Subject 515-3-4 INTEGRATED RESOURCE PLANNING

Rule 515-3-4-.01 Commission Authority and Scope of Provisions

Consistent with Official Code of Georgia Annotated (O.C.G.A.) Section 46-3A (H.B. 280), each electricity supplier (hereinafter "utility") in the state of Georgia whose rates are fixed by the Public Service Commission (hereinafter "Commission") shall be required to develop and file for review and approval by the Commission integrated resource plans and applications for certificates and amendments for construction or sale of electric plants, long term power purchases (including purchase or sale of existing power plants), and expenditures for demand-side capacity options as described by these regulations. These regulations establish guidelines for the development and submission of plans and certificate applications and amendments, including the solicitation, evaluation and approval of purchased power as among the potential supply-side options, and provide for the periodic review of each utility's integrated resource plan and capacity resource construction projects and implementation programs. Interim plan monitoring is established through reporting requirements.

(2)

The Commission will approve the utility's integrated resource plan, approve it subject to stated conditions, approve it with modifications, approve it in part and reject it in part, reject the utility's resource plan, as filed, or provide an alternate plan, upon determining, after a hearing is conducted, that this action is in the public interest.

(3)	Notwithstanding the provisions of paragraph 515-3-4-.01(2), above, failure to substantially comply with the provisions of this chapter may result in summary rejection of an applicant's plan. Such rejection may be without prejudice to the refiling of the application.

(4)	These rules shall not be construed to apply to any matters prior to the effective date of O.C.G.A. Section 46-3A.

Rule 515-3-4-.02 Definitions

(1)	Allowance: Authority to emit one ton of sulfur dioxide, as set forth in the Clean Air Act Amendments of 1990 (PL 101-549), at Title IV.

(2)

Avoided Cost: The cost over a future period to the electric utility of marginal energy and capacity from a utility supply-side resource for which an alternative resource may be substituted. Avoided costs shall be reported by season and time-of-day if variations are sufficient to warrant such time-differentiation. Avoided costs shall be as determined by current Commission policy.

(a)

The direct avoided cost, for the purposes of developing the integrated resource plan shall consist of:

1.	Avoided generating capacity cost, adjusted for transmission and distribution losses and reserve margin requirements.

2.	Avoided transmission and distribution system capacity cost; and

3.	Avoided energy cost, adjusted for transmission and distribution system losses.

(b)

The total avoided cost, for use in the societal cost test for the purposes of developing the integrated resource plan shall consist of:

1.	The direct avoided cost defined above;

2.	Avoided externality costs which have been monetized or considered through an adder (5%) or as otherwise determined by this Commission associated with a utility supply-side resource; and

3.	Other avoided costs and benefits which have not been monetized, including an adjustment for risk associated with a utility resource.

(3)

Capacity Factor: The ratio of the net energy produced by a generating facility to the amount of energy that could have been produced, in the absence of any scheduled or unscheduled outages, in any selected time period. Net capacity factor equals net power generation in the period divided by the product of [number of hours in the period and net dependable capacity], where net power generation is gross station output less in-station electricity consumption.

(4)	Capacity Resource: An electric plant, a long-term power purchase, or a demand-side capacity option.

(5)	Clean Air Act Amendments of 1990 ( PL 101-549): All titles of the amended Clean Air Act, subsequent rules and amendments, future revisions to the Act, and future federal legislation related to air quality.

(6)

Cogeneration: Production by a Qualifying Facility of electricity which the utility is required to purchase or in some instances carry over its transmission facilities as defined in and pursuant to the Public Utility Regulatory Policies Act of 1978, at 16 U.S.C. Section 796. An entity providing electricity from its Qualifying Facility is a cogenerator.

(7)	Commission: Georgia Public Service Commission.

(8)

Construction: The clearing of land, excavation, or other substantial activity leading to the operation of an electric plant other than planning, land surveying, land acquisition, subsurface exploration, design work, licensing or other regulatory activity, contracting for construction, or environmental protection measures and activities associated therewith.

(9)	Customer (or participant) Cost: The incremental cost to the customer(or to any person or entity, other than the utility serving the customer), for a demand-side measure.

(10)

Demand-side Capacity Option: A program for the reduction of future electricity requirements the utility's Georgia retail customers would otherwise impose, including, but not limited to energy efficiency and energy management options (together known as demand-side resources), and cogeneration and renewable resource technologies. (Cogeneration and technologies are generally included among supply-side resources because they add to the total amount of electrical energy produced by society).

(11)	Demand-Side Measure: Any hardware, equipment or practice which is installed or instituted for energy efficiency or energy management purposes.

(12)	Demand-Side Program: A utility program designed to implement demand-side measures.

(13)	Demand-Side Resource: A resource that reduces the demand for electrical power or energy as a result of applying demand-side programs to implement one or more demand-side measures.

