4. A. Georgia’s Electric Industry

Three types of electric utilities provide retail electric service in Georgia. These include investor-owned utilities, customer-owned utilities (cooperatives) and government-owned utilities (municipals). There are two investor-owned utilities, Georgia Power Company (GPC) and Savannah Electric and Power Company (Savannah Electric). Both of these are operating subsidiaries of Southern Company. Southern Company Services, another Southern Company subsidiary, operates the Power Control Center in Birmingham, Alabama, which coordinates the integrated operations of the Southern electric system, including generation and transmission facilities in Georgia. There are 42 Electric Membership Cooperatives, 39 of which distribute power received from Oglethorpe Power Corporation (OPC) while the remaining three distribute power received from the Tennessee Valley Authority (TVA). There are 47 cities and one county (Crisp County) that are members of the Municipal Electric Authority of Georgia (MEAG). There are other municipals, not members of MEAG, that also provide service to customers at the retail level. These include the City of Dalton, the City of Hampton, the City of Acworth and the City of Chickamauga.5 Georgia has an Integrated Transmission System, jointly-owned by Georgia Power Company, Oglethorpe Power Corporation, MEAG, and the City of Dalton. Each of these organizations is discussed below.


Georgia Power Company

Georgia Power Company (GPC), the largest electric utility in Georgia, is an operating subsidiary of Southern Company. GPC has a total of 14,367 megawatts of generating capacity. Its generation mix is comprised of approximately 74.3% coal, 22.4% nuclear, 2.7% hydro and 0.6% combustion turbines. GPC wholly owns numerous generating facilities and co-owns other generating facilities with OPC, MEAG, the City of Dalton, and Savannah Electric.6 GPC has wholesale contracts for capacity and energy with cogenerators and other providers both within and outside the State of Georgia.7

As of December 1996 Georgia Power Company served 1.7 million customers and provided electric service in all but six of the state’s 159 counties. The overall average price paid by all customer classes in 1996 was 6.15 cents per kilowatt-hour.8 GPC’s December 31, 1996 FERC Form No. 1 indicated operating revenue of $4,415,615,956 and total assets of $13,508,046,332.


Savannah Electric and Power Company

Savannah Electric, part of the Southern Company since 1988, is an investor-owned utility regulated by the Commission. Savannah Electric serves customers in five counties located in Southeast Georgia. These include Chatham, Effingham, Bryan, Bulloch, and Screven County. As of December 1996 Savannah Electric served 120,448 customers at an overall average rate of 6.40 cents per kWh.9

Savannah Electric has a total generating capacity of 840 megawatts. Their generating mix consists of 74% coal and 26% combustion turbines.10 They also contract for capacity with the City of Savannah and purchase energy from a number of cogenerators. Savannah Electric’s December 31, 1996 FERC Form No. 1 indicated operating revenue of $ 225,919,194 and total assets of $ 564,257,221.


Southern Electric System

Southern Company is a utility holding company with five electric utility operating subsidiaries that provide electric service in four southeastern states: Georgia Power Company and Savannah Electric and Power Company in Georgia; Alabama Power Company; Gulf Power Company in Florida; and, Mississippi Power Company. The geographic area served by these utilities constitutes the Southern Control Area. Southern Company Services, Inc., an affiliated company, operates the Southern electric system from Southern Company’s William R. Brownlee Power Control Center (PCC) in Birmingham, Alabama.


The PCC was established to provide integrated and coordinated operation of the generation and transmission systems of Southern’s operating companies. Using the guidelines established by the Operating Committee in the Intercompany Interchange Contract (IIC), the PCC is responsible for coordinating the operation of the bulk power supply resources. Its objectives are to supply the territorial power requirements of the respective service areas of the operating companies at the lowest practical cost consistent with a high degree of reliability of the bulk power supply, and fulfill the interconnected contractual agreements with non-associated utilities.

