Rethinking Georgia’s Public Policy in Electric Power

By Cameron Meierhoefer and Melissa Kelman

Since the passage of the 1992 Energy Policy Act, the Federal Energy Regulatory Commission (FERC) has been laying the federal groundwork for deregulated wholesale competition in the electric power industry across the country. At the same time, states across the nation have begun evaluating retail competition, where individual customers can directly benefit from competitive pricing. In an effort to protect their regional monopolies, a number of utilities have warned that market forces cannot protect the public and ensure reliable service to meet all future demand. Yet, industrial users and local economic development authorities have supported careful deregulation as a safe and effective way to achieve lower electricity prices. As a consequence, state governments across the country face the issue of how best to provide electric power to customers within their states.

Local decisions to deregulate electric power markets have been driven by disparities in electricity pricing throughout the country, with average rates ranging from below 5 cents per kilowatt-hour in low-rate states to over 10 cents per kilowatt-hour in many Northeastern states and California. Industrial users in high-rate states have long sought relief from expensive regulated electric rates. These states have been hotbeds of deregulation activity. Concurrently, the interconnection of national transmission systems (under the guidance of FERC orders) has made it feasible to “wheel” (See Glossary, Appendix C) wholesale electricity from distant generation sites to end-users virtually anywhere in the nation.

California, Rhode Island and Pennsylvania have all recently passed legislation mapping out their transition to a competitive electric power market, and at least half of the other state legislatures are currently in debate over the issue. The FERC has, in turn, continued to pave the way for competition with a recent round of rulemaking. There seems to be little question that the electric power industry is heading for competition. However, many of the details must still be worked out, and action by states across the country will be instrumental in determining the future make-up of the electric power industry. As such, it is inevitable that the Georgia Legislature will need to address this issue in order to ensure that Georgia’s electric power interests are served through emerging market structures.

This paper will present an overview of the prevailing model for market competition in the electric power industry, a summary of the options available for Georgia in shaping the future of its electric power industry, and a synopsis of the applicable federal and state legislation.

The Competitive Electricity Market Model

The model for competition in the electric power market consists of an “unbundling” (See Glossary) of the services which, to varying degrees, are currently offered together—generation, transmission, and distribution. The traditional view of the electricity market as a natural monopoly promotes a vertical integration of these three primary functions within a single operating system. Electricity rates are determined on the basis of the average cost of providing this bundled service and do not reflect the costs of performing each separate function.

The traditional rationale behind regulation of the power industry held that a legal monopoly structure, with price and quality standards determined by the state, would provide economy of scale benefits while still allowing regulators to ensure protection of social welfare. Social welfare in this instance encompasses an obligation to serve the general public, reliability standards, and assurance of power quality. Despite these lofty goals, however, consumer electricity rates under this structure have skyrocketed in many regions of the country. Because these high rates have most often been attributed to the failure of certain provisions within the regulatory framework, a more competitive market is widely seen as the preferred option for the supply of electricity.

In a competitive market, generation, transmission, and distribution are treated as distinct functions. It is widely agreed that the generation function is no longer a natural monopoly. It can and should be opened to competition to promote least cost pricing of electric power. The assumption is that there are enough real or potential participants to enforce a workable competition which will result in cheaper electric power.

It is also generally agreed that the wire-intensive transmission and distribution functions remain natural monopolies. The primary reasoning here is that the wires and facilities which transmit and distribute electric power are essential to the market structure, but that duplicate wire facilities would yield little downward pressure on prices. These facilities link all competing generators with their potential customers and must provide open access to all market participants for competition to be effective.

Fundamentals of the Competitive Market

In practice, the implementation of a competitive electric power market requires the establishment of two entities for operation: an Independent System Operator (ISO) controlling the transmission function, and a Power Exchange (PE) to establish the market for electric power and the prices at which power is bought and sold. In a competitive electricity market, power marketers will also emerge to broker transactions between power producers and end users.