(14)	Direct Costs: These are costs which are paid directly by the utility, the customer, or a third party and include such items as the cost of demand-side management equipment and programs, fuel and operating and maintenance costs, and generating, transmission, and distribution equipment.

(15)

Electric Plant: Any facility, or portion of a facility, that produces electricity, or is intended to produce electricity, for a utility's Georgia retail customers. Electric plant includes the realty, ancillary facilities, and associated facilities required to interconnect the electric plant with the bulk power supply system.

(16)

End-Use: Light, heat, cooling, refrigeration, motor drive, microwave energy, video or audio signal, computer processing, electrolytic process, or other useful work produced by electricity or its substitute. If equivalent energy-related amenity levels and/or productivity are maintained, the end-use service is considered constant for purposes of these regulations.

(17)	Energy Efficiency: The decrease of power (kilowatt, or "kW") or energy (kilowatt-hour, or "kWh") requirements of participating customers during any selected time period with end-use service held constant.

(18)	Energy Management: The modification of the time pattern of customer energy usage, with end-use service held constant.

(19)

Equivalent Availability: The availability of a generating facility in any selected time period, considering both scheduled and unscheduled, partial and full outages. The equivalent availability factor equals the [service hours plus reserve hours minus equivalent derated hours] divided by the number of hours in the period, where service hours are the hours the unit is electrically connected to the load, reserve hours are the hours the unit is shut down for economic reasons and the equivalent derated hours are the number of forced or scheduled derated hours times megawatt reduction divided by the maximum dependable capacity.

(20)

Exempt Wholesale Generator: Any person determined by the Federal Energy Regulatory Commission to be engaged directly, or indirectly through one or more affiliates as defined in section 2(a)(11)(B) of the Public Utility Holding Company Act of 1935, and exclusively in the business of owning and/or operating all or part of one or more eligible electric generating facilities and selling electric energy at wholesale. A person shall be deemed an exempt wholesale generator who complies with the definition of same under section 32(a) of the Public Utility Holding Company Act of 1935.

(21)

Externalities (or external costs/benefits): Those environmental and social costs or benefits of energy which result from the production, delivery, or reduction in use through efficiency improvements and which are external to the transaction between the supplier (including the supplier of efficiency improvements) and the wholesale (e.g., utility) or retail (e.g., ratepayer) customer. Externalities should be quantified and expressed in monetary terms where possible. Those externalities that cannot be quantified or expressed in monetary terms shall nonetheless be qualitatively considered in the societal cost test to develop resource plans.

(22)	FERC: Federal Energey Regulatory Commission.

(23)

Independent Power Producer: A supplier of electricity from an electric plant that is not directly owned and operated by a utility for servicing its retail customers, and not a utility operating company that sells electricity as part of an affiliated utility operating company system. Independent power producers include non-utility generators and exempt wholesale generators.

(24)

Indirect Costs/Benefits: These are costs which result from utility actions but are not paid directly by either the utility or the customers. Indirect costs include such items as the environmental impacts of air pollutant emissions from power plants, land use disruptions from building power plants and transmission lines, and similar generalized costs. Indirect benefits are benefits which result from utility actions but are not received directly by either the utility or the customers. Indirect benefits include consideration of economic developments, increased tax base and similar generalized benefits.

(25)

Integrated Resource Planning (IRP): A utility resource planning process in which an integrated combination of demand-side and supply-side resources is selected to satisfy future energy service demands in the most economic and reliable manner while balancing the interests of utility customers, utility shareholders and society-at large. In IRP, all resources reasonably available to reliably meet future energy service demands are considered by the utility on a fair and consistent basis. These options include, but are not limited to:

(a)	Options that increase the available supply from, or efficiency of, existing utility facilities, such as plant heat-rate improvements, plant refurbishment and life-extension, transmission and distribution system loss reduction;

(b)	Options that increase the available supply from new utility sources, such as new conventional plants and new advanced technology plants;

(c)	Options that increase the available supply from utility sources, including power pool purchases;

(d)	Options that increase the available supply from non-utility sources, such as cogenerators and independent power producers;

(e)	Options that reduce demands for utility-supplied power and energy through energy efficiency;

(f)	Options that reduce demands for utility-supplied power and energy through energy management; and

(g)	Options that reduce demands for utility-supplied power and energy through the use of alternative fuels.

(26)	Long-Term: Exceeding one year.

(27)	Long-term Power Purchase: Any purchase of electric capacity and energy for a period exceeding one year, the principal purpose of which is to supply the requirements of the Georgia retail customers of a utility. Long-term power purchases are one of several supply-side resources.

(28)	Market Discount Rate: A rate which reflects current customers' after-tax cost of capital. The utility's after-tax cost of capital is one such rate.