The scope of the Power Coordination Center’s responsibilities consists of the following:

  1. Unit Commitment—Determine the appropriate set of generating units and other power supply resources required to economically meet projected integrated system demand on a daily basis.
  2. Economic Dispatch—Determine the desired loading of the generating units and power supply sources connected to the integrated system.
  3. Common Interchange—Implement the interchange of power with the non-associated companies that are interconnected with the Southern electric system.
  4. Bulk Power Transmission Security—Evaluate the security (reliability) of the bulk power transmission system (500 kV, 230 kV and all interconnections) and concur on actions required to ensure its integrity under first contingency conditions.
  5. Maintenance Outage Coordination—Coordinate the unit maintenance outage requirements of the operating companies, including any auxiliary equipment which could curtail unit capacity, in such a way as to minimize cost to the system.
  6. Record Keeping – Maintain specified operating data and records.

All major utility systems in the eastern half of the United States and Canada (except in Texas) are interconnected and operated synchronously as part of the Eastern Interconnection—an interconnected grid of roughly 700,000 MW capacity. Within the Southern electric system generation is economically dispatched to meet resources without regard for operating company boundaries. Power flows are scheduled and controlled between the Southern electric system and non-associated companies. The Southern Company complies with FERC requirements and operational guidelines established by the North American Electric Reliability Council (NERC).

Interchange between independent utilities is regulated by the FERC, which regulates pricing and contract administration pursuant to the Federal Power Act. All Southern Company contracts must be filed with FERC. Standard practices and operating procedures are set forth by NERC, a voluntary organization of utilities that sets standard and practices for the industry. NERC’s Operational Guidelines are observed by all utilities.

The Southern electric system acts as a tight pool with the PCC at Southern Company Services, Inc. acting to provide integrated and coordinated operation of the system. A power pool is a group of interconnected utilities that act together in a closely coordinated manner to enhance reliability and economics. Loose pools may coordinate only a few operational functions—typically interchange, spinning reserves and system security—among independent utilities. Tight pools, such as the Southern electric system, share common unit commitment, economic dispatch and interchange functions to maximize reliability while minimizing production costs.

By operating as a pool the Southern electric system derives significant economic and operational efficiencies: (1) Reserve sharing: An independent utility would have to carry reserves equal to its largest unit. A pool also carries reserves equal to its largest single unit, but each pool member carries only a portion of such reserves; (2) Construction staging: Individual utilities must add generation in increments too small to take advantage of the economies of scale. A pool may add generation in larger increments to be shared among several utilities and take advantage of the economies offered by size; (3) Buying power: A pool generally has more clout in purchasing off-system capacity and energy than individual companies; and, (4) Reliability is generally enhanced by pool operations.11


Oglethorpe Power Corporation and the Electric Membership Cooperatives

Oglethorpe Power Corporation (OPC), the nation’s largest electric cooperative, supplies power to 39 of the state’s 42 Electric Membership Cooperatives (EMCs). OPC was created in 1974 by the General Assembly. The EMCs were formed during the 1930s and 1940s to supply electricity to rural customers. Each EMC is customer-owned and self-regulating with rates set by their decision-making entity, the EMC Board of Directors. The Commission’s limited regulatory jurisdiction over the EMCs includes resolution of territorial disputes and approval authority over financing applications. Although the Commission does not approve rates for the EMCs, the EMCs are required to file their rates with the Commission.

Earlier this year OPC reorganized into three separate companies: Oglethorpe Power Corporation, Georgia Transmission Corporation and Georgia System Operations Corporation. Oglethorpe Power Corporation continues to provide power to the member EMCs. The Georgia Transmission Corporation manages OPC’s transmission lines and substations. Georgia System Operations Corporation operates the generating facilities, control room and dispatch of electricity. This reorganization differs from the usual vertically-integrated utility in that it functionally unbundles the major electric services. The three companies are collectively owned by the EMCs. However, each of the three companies has its own separate decision-making board.

