy at prices above competitive price levels. Must-run generators, because of their location, must be dispatched during certain hours for reliability purposes, which places the units in a favorable position. ISOs specify must-run units in advance of when they are needed.
Market manipulation or abuses can take many forms. For example, a market participant may take unfair advantage of the rules, procedures, or conditions of the market. This may include a power generator, who is aware of a transmission constraint, taking advantage of the constraint by raising prices above those normally charged, or taking advantage of other conditions that affect the availability of transmission and generation capacity, such as generator or transmission outages.
The FERC requires an ISO to monitor its energy market for manipulation or abuses by the participants. This requirement covers both the power exchange (auction-based) market and bilateral transactions in the region. An ISO will prepare a market surveillance plan specifying the scope of its surveillance activities, the data and metrics used to flag potential problems, and remedial actions to eliminate the problems. A compliance staff will implement the ISO's surveillance plan.
The ISO's authority to take corrective actions when market abuses are identified depends on the nature of the abuse. Clearly, if a market participant is taking advantage of an ISO's rule or procedure, the ISO will have the authority, subject to the FERC's approval, to change its rules. Violations of the FERC's regulatory policies or of the antitrust laws will be referred to the appropriate agency for action.48 With an increase in the number of players in the industry, and the newness of the market, surveillance is an important activity to ensure that the market functions properly.
Ensuring System Reliability Through an ISO49
In accordance with FERC's ISO principle 4, all ISOs will ensure short-term reliability of grid operation using NERC operating policies and the applicable Regional Reliability Council (RRC) standards. All ISOs that have submitted applications to the FERC have indicated that they will comply with these policies and standards, although compliance is voluntary. The New York ISO has taken its responsibility one step further by establishing a new entity, the New York State Reliability Council (NYSRC). The New York ISO will follow the NYSRC reliability standards, which in turn will follow the NERC and RRC standards. The creation of a State reliability council in New York reflects a concern by the transmission owners that they, rather than the ISO, will be held responsible for maintaining reliability. The NYSRC will apply close oversight of the ISO. New York is the only State with plans to propose its own reliability council.
Compliance with the NERC operating policies has two implications for
the ISO. First, because NERC places operating responsibility for reliability
with the control area operators (see box), the ISO must direct a control
area or become one. The California ISO and each of the three tight power
pools that are restructuring into an ISO will operate as one control area.
The other ISOs will have multiple control areas within their regions and
will provide directives to the control areas.
| Introduction to NERC's Operating Policies |
| NERC operating policies place the responsibility for operating
reliably primarily on the Control Areas that operate within the four Interconnections
of the United States and Canada and Northern Baja California Norte, Mexico.
NERC recognizes that in the open access transmission environment, Control Area officials are assigning some of their responsibilities, especially for transmission security, to other entities. These entities include independent system operators and security coordinators. The Control Area officials who assign responsibilities to other entities must ensure, through agreements or otherwise, that those entities comply with the NERC operating policies. Purchasing and selling entities also are responsible for fulfilling
their informational and procedural obligations, and for keeping records
that document their compliance.
Source: North American Electric Reliability Council, "Introduction to the Operating Policies" (July 8, 1997). |
Second, NERC has created security coordinators that coordinate, oversee,
and enforceregional and subregional security processes affecting the bulk
electric system. These security coordinators have real-time data to allow
them to monitor the grid and to take appropriate action for reliability
purposes. Currently, 22 security coordinators cover the four Interconnections
in North America (three in the United States and one in Canada). Most ISOs
will assume the security coordinator's role (Figure
19). In a few instances (ERCOT, for example), the ISO will not be the
security coordinator, and the existing control areas will continue this
role.
Maintaining a reliable power system is an important responsibility of an ISO. Increases in the number of wholesale transactions and the number of market participants make operating the transmission grid more complex and maintaining a reliable system more difficult. The competitive dynamics among a much larger universe of players are not at all conducive to a system of voluntary compliance. A fundamental challenge to the industry is the expected decline in voluntary compliance with reliability standards.51 To meet the challenge, some industry leaders are recommending an enforcement authority. The Clinton Administration's recent electricity competition plan proposes to require the FERC to approve and oversee a private self-regulatory organization that prescribes and enforces mandatory reliability standards.52 In comparison, the NERC's Electric Reliability Panel, which was commissionedto study reliability issues, recommended that a reorganized NERC—called the North American Electric Reliability Organization (NAERO)—should have sufficient authority to enforce compliance with reliability standards. NAERO would be recognized by government bodies as a self-regulating organization.