(29)	Net Dependable Capacity: The maximum capacity a generating facility can sustain over a specified period of time, as modified for ambient limitations and less auxiliary loads, as reported to the U.S. Department of Energy on Form IE-411 or its successor.

(30)	Participant's Test: The economic test which measures the quantifiable benefits and costs to the customer due to participation in a program.

(31)

Pilot Demand-Side Program: A demand-side program which is implemented on a trial basis by the utility for one or any combination of customer classes for which the demand-side measure, program design, or method of implementation has not yet been proven cost-effective through either the implementation of a pilot program in the utility's service territory or the implementation of a transferable pilot or full scale program in the service territory of another electric utility. Pilot programs are limited in scope as to target population, duration or a combination of these factors.

(32)

Plan: The integrated resource plan, as defined in O.C.G.A. Section 46-3A, filed by the utility pursuant to these regulations, to cover the twenty-year forecast period from the year of filing. The plan will contain the utility's electricity demand forecasts, analysis of all capacity resource options, analysis of alternative system configurations, list of assumptions, and supporting data and information.

(33)	PURPA: The Public Utility Regulatory Policies Act of 1978 including any amendments.

(34)	Rate Impact Analysis: An analysis of the extent to which unit rates for electricity are altered by the implementation of an alternative system configuration.

(35)	Rate Impact Measure Test: The economic test which measures the changes in customer rates as a result of changes in utility revenues and operating costs caused by a program.

(36)

Request for Proposals: A formal written document submitted to potential utility, cogenerator, independent power producer and exempt wholesale generator suppliers, and others seeking proposals to sell supply-side capacity resource(s) in order to supply the requirements of the Georgia retail customers of a utility.

(37)

Screening Tests: The evaluations used to determine which demand and supply-side resource options are eligible for inclusion in the alternative system configurations. The demand-side screening tests may include the rate impact measure test, utility cost test, the participant's test, the total resource cost test and the societal cost test. The primary test for screening supply-side additions will be based upon the present value of revenue requirement over the life of the resource at varying levels of operation or capacity factor.

(38)

Societal Cost Test: An analytical test which identifies resources that provide net benefits considering economic, environmental and social factors. A resource option is cost-effective under the societal cost test when present value life cycle benefits exceed present value life cycle costs, evaluated at the utility discount rate. Total benefits equal the total avoided costs multiplied by the energy/capacity supplied by the resource option, plus any resource-specific benefits not otherwise reflected in the total avoided cost. Total costs equal the total installed cost of the resource option plus its operating costs plus any monetized and non-monetized costs attributable to the option.

(39)

Supply-Side Resource: A resource which can provide for a supply of electrical energy and/or capacity to the utility. Supply-side resources include supply-side capacity options, supplies from other utilities, cogenerators, renewable resource technologies, or independent third parties via existing or new transmission facilities; and the life extension, upgrading, plant refurbishment, efficiency improvement, or capital additions of existing generation, transmission or distribution facilities of the utility.

(40)	System Configuration: A set of demand-side resource options, supply-side resource options, or a combination thereof, which is designed to provide electric service needs over the planning period.

(41)	Total Resource Cost Test: An economic test which measures the "net" costs of a demand-side management program as a resource option based on the total costs of the program, including both the participant's and the utility's cost.

(42)

Transmission facilities shall be generally defined as those having the following general characteristics:

(a)	Transmission facilities are generally network in nature and are interconnected with other transmission systems;

(b)	Power generally flows through a transmission system:

(c)	Network transmission systems serve both native load and external markets through interconnecting with other transmission systems;

(d)	Power flowing on a transmission system may be consumed over a diverse geographic area; and

(e)	Transmission shall be at voltage levels as prescribed ty the FERC.

(43)	Utility: Any electric supplier whose rates are fixed by the Commission.

(44)	Utility Enterprise: A utility, its parent holding company and affiliated companies.

(45)

Utility Cost Test: An analytic test which considers only the direct utility economics of resource options. A resource option is cost effective under the utility cost test when present value life cycle benefits exceed present value life cycle costs, evaluated at a market discount rate. Direct benefits equal the direct avoided costs multiplied by the energy/capacity supplied by the resource option. Direct costs equal the utility cost of installing the resource option plus the utility's operating costs.

Rule 515-3-4-.03 Energy and Demand Forecasting Requirements

(1)

Time Frame of Analysis.

(a)	Historic Data. Energy and demand forecasts shall utilize and report historic data from the three years preceding the filing year when such historic data are available.

(b)	Forecast period. All energy and demand forecasts shall be performed for each year of the twenty-year period beginning with the filing year.

(2)

Contents of Energy and Demand Forecasts.

(a)	Characteristics. The forecasts specified below shall be weather normalized. The methodologies and processes used to normalize for weather shall be fully described and justifiable.