Oglethorpe Power supplies energy to the EMCs from 3,338 MW of owned or leased generating capacity. The generating mix includes 37.7% coal, 36.9% nuclear and 2.4% hydro. The remaining energy needs, approximately 23%, are met with purchased power from other utilities. In total, the 39 EMC’s serve 2.6 million customers.


Municipal Electric Authority of Georgia (MEAG) And The Municipals

MEAG is a public generation and transmission corporation, created in 1975 by the Georgia General Assembly. MEAG has assets of $4.7 billion and owns a total of 1,558 MW of generating capacity from facilities co-owned with Georgia Power Company, OPC and the City of Dalton. MEAG supplies electricity to its 48 member municipal electric utilities for distribution to their approximately 635,000 customers. Retail rates for each municipal are set by their respective governing body, e.g., the city council or mayor. The Commission has limited jurisdiction over municipals. However, they are required to file their rates with the Commission.


Tennessee Valley Authority (TVA)

Parts of extreme northern Georgia are supplied electricity by TVA. TVA is a federally-owned electric power system supplying power through five separate distribution systems in Georgia: Blue Ridge Mountain EMC; North Georgia EMC; Tri-State EMC; the City of Chickamauga; and, the Electric Power Board of Chattanooga. Approximately 117,000 customers in ten North Georgia counties are served by these distribution systems which have long-term, all-requirements wholesale power contracts with TVA. TVA also serves as the regulator of these distribution systems and has authority over rates and other matters for these distributors.

Congress established the TVA electric service territory through the Tennessee Valley Authority Act, as amended in 1959. In defining the service area, Congress included a prohibition on the sale of TVA generated power by either TVA or a TVA distributor outside the TVA boundary. The Georgia Territorial Act of 1973 allows other utilities in Georgia to compete for new loads above 900kW demand in the TVA distributors’ service territory while TVA distributors are federally restricted from competing for similar customers in other suppliers’ service areas.12


Other Suppliers

The cities of Acworth, Chickamauga, Dalton and Hampton are not members of MEAG Power. These municipalities purchase electricity on the wholesale market from MEAG, TVA, Georgia Power and others. Other suppliers exist in Georgia who currently sell, or will soon sell, energy and capacity in the wholesale electric market. These include Independent Power Producers (IPPs), such as Hartwell Energy and U.S. Generating, and numerous Qualifying Facilities (QFs), such as cogenerators and small power producers. These facilities are capable of producing in excess of 1000MW of capacity and may provide in-state competition in a future competitive retail market.13


Integrated Transmission System

Currently, Georgia Power Company, Oglethorpe Power Corporation, MEAG and the City of Dalton jointly own the majority of Georgia’s transmission system. Savannah Electric is connected to the Integrated Transmission System through an interface but does not have any financial investment in the system. In January 1975 Georgia Power Company entered into separate contracts with each of the other utilities, selling them ownership interests and equal access to the transmission facilities.

Several factors led to the creation of the Integrated Transmission System (ITS). During the early 70’s OPC, MEAG and the City of Dalton purchased generating capacity from Georgia Power Company. These companies also purchased ownership interest in the transmission system. This made it possible to receive energy from the generating plants in which they had purchased an ownership interest. The creation of the ITS avoided the duplication of transmission facilities that otherwise would have occurred among the Georgia utilities transmitting power to serve their respective customers. With a jointly-owned integrated facility, Georgia utilities have access to over 16,000 miles of transmission line.

The ITS is a $3.4 billion investment that is used primarily to serve Georgia load. It is interconnected with neighboring utilities through transmission tie lines. These ties allow utilities to transfer power from one system to another. The ties also allow Georgia utilities to purchase power from neighboring utilities when it is less expensive than operating their own units. It also allows the utilities to sell and transmit any excess power they may have available.