The Independent System Operator (ISO)

The Independent System Operator is the keystone of the competitive power market. Its importance extends beyond its duties in providing the transmission of all power sold within the state. The ISO is also the principal means for balancing the relative strength of suppliers and consumers within the market, and as such, the construct of the ISO will determine the effectiveness of such a market in delivering lower cost electricity. In addition, the ISO is normally seen as the vehicle for supplying public purpose initiatives for environmental and energy conservation efforts—matters currently regulated by state Public Service Commissions.

The ISO is responsible for scheduling delivery of electric power and ensuring that actual demands are met. It is also responsible for ensuring system reliability, which includes balancing power within the system in accordance with adjacent transmission authorities and ensuring that maintenance inspections of facilities within the system are standard and safe.

For the ISO to faithfully perform all of these important functions, it must be established as completely independent from supplier (and consumer) interests. Independence is necessary to ensure that all parties in the electricity market are given equal access to essential transmission facilities. This arrangement is the only way to give all consumers the ability to purchase the least cost power and all power producers the ability to sell at market prices. For independence to be achieved, the ISO must have complete operational control over all transmission facilities.

The ISO will be subject to regulation by the state Public Service Commission as well as the FERC. At the federal level, the ISO may be engaged in a good deal of wholesale transmission, wheeling power into, out of, and through the state, under the regulatory authority of the FERC. At the state level, the ISO will be responsible for the transmission of all intrastate electricity. ISO capital costs and the rendering of public services is subject to regulation by the state Public Service Commission.

The Power Exchange (PE)

In conjunction with the ISO, a Power Exchange (PE) provides a market for the sale of the electric power. The PE, like the ISO, must be established as an independent entity to ensure that the market will be competitive. The PE acts as a wholesale power pool where suppliers and customers arrange for the sale of electricity. The PE’s primary function is to match bids from suppliers and customers and publish hourly or half-hourly prices. This probably would occur a day in advance of the actual transmission of power. Once bids are matched, the PE would then be responsible for scheduling transmission with the ISO.

The PE provides a short-run spot market for electricity, but also establishes the framework in which long-run contracts can benefit from competition as well. Bilateral long-term contracts based upon the market price for electricity can allocate risks (due to price fluctuation) between the supplier and customer over time while permitting long-term service agreements. In the short- term market, the PE provides for market transactions between suppliers and consumers, either directly or through agents such as power marketers and brokers acting on behalf of suppliers and end-users.

Power Marketers

The competitive market will provide the setting for the growth of an altogether new business of buying and selling electric power. Power marketers are expected to emerge to “simplify” the purchase of electric power for the consumers. Power marketers would either act on the behalf of a single user or group of users to navigate the market and secure the lowest price for its customers, or alternately, they would act on behalf of a supplier and seek out customers for its power. The presence of power marketers will likely bring about a “re-bundling” of services from the customer’s perspective. A power marketer could offer, for example, two hours of free long-distance telephone service with the purchase of so many kilowatt-hours of electric power, or discounts on other, sometimes unrelated, services of value to customers.

Transition to a Competitive Power Market

In addition to the structural issues that must be addressed when establishing a new electric power market, major challenges arise when trying to implement such a structure. A transition from the current regulated industry to a competitive generation market is necessary to ensure the reliability of the power system and to ensure that the market will be stable. This transition presents difficulties which can be addressed in a variety of ways by a legislature, but due to the complexities of this process state Public Service Commissions are typically seen as the primary vehicle for solving many of these problems.

Stranded Cost Recovery

Perhaps the biggest concern surrounding the transition to a competitive electric power market is the recovery of “stranded investments.” (See Glossary) Under regulation, electric utilities have been allowed to “recover” investments they made in order to meet electricity demands through the electricity rates charged to customers. In other words, utilities have traditionally invested in new power plants or transmission facilities with the assurance from regulators that electric rates will not fall below levels necessary to pay for these investments over time. Should electricity rates become competitive, utilities would lose this assurance. Many of these investments, which have not yet been fully recovered, may well be “stranded” in a competitive environment where recovery is not guaranteed.