(b)

The load forecast shall include and report the following items for each historic and forecast years including: first, the jurisdictional portion of each utility; second, the utility including sales to Georgia partial requirements and full requirements wholesale, if applicable; and third, the utility including all Georgia retail and wholesale loads for which the utility has planning responsibility, if applicable:

1.	The total annual energy consumption for electricity for the utility and for each of the utility's customer classes;

2.	The total monthly energy consumption for the utility and for each of the utility's aggregate customer classes, for the most recent three years of history and the first three years of the forecast period;

3.	The summer, winter and annual peak demands for each of the customer classes;

4.	The monthly coincident and non-coincident peak demands for each of the customer classes, for the most recent three years of history and the first three years of the forecast period;

5.	Annual load factor; and

6.	Edison Electric Institute load data for the most recent three years, supplied both in hard copy and on a computer disk in ASCII format.

(c)

Analysis and Documentation of Peak Demand and Energy Forecasts. The Forecast documentation shall be the utility's standard forecast documentation which outlines the rationale and pertinent factors used for the utility's own planning purposes. The historic data and forecast of peak demand and energy usage shall include, and shall separately identify and describe the impact on peak demand and energy usage of the following load requirements and resources:

1.	Utility demand-side programs which were implemented before preparing the plan under consideration;

2.	Existing government-sponsored or mandated demand-side programs;

3.	Price-induced substitution of alternative fuels for electricity and vice versa;

4.	Actual and expected interruptible demand, including number of customers and firm capacity contracted for interruption from each customer, and, for historic years, the amount of interruptible demand which was actually interrupted;

5.	Self-generation and cogeneration by existing and future customers, including the number of customers with such capacity, their total capacity rating and, where applicable, the capacity and energy they are contracted to provide; and

6.	Transmission and distribution losses.

(d)

Evaluation of Previous Forecasts. Each utility plan shall contain an evaluation of the previous forecast. The evaluation must assess the accuracy of the previous forecast(s), attempt to explain the deviation between forecasted and actual energy and demand, and describe revisions to subsequent methodologies and assumptions utilized to correct for potential deviations, as appropriate.

(3)

Forecasting Methodology.

(a)

Forecasting Methodology and Determinants. Utility forecasts used in the integrated resource plan filing shall be based on desegregated end-use methods or some other comparable forecasting methodology. The forecast of energy and demand shall identify and describe the significant determinants used in forecasting future peak demand and energy usage. In addition to end-use specifications, each forecast should address the following factors influencing peak demand and energy usage, where appropriate:

1.	Demographics, including population, number of households, household type (e.g., single versus multi-family), employment, and income;

2.	Economic conditions, including gross product of the service area;

3.	Price of electricity and price elasticity of demand for electricity;

4.	The substitution of electricity for and with competing fuels in end-uses, including the rates of penetration and saturation of the market of those end-uses;

5.	The future price of competing end-use fuels;

6.	Behavioral factors which affect energy use by customers;

7.	Energy policies of the state and federal government affecting energy use, both existing and reasonably anticipated; and

8.	Any other factors deemed relevant.

(b)

Each utility energy and demand forecast shall include detailed descriptions of the source of all determinants upon which it relies and shall document and fully justify the procedure by which the determinants were incorporated into the peak demand and energy usage forecasts. The determinants used in forecasting energy and demand must be consistent with and integrated into the different components of the forecast;

(c)

Data Requirements. Utility energy and demand forecasts shall be based on the best available data. Where reliable data are not available, estimates should be used and justified. Each utility shall develop a data base of electricity consumption patterns by customer class and by end-use where applicable (e.g., classes for which end-use data have been collected within the most recent five years). When using end-use forecasting methodologies, each utility shall submit the most current data available on end-use appliance penetration and saturation rates and end-use electricity consumption patterns. Each forecast shall include a detailed description of data used in making the forecast, an identification of the sources of such data, and a detailed explanation of specific techniques employed for gathering, organizing, adjusting, or interpreting the data;

(d)	Econometric Forecasting Methods. Where statistical or econometric methods are used in developing forecast inputs or in the forecasting process, analyses of the reasonableness of such methods and models shall be presented, including computer outputs with parameter estimates; and

(e)	Load research. Each utility shall identify and describe ongoing and planned load research.

(4)

Sensitivity Analyses and Contingency Planning.

(a)	Sensitivity to Major Assumptions. The energy and demand forecast shall include an analysis of the sensitivity of results to the major assumptions and estimates used in preparing the forecasts.

(b)

Sensitivity Planning. Each utility plan must contain a series of demand forecasts sensitivities which represents a reasonable range of electricity sales and demand which its system may be required to serve. The range must include three levels of expected growth based on alternative assumptions of demand determinants, as follows:

1.	A base case scenario should be developed, which incorporates all assumptions that are likely to occur. This case shall be used to project revenue requirements, avoided costs, ceiling prices, and resource blocks;

2.	A high growth scenario; and

3.	A low growth scenario.

Rule 515-3-4-.04 Identification of Capacity Resources

(1)

Existing Resources.