At the local level, the ITS is operated by Georgia Power Company through two Transmission Control Centers (TCC). The TCCs are the system operations agents for all of the owners of the ITS. One TCC is located in the northern region of the state, while the other is located in the southern region. The Transmission Control Center monitors bus voltage, transmission line loading and network status throughout the ITS. The TCC also reviews maintenance outage requests from the ITS owners to see if the transmission system can withstand any single contingency during scheduled maintenance activities. The ITS is located within the Southern Company Control Area and Southern Company Services is responsible for operating the control area in compliance with NERC and SERC guidelines.14

A Joint Committee, comprised of two members from each of the owners of the ITS, was established in August 1976. The Joint Committee, along with three subcommittees, make up the decision-making body for the ITS and are responsible for changes, additions and improvements to the transmission facilities. This body ensures that the system can handle current and future loads of the co-owners and that tie lines with neighboring utilities are adequate. The Joint Committee also ensures adherence by all parties to the ITS Agreements.

The existence of a fully integrated transmission system in Georgia allows the owners of this system to compete for customer choice loads provided by the Georgia Territorial Act. The ITS has made it economically feasible for limited competition to exist in Georgia for the past 20 years.

Although the transmission system is defined as jointly-owned, each transmission facility has a single owner. Each utility is responsible for maintaining its own facilities and develops separate maintenance standards for its respective facilities. These standards make no distinction between the facilities that serve the owner and the facilities that serve the other ITS participants. The cost of maintenance is the responsibility of the owner of the facility.

As of December 1996 the ownership investment percentages in the Integrated Transmission System were Georgia Power Company 66.48%, Oglethorpe Power Corp. 23.43%, MEAG 8.68%, and the City of Dalton 1.41%. The utility’s percentage investment in the system is equal to its peak load ratio. If the utility’s investment is not equal to its load ratio, it can consider the purchase or sale of transmission facilities from or to another co-owner.

In the event that a utility has more invested in the system than is required, then the under-invested utility is required to pay the over-invested utility the amount of the over-investment multiplied by the higher of the two utilities’ carrying charge. However, paying this amount does not confer any ownership interest in the facilities.

The ITS arrangement, which has existed for more than 20 years, is unique to Georgia. The ITS allows Georgia utilities access to power delivery systems for buying and selling available wholesale electric energy both within and outside of Georgia. This helps reduce energy prices in Georgia while minimizing the impact on the physical environment. The ITS enabled joint transmission services to be offered in Georgia years ahead of the recent federal initiative, creating transmission open access at the wholesale utility business level on a regional and national basis.

It remains to be seen what impact a federal retail access mandate may have on the ITS. If competition is not federally mandated, but increased competition is brought about through amendments to the Georgia Territorial Act, it may be advantageous to keep the ITS, or some variation of the ITS, in place.  


4. B. Regulatory Entities and Statutes Affecting the Electric industry


The Georgia Public Service Commission

Duties and powers of the Georgia Public Service Commission (Commission) extend to electric light and power companies, or persons owning, leasing or operating public electric light and power plants furnishing service to the public.15 The Commission has exclusive power to determine just and reasonable rates and charges to be made by any person, firm or corporation subject to its jurisdiction. Georgia Power Company and Savannah Electric are the two investor-owned electric companies under full Commission rate-making jurisdiction. The Commission has limited authority with respect to cooperatives or municipals, who must file their rate with the Commission. The Commission approves the issuance of certain EMC bonds and notes and enforces rules and regulations to provide electric service to an EMC’s members. Where EMCs receive financial support from the federal Rural Utilities Service (RUS) agency, RUS guidelines and Commission approvals exist to help assure that all financial requirements are met. The Commission also has certain authority granted under the Georgia Territorial Electric Service Act.16

Currently, the Commission’s authority over investor-owned utilities includes regulation of bundled rates for generation, transmission, distribution and other costs necessary to serve the retail customer. If retail generation is opened to competition, it is expected that the Commission would no longer set the rates for the commodity portion of electric service; however, the Commission would continue to set rates for distribution and other customer services currently bundled with the commodity charge. In addition, other regulatory responsibilities, such as ensuring the quality of service and fair treatment of customers, would remain.