Utilities have contended that these investments were made under a regulatory contract that allows for the recovery of investments made to meet their “obligation to serve.” Thus, they argue that utilities should be allowed to recover these stranded costs prior to being forced into competition. Utilities have often found recovery of these costs difficult due to dampened demand and pressure on Public Service Commissions to keep electricity rates low.

This issue is of particular importance for transition because utilities account for a large portion of the generation capacity in the regulated market. Should they find it difficult to price their electricity competitively while recouping their investments, there is the possibility that major utilities could not stay in business. This could potentially threaten the ability of the market to meet all demands for electricity. The controversy here centers on how much of the stranded investment utilities are entitled to recover. Utilities, not surprisingly, believe that they deserve complete recovery because these investments were made under their regulatory obligation to meet future electricity demands. Public service commissions and consumers, on the other hand, point to cost over-runs and the value of these assets in competition as arguments for a lesser amount of recovery.

To address this issue, proposals have called for an accelerated recovery of these costs either through current rate-setting procedures, or through a “transition surcharge” administered through the ISO transmission charge. There are also efforts to accelerate recovery of these costs through a divestiture of generation capacity by investor-owned utilities, which would allow them to receive market prices for their generation assets.

Consumer Protection and the Public Good

Establishing an effective market for electric power, where consumers receive the lowest possible prices requires that there be a distribution of generation capacity among suppliers such that no single supplier can exert control over market prices. In the current regulated environment, the majority of generation capacity is owned by large investor-owned utilities. While such concentration of capacity makes sense in a regulated monopoly, it is undesirable in a competitive generation market. Consequently, divestiture of generation capacity by incumbent utilities has been recommended by FERC to diffuse market power as generation becomes competitive.

Additional concerns in the transition to market competition lie in providing for the public services currently rendered through regulation. These include public efforts to provide universal service (assistance for low-income customers), ensure environmental protection, and promote energy conservation. Many of these efforts will conflict with competitive decisions made by energy suppliers, so continuation of these efforts under competition will require some sort of public intervention.

State Restructuring Plans

California, Rhode Island and Pennsylvania, all of which have rates well above the national average, have enacted legislation that will result in retail competition in electric power generation. California was one of the leaders of this movement, recently approving a plan through which the State will have a fully competitive market by January 1998. This is a comprehensive plan and transition has already begun with the establishment of an ISO and a PE underway. The ISO will have operational control of all transmission facilities and will be responsible for many of the functions currently provided through regulation, such as ensuring system reliability and providing public services. Stranded costs recovery will occur through a consumption-based transition charge for all customers that will not extend beyond the year 2002.

The New England states have proceeded with similar plans, with the Rhode Island legislature mandating full competition by July 1998, and Massachusetts and New Hampshire pilot programs currently in effect. Regional change in this case is being orchestrated by the New England Power Pool (NEPOOL) which manages the area’s transmission system. As such, these states are building their competitive market around their existing transmission system with a gradual phase-in to competition.

Pennsylvania recently adopted broad legislation demonstrating their commitment to competition, but has left many of the details to the public service commission. The legislation encourages the creation of an ISO, but does not explicitly outline a role for a PE. The transition to competition will take place over a four-year time period, which includes time for a possible pilot program. Transition will be complete by January 2002.

As Georgia continues to consider its options for its electric power industry, it could be helpful to look at how other states have approached competition and how they have proposed to deal with the issues surrounding transition. Brief overviews of several state plans appear in Appendix B of this document.

Implications for Georgia

Clearly, there is a movement toward deregulation in the generation portion of the electric power industry. As the resulting “wheeling” expands, Georgia will eventually become a participant in this system. Currently, Georgia electricity rates average roughly 6.5 cents per kilowatt-hour—well below the 10 cent rates facing states actively pursuing competitive generation. While this may reduce the urgency of electric power deregulation in Georgia, it is important the State recognize these trends and take steps to ensure that electricity rates remain competitive in a market structure. This task will include determining how the eventual market should be structured in Georgia and exactly when the transition should be complete.