(a)

Assessment of Existing Resources. The utility shall describe all existing resources, including existing power purchases, sales and exchanges, demand-side resources, purchases from non-utility sources, purchases from other utilities, cogeneration, standby generation capacity, interruptible service capacity, pooling or coordination agreements that reduce resource requirements, owned or partially-owned generating facilities, and any other supply-side resources. Any projected changes must be documented. The utility shall also describe all resources available to the utility enterprise, to the extent that these resources affect the resources available to the utility;

(b)

Assessment of Existing Transmission. The utility shall analyze the adequacy of its existing transmission system to determine its capability to serve load over the next ten years, to evaluate the supply-side resource potential of actions to reduce transmission losses, to evaluate the potential impacts of demand-side resources on the transmission network, and to assess the transmission component of the avoided cost;

(c)

The utility must provide a comprehensive Environmental Compliance Strategy ("ECS") that includes a detailed report on the state of current and proposed environmental regulations that may have an effect on the installation of equipment or changes in the operation of electric generating plants, including coal-fired, gas-fired, nuclear and hydroelectric. Included among the items the ECS is to address are existing and proposed regulation of sulfur dioxides, nitrogen dioxides, lead, mercury and other hazardous air pollutants listed in section 112 of the Clean Air Act, particulates, ozone, carbon dioxide, methane, low-level nuclear waste, high-level nuclear waste, as well as water quantity and quality, cooling technologies, and the discharge effluents of coal ash and thermal pollution, as applicable to electric generation. The ECS will evaluate the utility's plans, including technologies and forecasted incremental capital and operation and maintenance expenditures for compliance for the next ten years for existing plants. It will include a section of environmental regulations promulgated since the last IRP, and the status of pending regulations that may have an effect on the installation of equipment or changes in the operation of electric generating plants, including coal-fired, gas-fired, nuclear and hydroelectric. The utility will also provide the citation and procedural status of any litigation (whether in a state or federal court, administrative tribunal, or any other forum) the utility is participating in, either representing itself or as a member of a consortium, that involves challenges to any regulations covered in the ECS.

(d)

Assessment of the Future Potential of Existing Resources.

Each utility shall assess the role of existing demand-side and supply-side resources in meeting future demand requirements. For those resources for which any action other than continued use in its existing condition appears to be cost-effective, the utility shall assess and document the cost and benefit associated with any such action, and justify why such action will or will not be taken. Such assessment with respect to the use of existing supply-side capacity resources must include comparison against the resources offered in response to the utility's Request for Proposals, with the exception of the capacity resources identified in Rule 515-3-4-.04(3)(f);

(2)

Potential New Electric Plant and New Transmission Facilities.

(a)

The utility shall identify and fully describe all potential new utility electric plant options and transmission facilities options for meeting future demand. To the extent practicable and economically feasible, the options considered shall include all technologies and designs which are expected to be available within the twenty-year planning period, either on a commercial scale or on a demonstration scale. The utility shall also fully describe all new electric plant and transmission facilities options available to the utility enterprise to the extent that these resources affect supply-side resources available to the utility;

(b)

The utility shall perform an initial screening utilizing the screening test of all future electric plant options to eliminate those which, upon preliminary evaluation, are not cost effective in relationship to other available electric plant options. These cost-benefit analyses shall be provided in the integrated resource plan for each electric plant option. If the utility eliminates any electric plant options, then each such option shall be identified, and the reason for rejection shall be fully explained and justified; and

(c)

The utility shall submit a comprehensive and detailed bulk transmission plan of the Georgia Integrated Transmission System every three years. The utility shall identify future transmission facilities required to solve the transmission system inadequacies during the next ten years, as identified in 515-3-4-.04(1)(b). The purpose of this analysis is to assure that the transmission network is capable of reliably supporting the loads and resources placed upon it during the next ten years, that costs of the transmission network associated with supply- and demand-side resources are properly considered, that the avoided costs reflect the expected transmission system expansion, and that transmission system loss reduction opportunities are considered as a supply-side resource. Approval or adoption of an integrated resource plan does not constitute approval of transmission facilities for which information is provided under this section. The utility plan shall include at least the following:

1.	An Executive Summary containing an overview of the plan, the results, conclusions and recommendations:

2.	A Section that details all processes, procedures, guidelines and applicable planning standards used in the development of the plan.

3.

A Section that contains a review and analysis of any major outage events in the prior three years, including a discussion of the problem, action taken and any conclusions and recommendations. In addition, a discussion of any significant issues affecting the reliability or adequacy of the transmission system and plans to address them.

4.