The Integrated Resource Planning Act

The Commission has responsibility pursuant to the Integrated Resource Planning Act to review and approve supply-side and demand-side resource options filed by the utility companies. The purpose of this certification process is to ensure that energy requirements are met and customers receive safe and reliable electric service. The Integrated Resource Planning Act (IRP Act) was established by the state legislature in 1991.17 The IRP Act resulted from the Commission’s ex post facto reviews of generating plants, such as the Commission’s review of Georgia Power Company’s construction of Plant Vogtle. Prior to enactment of the IRP Act, the Commission did not review a utility’s management decisions pertaining to the need, planning and construction of expensive electric generating facilities until the company applied for financing approval or filed for recovery of these costs in rate case proceedings after the plants were partially built or completed. If planning or construction management decisions were found to be imprudent or if the facility was deemed unnecessary, the Commission could disallow recovery of certain costs.

The IRP Act gave the Commission the authority to review, modify, reject or approve a plan for meeting future energy demands prior to any commitment regarding construction of the facility, contracting for purchase power or the expenditure of large sums of capital. This certification process helps to ensure the energy is needed, gives the utility more certainty in recovery of expenditures and ensures that the source of power with the best value is selected after considering both cost and reliability.

The IRP Act provides for utilities to file a plan at least every three years. The plan must include a 20-year projection of energy requirements and consider the economics of all options available to meet these requirements including supply-side resources, demand-side resources, purchased power and cogeneration. Long-term plans for the type of facility needed, the size, and the required commercial operation date are determined and approved by the Commission. Before construction of a facility has begun or a purchased power agreement is finalized, the Commission must first certify the need for the facility, contract or conservation program, and determine that it is the appropriate type facility based on economic analysis. Once certified, the utility is guaranteed recovery of the actual prudently incurred costs. The IRP Act also provides the Commission a means to ensure that a reliable supply of low cost energy will be available for the long term.

In the past, long range planning and the orderly addition of power facilities to supply a defined service territory have given consumers in Georgia a highly reliable and efficient electric generation, transmission and distribution network. This system has responded well to accidents, natural disasters and rapid growth in customer power demands. The following questions illustrate some of the planning issues which must be resolved or considered prior to legislative alterations to the current regulatory scheme.

This Commission should retain regulatory oversight concerning reliability to ensure that the supply of generation is adequate and system security is not compromised. The manner and extent of this oversight would vary depending upon the market structure and actions of the market participants. Possible Commission roles could be coordinating a long-term planning forum or setting reliability and planning requirements for newly certificated suppliers and for existing suppliers in the generation market in Georgia.


The Georgia Territorial Electric Service Act

Customer choice for new large commercial and industrial customers with a load of 900kW or more has been in place in Georgia for more than 20 years, long before the national debate on electric industry restructuring began. The Georgia Territorial Electric Service Act of 1973 (Territorial Act or Act) established territories for serving residential and small commercial customers as well as initiating the customer choice provisions for large customers.25 These legislative and regulatory provisions in Georgia have provided the foundation for an effective electric utility structure.

The Territorial Act was enacted March 29, 1973 to assure the most efficient, economical and orderly rendering of retail electric service within the state, avoid duplication of electric lines, foster the extension and location of electric suppliers’ lines in a manner most compatible with the state’s preservation and enhancement of the physical environment, and to protect and conserve lines lawfully constructed by electric suppliers.

Electric suppliers under the jurisdiction of the Territorial Act are Georgia Power Company, Georgia’s Electric Membership Cooperatives (42 EMCs), Municipal Electric Authority of Georgia (MEAG), Savannah Electric and Power Company, North Carolina’s Haywood EMC and Tennessee’s Electric Power Board of Chattanooga.

Under the Territorial Act, every geographic area within the state was either assigned to an electric supplier or declared unassigned as to any electric supplier by the Commission. Customers with connected loads of less than 900kW (about the size of a modern grocery store) must take electricity from the franchised supplier. However, if any customer with a load of 900kW or more locates within the corridors of an electric supplier’s lines, that customer may have a choice of suppliers. Once a customer chooses a supplier, the Territorial Act provides that the chosen electric supplier has the exclusive right to serve that customer for the life of the premises.26

Georgia Power Company estimates that since enactment of the Territorial Act, approximately 2,800 large and small customers throughout the state have been able to choose their electric supplier when locating new facilities in Georgia. Georgia electric suppliers compete for about 500 MW of load each year.