Potential First Mover Advantages

Potential advantages could be gained by moving early on this issue. In the Southeast, Georgia could establish itself as a regional leader in the electric power industry. The market structure could potentially, like other markets, develop into a system with primary and secondary markets. By being first to establish a power market, Georgia could become the center of trade in the Southeast, with a large portion of electricity in the region being bought and sold within the State’s borders.

Establishing a competitive electricity market before adjacent states could potentially establish the power marketing industry in Georgia. This would not only be a source of jobs for the state, but as other states move to competition, the power marketing industry could see substantial growth from sheer market expansion. Should other states establish the marketing industry first, Georgia could see these jobs created elsewhere as marketers in other states buy and sell Georgia power.

Drawbacks from Early Action

While competition may be coming elsewhere, there is still much to be learned on how to effectively operate such a system so as to reap lower electricity rates. Georgia may be wise to postpone restructuring legislation until the positive and negative effects of other state plans become apparent. Moreover, with some of the cheapest electric power rates in the country, Georgia may be hesitant to enter a national competitive market. Equilibrium effects from nationwide trading, with high-rate states purchasing cheaper power from within Georgia, could potentially bring about an increase in rates for Georgia consumers, defeating the primary purpose of competition. Georgia will need to proceed by considering what is best for both its consumers and its producers in order to benefit from opening its markets to competition.

Legislative Options

Considering the trends nationally and the action taken by several states, the issue of electric power deregulation is ripe to be addressed by the State of Georgia. There are several options for legislative action.

  • Postpone Action: The legislature need not enact legislation deregulating the electric power industry in the State of Georgia. This “do nothing” option would delay action on deregulation, allowing time for initiatives in other states to pan out. This would allow for the issue to be addressed once the benefits and drawbacks of various approaches are better understood. However, any potential advantages gained by being an early adopter of competition would be lost.
  • Commission a Study Group: As a precursor to taking definitive legislative action it may be prudent to further examine how deregulation will work in Georgia. A study group would provide the legislature with specific knowledge of this complex issue and provide guidance on how it should proceed.
  • Initiate a Pilot Program: Initiating a pilot program where a small portion of the state receives competitive electric power service gives the state the ability to test how deregulation will operate within the state. The attractiveness of this option stems from the fact that a state can actively investigate deregulation without the risks and high investments associated with full-scale implementation. It provides the opportunity to assess the strengths and weaknesses of competition in Georgia as well as the time to gain a better understanding of the details of deregulation.
  • Deregulate: Deregulation of the power industry can take many forms and can proceed along a variety of timelines. Swift action moving the industry quickly to competition could capitalize on any potential benefits from early adoption, but will also impose a good deal of learning about how to mold the competitive model to Georgia’s resources and needs. It will be crucial to determine the desired role of the PSC in transition as well as in the final structure. Similarly, the proper role of the transmission authority (ISO) and the PE will need to be determined to guide the transition process. Of course, efforts to deregulate the industry can include studies and pilot programs to help answer some of these questions.

In coming to a decision on how to proceed, it is important that several questions be answered. First, is Georgia likely to benefit from the competitive sale of electricity? This question must be approached from both the consumer and producer perspective. Will it result in lower prices for Georgia consumers? Will it harm Georgia power producers or benefit them through accelerated recovery of stranded costs and broader markets for their power?

If competition is desirable, how should the transition proceed? Transition is a complex process that will require attention to details if it is to result in a stable market structure. What responsibility should be given to the PSC? Concurrently, the pace of transition will have to be considered. This should be determined by answering questions such as: What don’t we know about how competition will work in Georgia? Are there questions that are best answered through a pilot program or study group? What elements are necessary for a functional PE and how long will it take to establish the necessary framework for competition?

The Georgia General Assembly will need to answer these questions to decide on the proper course of action for moving to market competition in the electric power industry. Assuming the inevitability of competition, when and how it occurs in Georgia will determine if Georgia benefits or loses.