A Section that summarizes the results of the long-term analyses of the transmission network by year for the next ten years which would include at least the following:

i.	An overview of the existing integrated transmission system ("ITS") plan for Georgia as a whole and by regions within the State, including interfaces.

ii.	A ten year study of all regional interfaces and their import and export capabilities as defined in the applicable NERC/SERC guidelines, as well as plans for future interconnections and improvements to existing interconnections.

iii.

A ten year plan by year with details of all approved budgeted projects including discussions of the problems, alternatives and the final solutions as well as all forecasted projects including discussions of the problems and proposed solutions. Details of all approved budgeted projects shall include at least the following:

(1)	the expected termination points and length for each new transmission line;

(2)	identification of existing transmission facilities planned for upgrade, rebuilding or retirement;

(3)	the expected design voltage, capacity and in-service date for each new, upgraded or rebuilt transmission facility;

(4)	the approximate cost of each planned expansion or alteration to the transmission network.

iv.	A list of all transmission projects proposed for the 500 kV, 230 kV and 115 kV systems, by year for the next 10 years.

5.	An appendix that contains the Siemens load flow program (PSS/E) data files. The cases to be included are the Summer Contract cases for the 10 year plan period without the proposed fixes and an IDEV file containing the proposed fixes for each year. These files will be provided in electronic format.

6.	Public information regarding preferred sites on the transmission system for the interconnection of new generation.

(d)

The utility shall submit documentation which discusses the following:

1.

A general discussion of the decision making process, criteria, and standards employed at the utility as it relates to resource development and acquisition, including, but not limited to a discussion of the utility's organization, the review and approval procedure, and schedule for resource assessment and acquisition plan preparation;

2.	A discussion which outlines and justifies the general methodological approach taken for resource assessment and selection;

3.	A discussion of the models, methods, data sets and information used by the utility to obtain the results;

4.	A discussion of key assumptions and judgments used in the assessment and how those assumptions and judgments were incorporated into the analyses;

5.

An identification and discussion of those factors (e.g., environmental laws, inflation, customer acceptance) which are most likely to have the greatest impact on the selected system configuration, and those factors that could prevent the successful implementation of the resource acquisition plan as presented;

6.

A discussion and justification of the criteria (e.g., present value of revenue requirements, capital requirements, environmental impacts, flexibility, diversity) used to screen each resource alternative and the criteria used to select the final system configuration presented in the application(s) for certification;

7.	A discussion and justification of why each alternative in the screening analysis was either accepted or rejected for further analysis; and why each alternative was or was not included in the final mix of resource options;

8.	A discussion and justification of the criteria used in determining the appropriate level of reliability and the required reserve or capacity margin, and a discussion of how this determination has influenced the selection of options; and

9.	A discussion of research efforts and/or programs underway or planned which are directed at developing data for future assessments and refinements of analyses.

(3)

Request for Proposals Procedure for Long-Term New Supply-Side Options.

(a)

Notwithstanding language contained in any other rule set forth in this chapter, the following terms shall have the following definitions as used in this Utility Rule 515-3-4-.04(3):

1.	"Commission" means the Georgia Public Service Commission.

2.	"Independent Evaluator" or "IE" means the entity or entities selected pursuant to the RFP Rule to conduct a RFP Process.

3.	"IRP" means the filing ma de by the utility in which it proposes a specific integrated resource plan for adoption/approval by the GPSC.

4.	"IRP Plan" means the specific integrated resource plan adopted by the GPSC for a utility, as may be modified from time to time, and which identifies specific supply-side resource blocks to be added by the utility at specific periods in time.

5.	"PPA Execution Date" means the date on which a power purchase agreement between the soliciting utility and the winning bidder is executed pursuant to a RFP Process.

6.	"RFP" means the notice of a request for proposals distributed to the marketplace by the IE under the RFP Rule identifying the needed resources and the time for providing those resources as set out in the IRP Plan, or any amendment thereto.

7.	"RFP Document" shall mean the collection of materials identified in part IV.4 and distributed to interested bidders and pursuant to which the bids shall be submitted and evaluated during the RFP Process.

8.

"RFP Process" means the preparation and issuance of a RFP and all the activities subsequently associated therewith that are expected to terminate in the execution of a PPA between the soliciting utility and the winning bidder, and in which an Independent Evaluator is selected pursuant to and performs the functions described in this Proposed RFP/IE Structure.

9.	"RFP Rule" means GPSC Rule 515-3-4-.04(3) as amended from time to time, including specifically as amended to adopt the procedures and principles contained in this Proposed RFP/IE Structure.

10.	"RFP Service Date" means that date six months in advance of the date the RFP is expected to be issued, as further described in paragraph II.3.

11.	"Staff" means the Commission Staff assigned to participate in the RFP Process.

(b)

Requirement to use an RFP Process.

1.

For each block of required new supply-side resources identified in the IRP, the utility shall propose a schedule for conducting a RFP Process, including specifically the expected date upon which the RFP shall be issued that solicits each such new supply-side resource along with the amount of capacity required. This information shall be considered public information and made available to all potential bidders.