The Territorial Act was the result of a compromise negotiated by all of the electric suppliers doing business in the State of Georgia during the early 1970s. A 900kW level was agreed upon as the load threshold for customer choice. This load level was chosen because a 900kW load was considered sufficient to justify the economics of the investment necessary to serve the load and foster competition for that load.

Some advantages of the current structure have been to produce extremely reliable electric service and provide that service at prices that are reasonable when compared to many other states and the nation as a whole. While some parties believe that the Territorial Act has worked well to foster competition, others believe the Territorial Act should be repealed and the market should be allowed to develop as it will.

Still others believe that competition could be increased by modifying the Territorial Act. This could be accomplished by reducing the 900kW threshold exemption and by allowing existing customers to renegotiate contracts after a specified period of time. While increasing competition this would limit the competitive choices to those suppliers currently providing retail electric service within the State of Georgia. If retail access is mandated by the federal government, this scenario may or may not be acceptable since it could prohibit out-of-state suppliers from providing retail generation service in Georgia. This scenario could also cause duplication of distribution facilities at levels that may or may not be cost-effective, which the Territorial Act had intended to mitigate. For these reasons competition at levels below the 900kW threshold exemption should be restricted to generation services and not for the extension of distribution facilities. Changes to the Territorial Act that impact generation services may be appropriate, whereas changes that affect territorial assignments or exemptions for transmission and distribution services may not.

The participants at the workshops and in the focus groups reached a general consensus for restructuring the electric industry. The consensus was that, if generation was opened to competition, territorial assignments for distribution lines should be kept and distribution service should remain as a state regulated service. Transmission services would be regulated by the FERC. For this consensus model to work access to the distribution system must be granted to all suppliers. Any access charge should be the same for all customers connected to that distributor.

Under the Georgia Territorial Act, all utilities are now permitted to compete for new load over the 900kW threshold, even if the load is not located in their service territory. This has allowed competing utilities to "cherry-pick" large industrial customers in the TVA distributors’ service territory, while TVA distributors are federally restricted from competing for similar customers in other suppliers’ service areas. These conflicting laws have created an inequitable situation with an artificial boundary to fair, bilateral competition.

Consideration should be given to how the TVA regulatory role will relate to that of the State of Georgia, and particularly: (a) how the State of Georgia should address the impact of the Energy Policy Act of 1992 upon the transmission obligations of TVA; (b) how the State of Georgia would contemplate dealing with any changes in federal law that would affect TVA and the distributors of TVA power as to any territorial restrictions upon the sale or resale of electric power within the TVA region; and (c) how the State of Georgia would equitably provide for fairness to the ratepayers of the TVA distributors in Georgia, given the all-requirements long-term contracts with TVA and the applicable federal law.27


Federal Energy Regulatory Commission (FERC)

The Federal Energy Regulatory Commission was created by the Department of Energy Organization Act on October 1, 1977 to replace the Federal Power Commission. The FERC’s legal authority comes from the Federal Power Act of 1935, the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, the Public Utility Regulatory Policies Act of 1978, and the Energy Policy Act of 1992.

FERC oversees wholesale electric rates and service standards, as well as the transmission of electricity in interstate commerce. The FERC ensures that wholesale and transmission rates charged by utilities are just and reasonable and not unduly discriminatory or preferential. It also reviews utility pooling and coordination agreements.

In addition, the FERC oversees the issuance of certain stock and debt securities, assumption of obligations and liabilities, and mergers. The FERC reviews the holding of officer and director positions between top officials in utilities and major firms supplying electrical equipment to the power companies and underwriting securities.