Georgia Legislative History

Electricity suppliers in the State of Georgia are subject to three laws enacted by the state legislature: the Georgia Territorial Act of 1973 (GTESA), the Cogeneration Act, and the Integrated Resource Plan (IRP) Statute (HB 280).

Georgia Territorial Act of 1973 (GTESA)

GTESA established Georgia’s system of assigned service areas supported by an Integrated Transmission System (ITS) shared by all utilities. Under this Act, the bulk of the state’s consumers were assigned to major suppliers such as Georgia Power, Oglethorpe Power Corp., and the Municipal Electric Authority of Georgia (MEAG), with smaller allocations given to Savannah Electric and Power Company, the Tennessee Valley Authority, and the Electric Power Board of Chattanooga. Approximately 30 percent of the state’s land area remains unassigned. Within this assignment scheme, however, there are certain exceptions. The Act provides that customers whose demand equals or exceeds 900kW at all times may choose their supplier, free from assigned territorial boundaries. While utility transmission lines are shared in line with the obligation to serve, those suppliers chosen to serve customers outside of their assigned territory are then responsible for constructing and maintaining all necessary distribution lines. In light of this investment, the Act provides that once a choice has been made, the customer must stay with that supplier for the life of its business. However, in special circumstances, customers may petition the PSC for the right to choose a different supplier.

Cogeneration Act and Integrated Resource Planning (IRP) Statute

The Cogeneration Act and the IRP Statute essentially dictate the role of Georgia’s Public Service Commission (PSC) in regulation of the state’s electric power industry. The Cogeneration Act specifies that all retail suppliers of electricity in the state must file their rates with the PSC for approval. This process includes approval of an IRP and certification of resources. Also, this Act prohibits retail wheeling such that industrial cogenerators cannot wheel excess power between different company locations without registering as a competitive utility.

The IRP Statute requires regulated utilities to file an Integrated Resource Plan every three years detailing their current generation capacity and plans for meeting future demand by building new generation plants. The IRP is subject to PSC approval and is used by the PSC in determining regulated rates. This statute also requires that a utility must obtain a certificate from the PSC before undertaking any of the following activities:

  • Beginning construction of a new generating plant;
  • Purchasing power under a long-term contract;
  • Implementing new demand side programs;
  • Increasing or decreasing the output of an existing plant by more than 15 percent; or
  • Selling generating plant capacity which is either certified or in the rate base.

Finally, the IRP Statute guarantees that companies will recover the lesser of actual or certified resource cost along with an additional amount intended to encourage additional power purchases and demand side management programs. Municipal distributors are exempt from these provisions.

Federal Legislative History

The existing electric power regulatory framework was established by three main federal laws: the Public Utility Holding Company Act of 1935 (PUHCA), the Public Utility Regulatory Policy Act of 1978 (PURPA), and the Energy Policy Act of 1992 (EPAct).

Recent actions taken by FERC impose major changes on the standard regulatory framework of the electric power industry by facilitating retail wheeling. These changes are set forth in two rules and a Notice of Proposed Rulemaking (NOPR).

Public Utility Holding Company Act of 1935 (PUHCA)

The first of these laws, PUHCA, was originally enacted to protect investors and consumers from overzealous holding company business practices. Specifically, PUHCA dictated that each holding company could only control one utility unless the multiple utilities were dispersed across adjoining states and bolstered the regional economy.

Public Utility Regulatory Policy Act of 1978 (PURPA)

The enactment of PURPA was an effort to promote the use of “alternative fuels” and to tap all available electricity generation capacity in the context of the energy crisis of the 1970s. The Act enabled industrial and commercial customers to generate their own supply of electricity, bypassing the major utility. These self-generating entities, such as industrial facilities that generate electricity on-site, referred to as Qualifying Facilities (QFs), are exempt from various regulatory provisions. In addition to these exemptions, PURPA created several incentives for self-generation by mandating that regulated utilities purchase excess power generated by QFs. Specifically, PURPA mandates that utilities must:

  • Maintain line connections and continue to sell electricity to QFs as needed;
  • Provide this back-up service at non-discriminatory rates; and
  • Purchase the QF’s surplus output at avoided cost.