2.	The RFP Process shall be utilized for every block of required new supply-side resource identified in the IRP Plan, except as provided in Rule 515-3-4-.04(3)(f).

(c)

Role and Selection of an Independent Evaluator.

1.

The IE will be retained by the soliciting entity under a contract that is acceptable to the Commission and which is consistent with the RFP Rule. In order to help assure independence, the IE shall be selected by and report to the Commission. The soliciting entity (i.e., Georgia Power Company or Savannah Electric and Power Company), the Staff and potential bidders may recommend persons or entities to serve as the IE. The Commission shall establish the minimum qualifications and requirements for an IE and shall select the IE pursuant to the selection process described herein. The role and function of the IE in the RFP Process shall be as set forth herein.

2.

Any IE considered by the Commission shall be required to disclose any financial or personal interest involving any soliciting entity or any potential bidder, including but not limited to all substantive assignments for any Southern Company affiliate or any other potential bidder during the preceding five (5) years. The Commission may consider this interest in selecting the IE. The Commission will post on its web site the list of all IE candidates being considered and their statements of interest. The Commission will invite and consider any comments from the soliciting entity and potential bidders concerning the IE candidates prior to the selection of the IE. No IE selected by the Commission may perform services for the soliciting entity or any bidder for a period of two (2) years after the completion of an RFP Process in which the IE served.

3.

The IE shall be retained in time to begin service at least six months prior to the expected issuance of the RFP ("RFP Service Date"). Consequently, the IE selection process identified in paragraphs II.2 and II.3 shall be concluded in time for the IE to begin service as of the RFP Service Date. From the date the IE is selected, no bidder or potential bidder shall have any communication with the IE, Staff, or the soliciting entity pertaining to the RFP, the RFP documents, the RFP process, the evaluation or the evaluation process or any related subjects except as those communications are specifically allowed by this proposed RFP/IE structure or as are made publicly through the IE's website.

4.	The IE will report to the Commission and the Staff. In carrying out its duties, the IE will work in coordination with the Staff and the soliciting entity with regard to the RFP Process as further described herein.

5.	If the IE becomes aware of a violation of any requirements of the RFP Process as contained in the RFP Rule, the IE shall immediately report that violation, together with any recommended remedy, to the Commission.

6.

The IE's fees shall be funded through reasonable bid fees collected by the soliciting entity. The soliciting entity shall be authorized to collect bid fees up to $10,000 per bid to defray its costs of evaluating the bids and, in addition, the soliciting entity may charge each bid an amount which shall be equal the estimated total cost of the IE divided by the anticipated number of bids. To the extent that insufficient funds are collected through this method to pay all of the IE's fees, the soliciting entity shall pay the outstanding cost. Invoices for services rendered by the IE should be sent directly to the Commission for its review. After they are reviewed and approved, the invoices will be forwarded to the soliciting entity for payment, which will be made directly to the IE.

(d)

Affiliate Communications.

1.	Any affiliate of the soliciting entity that intends to submit a bid in response to the RFP, as well as any other persons acting for that affiliate or on its behalf in support of the development and submission of such bid, shall be known collectively as the "Bid Team."

2.	The representatives of the soliciting entity that will be evaluating the bids submitted in response to the RFP, as well as any other persons acting for or on behalf of the soliciting entity regarding any aspect of the RFP Process, shall be known collectively as the "Evaluation Team."

3.

No later than the RFP Service Date, the Bid Team shall be separately identified and physically segregated from the Evaluation Team for purposes of all activities that are part of the RFP Process. The names and complete titles of each member of the Bid Team and the Evaluation Team shall be reduced to writing and filed with the Commission for use by the IE.

4.

There shall be no communications, either directly or indirectly, between the Bid Team and Evaluation Team from the RFP Service Date through the PPA Execution Date regarding any aspect of the RFP Process, except (i) necessary communications as may be made through the IE and (ii) negotiations between the Bid Team and the Evaluation Team for a final PPA in the event and then only after the Bid Team has been selected by the soliciting entity as the winning bid. The Evaluation Team will have no direct or indirect contact or communications with any bidder other than through the IE as described further herein, until such time as a winning bid is selected by the soliciting entity and negotiations for a final PPA have begun.

5.	At no time shall any information regarding the RFP Process be shared with any bidder, including the Bid Team, unless the precise same information is shared with all bidders in the same manner and at the same time.

6.

On or before the RFP Service Date, each member of the Bid Team shall execute an acknowledgement that he or she agrees to abide by the restrictions and conditions contained in paragraphs III.3 through III.5 above. At the PPA Execution Date, each member of the Bid Team shall execute an acknowledgement that he or she has met the restrictions and conditions contained in paragraph III.3 through III.5 above. These acknowledgements shall be filed with the Commission by the Bid Team within 10 days of their execution.