Finally, FERC reviews rates set by the federal power marketing administrations, such as the Tennessee Valley Authority, makes determinations as to exempt wholesale generator status under the EPAct, and certifies qualifying small power production and cogeneration facilities.


Rural Utilities Service (RUS)

The Rural Electrification Act of 1936 established the Rural Electrification Administration (REA) in the U. S. Department of Agriculture to provide affordable electric service to rural communities. Early investor-owned utility companies, located in large and moderately-sized cities, could not profitably provide service to less populated rural areas. REA offered low cost loans to encourage groups in rural areas to start customer-owned utilities to provide electric service for their members.

The Rural Electrification Loan Restructuring Act of 1993 amended the 1936 Act. The Rural Utilities Service (RUS) replaced the REA and makes loans and loan guarantees to non-profit rural electric cooperatives. These loans finance the construction, operation and improvement of electric facilities. The loan program offers the incentive of low cost financing to ensure continued reliable service to rural areas in Georgia and throughout the country.


4. C. The Regulatory Compact

Any effort to restructure the electric industry in Georgia will be complicated by the mix of regulatory schemes that have developed over the years. Three different regulatory paradigms are in place—one for each of three main categories of suppliers—investor-owned utilities (IOUs), electric membership cooperatives (EMCs), and municipal suppliers. The investor-owned electric utilities in Georgia are rate base/rate of return regulated by the Commission for all sales to the end user, i.e., retail sales. Municipal’s and EMC’s prices are not rate regulated by the Commission; however, the Commission administers the Territorial Electric Service Act that applies to all distribution companies. All suppliers are regulated by the FERC for sales for resale, i.e., wholesale transactions. Each of the three types of supplier operates under a different "regulatory compact":

  1. The vertically-integrated Southern Company through its Georgia subsidiaries, Georgia Power and Savannah Electric, has a regulatory compact with the Commission and the FERC. In exchange for a commitment to serve their area (Obligation to Serve and Universal Service) with electric energy at reasonable rates, the operating companies are given a reasonable opportunity to recover all prudently-incurred costs including a comparable return on capital invested in plant used in the reliable production and delivery of electric energy. Prices are set through rate base/rate of return regulation to achieve the level of revenue required to cover the utility’s operating and capital costs;
  2. The municipals have a regulatory compact with their own citizen customers. MEAG is a generation and transmission company serving the member municipal systems. Since the municipals are government-owned, ultimate regulation is by the citizens through the political process. The Commission has no rate regulation over the municipal systems; and
  3. The EMCs have a regulatory compact with the RUS (formerly the REA) to provide universal service in exchange for low cost loans. Since the customers are the owners, there is no rate regulation of the cooperatives. Any profits above the required margins are returned to the customer/owners as capital credits after a period of time. Oglethorpe Power Corporation is the generation and transmission cooperative serving the distribution cooperatives.

The most recent paradigm shift has been to replace a regulated monopoly with a competitive generation market, based on the theory that a competitive market is the most efficient in allocating resources for the production of goods and services. A number of industries have been restructured and made more competitive, including the electric industry. The FERC is committed to a competitive wholesale market for electricity. Some states have restructured to allow competitive retail markets. People expect lower prices or better service, or both, from a competitive supplier or they take their business elsewhere. As with other industries, these expectations may or may not be met. Of particular concern is the universal availability of electric power. Virtually every person has electric power in Georgia. Competitive markets, however, tend to serve only the more profitable markets or charge higher prices to serve high-cost areas. In the electric industry, the unprofitable customers are those with low usage and those in remote locations. The regulatory compacts have resulted in universal service, reasonable prices and a safe, reliable and adequate supply of electricity in Georgia. A restructured electric industry must build upon the strengths of the current system.


4. D. Status of Electric Industry Restructuring in Other States

The electric industry is rapidly changing. During the next five years the electric power industry will experience many changes and uncertainties. Some states are taking an aggressive approach to competition and moving quickly to make changes in their electric markets by approving comprehensive restructuring plans. Others are taking a slower approach and are establishing timetables to phase-in competition over a period of several years. Many states are still in the early stages of discussing and studying the impacts of restructuring.