Outside of these provisions, PURPA also gave the FERC the authority to order a utility to make their transmission lines available to the QFs for the purpose of “wheeling” power to other consumers.

A 1992 revision of PURPA created additional utility requirements, mandating that utilities must engage in Integrated Resource Planning and invest in conservation and demand management programs, as well as improvements in energy efficiency.

Energy Policy Act of 1992 (EPAct)

The EPAct is most notable for its substantial revision of PUHCA. This revision created a new class of power producers known as Exempt Wholesale Generators (EWGs). EWGs are allowed to generate and sell electricity at wholesale prices, free from PUHCA’s restrictions. The Act also sets forth the following provisions regarding EWGs:

  • An EWG may not sell electricity in the domestic market.
  • An EWG may be entirely owned by a utility.
  • An EWG may sell electricity generated by others.
  • Electric utilities are not required to purchase any available electric energy from an EWG.

FERC Order 888

In April 1996, FERC issued Order 888 which provides open access to utility transmission lines through institution of a single pro forma tariff which all utilities must adopt. This tariff describes the minimum terms and conditions under which a utility can offer nondiscriminatory open access transmission service. A utility is then required to apply this pro forma tariff to use of their transmission lines by other competitors as well as their own wholesale energy sales and purchases.

Order 888 also allows for full recovery of a utility’s service investment (stranded costs) provided that the costs were prudently incurred. The rationale behind this allowance is that competition stemming from open access may result in substantial customer loss such that a utility would not recoup its investment. As such, the Order’s provision states that these costs should be recovered from a utility’s departing customers. However, this recovery guarantee is only applicable to costs incurred under contracts signed before July 11, 1994.

FERC Order 889

In conjunction with Order 888, FERC issued Order 889, known as the Open Access Sametime Information System (OASIS) rule. This rule states that all transmission system information will be available and obtained through an OASIS on the Internet so that transmission line owners will not have unfair advantages due to privileged information. Also along these lines, Order 889 sets forth standards of conduct which require that utility “wholesale merchant functions” must be entirely separated from “transmission system operations.”


Finally, FERC issued a NOPR regarding Capacity Reservation Open Access Transmission Tariffs which states that the open access pro forma tariff established under Order 888 will be replaced with a Capacity Reservation Tariff (CRT) by December 31, 1997. In accordance with the CRT proposal, all power market participants would use a reservation system to secure specific amounts of transmission capacity for retail sales. This reservation system would work in conjunction with the on-line OASIS.





  Legislative Action
  • Legislation passed Aug. 31, 1996 by unanimous vote
  Time Line
  • Full customer choice by Jan. 1998
  • ISO and PE fully operational by that time
Market Structure  
  • Has operational control over all transmission facilities (ownership however retained by the companies)
  • “Shall ensure efficient use and reliable operation of the transmission grid”
  • Responsible for setting standards for maintenance inspection and repair
  • Coordinate grid integrity with adjacent states
  • Responsible to oversight board along with the PE
  Power Exchange
  • Operate an “efficient competitive auction” for the buying and selling of electricity
  • Open to all suppliers on a non-discriminatory basis
  • Establish “spot prices” for electric power
  • Responsible for scheduling transmission with the ISO
Key Issues  
  Stranded Costs
  • Competition Transition Charge (CTC) to be included as separate item in customer bills in proportion to their consumption
  • Departing customers pay a severance fee
  • Complete recovery by Dec. 31, 2001
  Consumer Protection & Public Good
  • Industrial and other large customer rates frozen at current levels until CTC recovery complete
  • Divestiture of generation assets by IOUs “requested”—began Dec. 1996
  • Rate cap is provided
  • Program for low-income service will continue to be funded at not less than present levels
  • Public Utility Commission registration required of all suppliers
  • PUC will provide price notices
  • PUC will attend to customer complaints
  • ISO is responsible for enforcement of environmental protection