As it stands now, it is not clear who will enforce reliability and under what authority. Solutions to the enforcement issues and a myriad of other complicated reliability issues will likely affect in undetermined ways the ISOs now operating and those that are now being formed. For example, the ISO's role for maintaining reliability under a voluntary compliance program might expand to include enforcement if a mandatory compliance program is established.
ISOs and the Open Access Same-Time Information System
The Open Access Same-Time Information System (OASIS) is an interactive
Internet-based database developed by the electric power industry (Figure
20). The database, which will be used by transmission providers and
transmission customers, contains information on transmission capacity reservations,
ancillary services, and transmission prices (Table 16).
The underlying idea of the OASIS is to create an interactive computerized
market for transmission reservations, along with other transmission-related
products and services. In that role, the OASIS facilitates equal and comparable
access to the transmission grid, and it supports a competitive wholesale
electricity market.
OASIS will be developed in two phases. Phase I was completed in January 1997, when the system became operational. Based on a few months of experience, Phase I-A was started to implement short-term improvements in OASIS requested by FERC and by the industry. Phase I-A is ongoing. Phase II is intended to expand the system's functionality by adding capability to process energy transactions, to manage transmission constraints, and to place next-hour reservations and schedules.
The FERC required development of the OASIS, with mandatory participation for those utilities under FERC's jurisdiction.53 FERC's jurisdiction covers utilities owning about 70 percent of the Nation's transmission grid. A significantnumber of nonjurisdictional transmission providers also participate in the OASIS, including several Canadian utilities. As of January 1998, 174 transmission providers share 27 nodes on the system. Three operational ISOs and three underdevelopment have OASIS nodes: ERCOT-Texas ISO, ISO-Nepool, PJM-ISO, New York ISO, MAPP, and SPP.54 For its electronic information exchange needs, California ISO built the Western Energy Network (Wenet), a system that is separate from the OASIS. Wenet does not satisfy OASIS requirements, and the FERC granted the California ISO an interim waiver with instructions that it must comply with Phase II.
The OASIS concept is an innovative tool developed by the industry to manage and disseminate information that will make the industry more competitive; however, OASIS has an uncertain future. Although OASIS has had some successes, it also has had serious development and operating problems, and at present it is not an entirely useful or effective tool for supporting a competitive wholesale market.55 Some of the problems are that the system is hard to use, the nodes lack standardization of terms and graphics, and definitions and business practices are inconsistent across nodes. Many of these problems should be solved during Phase I-A.
A broader issue concerns regional tariffs and their effect on OASIS.
OASIS was conceived as a nationwide system serving all transmission customers
with standardized procedures and protocols. Regional transmission tariffs
have been approved, however, with nonstandardized procedures and protocols
that are not compatible with the OASIS design. For example, New York ISO,
ISO-New England, and PJM-ISO have regional tariffs that either do not use
transmission reservations as defined in OASIS, or use a different process
for transmission reservations. The California ISO and PX are adopting a
system in which transmission reservations are irrelevant, because all schedules
for transmission service are accepted, although they may be adjusted. More
regional tariffs are likely as the ISO movement continues. It is safe to
conclude that regional differences will increase the complexity and costs
of the OASIS.
The ISO is a relatively new concept in the electric power industry, brought on primarily by the need to ensure nondiscriminatory access to the transmission system. With more experience, the role and importance of the ISO in the industry will likely expand. Most of the ISOs now being formed will be responsible for control and reliability of the transmission system, ensuring open access, administering a regional transmission tariff, transmission system planning, and, in some instances, facilitating regional wholesale power markets.
Competition and the increasing number of transactions and players in
the wholesale energy market will make the ISO's responsibility for system
reliability more difficult to carry out. ISOs are experimenting with new
approaches to transmission pricing which, if successful, should make the
overall industry more efficient.
29. The control areas are listed on the web site www.tsin.com.
30. Report prepared by Paul A. Centolella, Science Applications International Corporation, for The National Council on Competition and the Electric Industry, The Organization of Competitive Wholesale Power Markets and Spot Price Pools (October 1996).
31. Written comments of Professor Paul L. Jaskow, Massachusetts Institute of Technology, submitted to the Federal Energy Regulatory Commission, Technical Conference Concerning Independent Systems Operators and Reform of Power Pools Under the Federal Power Act (Washington, DC, January 24, 1996).
32. Federal Energy Regulatory Commission, Inquiry Concerning Alternative Power Pooling Institutions Under the Federal Power Act, 18 CFR Chapter I (October 26, 1994).