There is significant variation in the reasons why states are restructuring their electric industry. Many states would like to reap the perceived benefits of competition. Some states with electric rates far in excess of the national average have restructured, including California, New Hampshire, Pennsylvania and Rhode Island. Rate reductions are mandated under some of the restructuring plans adopted to date. Other states wish to improve economic conditions by attracting industry and jobs. Still others believe that competition is inevitable and do not want to be forced into a federally-mandated, "one-size-fits-all," model. They would prefer to restructure their electric industry to accommodate their state’s unique circumstances. For example, the State of Washington, where the rates are below the national average, is seriously considering restructuring and Oklahoma and Montana with low electric rates have already passed restructuring legislation.

Ten states have passed various forms of legislation that allow some retail wheeling.28 The most recent states to adopt legislation include Nevada, Maine, Oklahoma, Montana, Massachusetts and Illinois. Eleven states have implemented retail pilot programs, for example, Illinois, New Hampshire and Massachusetts. Twenty-one states have adopted principles or guidelines. Some states have allowed the recovery of stranded costs and have established an independent system operator, including California.29


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5Memorandum of Municipal Electric Authority of Georgia, Docket No. 7313-U, March 20, 1997 and Written Comments of Georgia Power Company, Docket No. 7313-U, March 20, 1997.
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6A list of generating facilities owned by GPC and a list of jointly-owned facilities are included in Appendix D, List of Generating Facilities, on page 98 of this report.
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7Georgia Power Company, 1997 Facts and Figures.
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8Georgia Power Company, 1996 Annual Report.
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9Savannah Electric and Power Company, 1996 Annual Report.
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10A list of Generating Facilities owned by Savannah Electric is included as Appendix D List of Generating Facilities, on page 98 of this report.
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11"Power Pooling in the Southern Electric System," Raymond L. Vice, Bulk Power Operations, Southern Company Services, Inc.
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12Comments submitted by the Tennessee Valley Public Power Association, Docket No. 7313-U, March 1997.
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13Approximate Capacity Ratings: Hartwell Energy has 300MW; U.S. Generating has 475MW; and Mid Georgia Cogen. has 300MW.
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14NERC is the North American Electric Reliability Council and SERC is the Southeastern Electric Reliability Council.
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15O.C.G.A. 46.
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16See Georgia Territorial Electric Service Act on page 24 of this report.
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17O.C.G.A. 46-3A et seq.
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18Comments submitted by the Tennessee Valley Public Power Association, Docket No. 7313-U, March 1997.
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19"Retail Competition in the U. S. Electricity Industry," A Special Report by the Electricity Consumers Resource Council, June 1994.
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20Comments submitted by U. S. Generating Company, April 1997.
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21GPSC Electric Workshop "Presentation of Conclusions, and Development of Plan of Future Action" Statutory Changes Focus Group Report, July 1997.
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23Comments submitted by the Tennessee Valley Public Power Association, Docket No. 7313-U, March 1997.
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          25O.C.G.A. 46-3-1 through O.C.G.A. 46-3-15
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26O.C.G.A. 46-3-1, Allocation of Territorial Rights to Electric Suppliers.
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27Comments submitted by the Tennessee Valley Public Power Association, Docket No. 7313-U, March 1997.
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28A listing of the status of restructuring in the 50 states and the District of Columbia as of November 1997 is included in Appendix E, Status of Restructuring in the United States, on page 102 of this report. NRRI, Electric Industry Restructuring Box Score; GDS Associates, Inc., Report on State Restructuring; Brubaker & Associates, Inc., "Industry Restructuring Newsletter."
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29National Regulatory Research Institute's (NRRI) Electric Industry Restructuring Box Score, GDS Associates, Inc.’s Report on State Restructuring, Brubaker & Associates, Inc.'s, Industry Restructuring Newsletter, Workshop Transcript.
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