Rhode Island

  Legislative Action
  • Enacted August 7, 1996
  Time Line
  • Gradual phase-in with complete customer choice by July 1998 or sooner if 40% of New England has customer choice beforehand
Market Structure  
  • Electric power generation and transmission will continue to be coordinated and monitored by the New England Power Pool (NEPOOL)
  • NEPOOL will perform ISO function in Rhode Island
  Power Exchange
  • Minute by minute decisions of power dispatch are carried out by the New England Power Exchange (NEPEX)
  • NEPEX is a division of NEPOOL
Key Issues  
  Stranded Costs
  • 12.5 year recovery period
  • Stranded costs recovered through a declining transition charge
  Consumer Protection & Public Good
  • Distribution systems to be operated separately from generation (functional unbundling of services by IOUs)
  • State-subsidized rate for low-income customers will remain unchanged




  Legislative Action
  • Adopted December 24, 1996
  Time Line
  • Four year transition and “phase-in” period
  • Includes time for possible pilot program
  • Complete transition by January 1, 2000
Market Structure  
  • Creation of an ISO is “encouraged”
  • Coordination of final system assigned to an ISO or “its functional equivalent”
  Power Exchange
  • NO MENTION of a PE or similar device to provide a market mechanism for deregulated power
Key Issues  
  Stranded Costs
  • Public Utility Commission will determine the level of “transition or stranded costs for each utility and [will] provide a mechanism, the competitive transition charge, for recovery of an appropriate amount of such cost”
  • Stranded costs determined on a net present value basis over the life of the asset
  • Recovery contingent on utility efforts to mitigate them as reviewed by the PUC
  • “Transition bonds” tied to future cash flow of the asset could be used to stretch recovery period
  • Transition charge will not shift cost between customer classes
  Consumer Protection & Public Good
  • Rate cap for a period of 54 months or until transition cost recovery is complete, whichever is shorter
  • Required operational unbundling of services reflected in tariffs and customer bills
  • Public Utility Commission can permit the divestiture of generation assets by utilities
  • Universal service is ensured. Continuation of subsidies for low-income customers
  • NO provision on renewable energy resources



Glossary of Terms

Wheeling: The transmission of electricity through a third party transmission system connecting suppliers and consumers in different states.

Independent System Operator (ISO): Independent System Operator controlling the transmission function of providing electric power service connecting power producers to local distribution networks.

Power Exchange (PE): The market for the competitive sale of electric power.

Stranded Investment or Stranded Costs: The sunk cost of investments in generation facilities (power plants), or other aspects of providing electric service, by utilities which has not been yet been recovered through regulated rate-setting procedures. Investments become “stranded” when a power plant, which has not been fully paid for, becomes an “uneconomic” asset due to competition.

Public Services: Services rendered under regulatory obligations to provide universal electric service, environmental protection and energy conservation.

Unbundling of Services: Electric power service consists of three primary functions: Generation, Transmission and Distribution. Privately owned utilities typically control all functions and charge a single government regulated price for this “bundled” service. Deregulation separates these functions, introducing competition into the generation element and separate pricing for each function.

Market Competition: In the electric power industry this refers to the generation element of electric service where produced power is bought and sold competitively and ultimately delivered to the end-user through regulated transmission and distribution networks.

Integrated Transmission System (ITS): Georgia’s system of shared ownership, planning and operation of an integrated transmission system for 97 electrical suppliers in the State.

Cameron Meierhoefer and Melissa Kelman are graduate students in the School of Public Policy at Georgia Tech. Their issue brief was written under the supervision of Professor William Read. The Georgia Public Policy Foundation is an nonprofit,  nonpartisan research and education organization dedicated to keeping all Georgians informed about their government and to providing practical ideas on key public policy issues. The Foundation believes in and actively supports private enterprise, limited government and personal responsibility. Nothing written here is to be construed as necessarily reflecting the views of the Georgia Public Policy Foundation or as an attempt to aid or hinder the passage of any bill before the U.S. Congress or the Georgia Legislature.

© Georgia Public Policy Foundation (June 12, 1997). Permission is hereby given to reprint this article, with appropriate credit given.