33. Federal Energy Regulatory Commission, Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 18 CFR Part 2 (December 18, 1996).
34. This concept refers to a utility divesting ownership of its transmission facilities. California's Public Utility Commissioner Greg Conlon stated this position, noting that the ISO in California was a compromise solution to the State's restructuring initiative. "Fitch Analyst Sees ISOs Playing Brief and Relatively Minor Role," Electric Power Week (August 25, 1997), p. 8.
35. The Clinton Administration's Comprehensive Electricity Competition Plan addressed this issue by proposing an amendment to the Federal Power Act to provide FERC with the authority to require utilities to transfer operational control of their transmission facilities to an independent system operator (Washington, DC, March 25, 1998), p. 8.
36. D.W. Fessler, in Federal Energy Regulatory Commission Technical Conference Concerning Independent System Operators (Washington, DC, January 24, 1996).
37. Federal Energy Regulatory Commission, Order Conditionally Authorizing Establishment of an Independent System Operator and Disposition of Control Over Jurisdictional Facilities, Docket No. EC97-35-000 (June 25, 1997).
38. "Midwest ISO Cratered by Breakaway Group; Regional Picture Now Unclear," Electric Utility Week (December 15, 1997), p. 1.
39. Additional discussion of an ISO's responsibilities is contained in: Secretary of Energy Advisory Board Task Force on Electric System Reliability, The Characteristics of the Independent System Operator (Washington, DC, March 1998).
40. Many of the governance concepts in this section are discussed in more detail in James Barker et al., Governance and Regulation of Power Pools and System Operators, An International Comparison, World Bank Technical Paper No. 382 (Washington, DC, September 1997).
41. Federal Energy Regulatory Commission, Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities, Order No. 888-A, 18 CFR 35, p. 211.
42. These costs do not include the cost of ancillary services, which are reported as production expenses.
43. Federal Energy Regulatory Commission, Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act; Policy Statement, 18 CFR PART 2.22.
44. Many articles on location-based marginal pricing are available in trade journals. The Electricity Journal for the years 1996-1997 has some informative articles on LBMP. Also, a good explanation of LBMP can be found in the Affidavit of Susan Pope to the FERC, On Congestion Pricing Under the Proposal To Restructure the New York State Electricity Market, available from the New York Power Pool's web site, www.nypowerpool.com/iso/dec97/VOL_II.PDF.
45. The California restructuring plan creates scheduling coordinators whose purpose is to prepare schedules that match generation with demand for their customers. The California Power Exchange is one of the scheduling coordinators. The scheduling coordinators submit their proposed schedules for power to the California ISO. The ISO has the job of reconciling the requests of the various scheduling coordinators and dispatching the generators.
46. Energy Information Administration, The Changing Structure of the Electric Power Industry: An Update, DOE/EIA-0562(96) (Washington, DC, December 1996), p. 98.
47. The Wall Street Journal carried a series of articles and letters to the editor covering this subject: R. Blohm, "Don't Give Utilities a Monopoly on Power" ( March 11, 1997); W. Hogan, G. Weil, "Letters to the Editor—A Stock Market for Electricity" (April 2, 1997); R. Blohm, S. Oren, "Letters to the Editor—The Case Against Centralized Electricity" (April 21, 1997).
48. The Clinton Administration's Comprehensive Electricity Competition Plan proposes to amend the Federal Power Act to give the FERC the authority to remedy concentrations of market power in the wholesale market, including the authority to order divestiture of assets (Washington, DC, March 25, 1998), p. 7.
49. A recent report prepared by ICF Resources, Inc., for the Office of Economic, Electricity and Natural Gas Policy, U.S. Department of Energy, contains a thorough discussion of issues associated with ISOs and system reliability. U.S. Department of Energy, Independent Transmission System Operators and Their Role in Maintaining Reliability in a Restructured Electric Power Industry, DOE/PO/791010 (Washington, DC, December 1997).
50. North American Electric Reliability Council, Electric Reliability Panel, Reliable Power: Renewing the North American Electric Reliability Oversight System (December 1997).
52. U.S. Department of Energy, Comprehensive Electricity Competition Plan (Washington, DC, March 25, 1998), p. 6-7.
53. Federal Energy Regulatory Administration, Open Access Same-Time Information System and Standards of Conduct, Order No. 889, 18 CFR Part 37 (April 24, 1996).
54. A complete list of transmission providers and OASIS nodes can be obtained from web site www.tsin.com.
55. Federal Energy Regulatory Commission,
Industry Report to the Federal Energy Regulatory Commission on the Future
of OASIS (October 31, 1997).