7.

Should any bidder, including the Bid Team, attempt to contact a member of the Evaluation Team directly, such bidder shall be directed to the IE for all information and such communication shall be reported to the IE by the Evaluation Team member. At the RFP Service Date, each Evaluation Team member shall execute an acknowledgement that he or she agrees to abide by the and conditions contained in paragraphs III.3 through III.5 above and, as of the PPA Execution Date, shall execute an acknowledgement that he or she has met the restrictions and conditions contained in paragraphs III.3 through III.5 above. These acknowledgements shall be filed with the Commission by the Evaluation Team within 10 days of their execution.

(e)

RFP Structure and Process.

1.

Identification of Bidders and Design of RFP.

i.

The soliciting entity will provide the Staff and the IE with a list of the companies that have submitted proposals in the three most recent solicitations conducted on behalf of the soliciting entity, as well as a list of all potential bidders to whom notice of those prior solicitations was sent. The soliciting entity shall be responsible for preparation of the final list of potential bidders to whom notice of the upcoming solicitation will be sent.

ii.

The soliciting entity will be responsible for preparing an initial draft of the RFP Document, including RFP procedures, evaluation factors, credit and security obligations, a pro forma power purchase agreement, the inclusion of any "proxy price" agreed to by the Staff and the IE against which the soliciting entity wishes to have the RFP bids tested, and a solicitation schedule. No later than one hundred twenty (120) days prior to the planned issue date of the RFP, the soliciting entity will supply the draft of the RFP Document to the Staff and the IE. These drafts shall be posted on the Commission's website and be accessible through a link established for the use of the IE (the "IE website").

iii.

If the soliciting entity wishes to consider an option for full or partial ownership of a self-build option, the utility must submit its construction proposal ("Self-build Proposal") to provide all or part of the capacity requested in the RFP to the IE at the time all other bids are due. Once submitted, the Self-build Proposal may not be modified by the soliciting entity. Provided, however, that in the event that the soliciting entity demonstrates to the satisfaction of the Staff and the IE that the Self-build Proposal contains an error and that correction of the error is in the best interest of customers and will not be harmful to the RFP Process, the soliciting entity may correct the error. Persons who have participated or assisted in the preparation of the Self-build Proposal in any way may not be a member of the Bid Team, nor communicate with the Bid Team during the RFP Process about any aspect of the RFP Process. The soliciting entity's Selfbuild Proposal must consist of the entire cost to complete the project including the "overnight cost," project capital additions, the Allowance for Funds Used During Construction (AFUDC) and the non-fuel operating and maintenance cost of the proposed self-build facility. The "overnight cost" is the cost to build the plant all at once, or "overnight," without consideration of financing costs. The utility thus may choose to make no commitment to the structure of the construction organization, to the timing of the project, or to its financing costs.

iv.

The RFP and RFP Document together shall identify all factors to be considered in the evaluation of bids. In addition to the matters specified in Commission Rule 515-3-4-.04(3)(b), the following materials or matters shall be included in either the RFP or RFP Document, as appropriate:

I.	a pro forma power purchase agreement containing all expected material terms and conditions;

II.	information on the Southern Company OASIS that will permit each prospective bidder to identify any native load growth transmission service reservation made by or on behalf of the soliciting entity; and

III.

the solicitation schedule.

With respect to item (iv)(I) above, the Commission shall conduct a process beginning at the conclusion of this IRP case, to be concluded within the shortest time practicable, in which all interested parties may participate to develop a pro forma power purchase agreement that will become part of the RFP Document. It is anticipated that the proforma power purchase agreement that is part of the RFP Document may be modified from time to time with the consent of both contracting parties in a manner that does not depart from the terms upon which the winning bid was selected.

v.

The Staff and the IE will critique the initial draft RFP and RFP Document and provide their input to the soliciting entity. The soliciting entity may incorporate changes based on this critique if it so chooses. The initial draft RFP and RFP Document, plus the Staff/IE critique thereof, will be posted on the IE website.

vi.

The IE and Staff, plus the soliciting entity, may conduct at least one public bidders conference to discuss the draft RFP and RFP Document with interested parties, including but not limited to potential bidders. Potential bidders may submit written questions or recommendations to the IE regarding the draft RFP and RFP Document in advance of the bidders' conference. All such questions and recommendations shall be posted on the IE website. The IE shall have no private communication with any potential bidders regarding any aspect of the draft RFP and RFP Document.

vii.

Based on the input received from potential bidders and other interested parties, and based on their own review of the draft RFP and RFP Document, the Staff and the IE will submit a report to the soliciting entity detailing suggested recommendations for changes to the RFP and RFP Document prior to its issuance. This report shall be provided to the Commission and posted on the IE website for review by potential bidders.

viii.

The soliciting entity shall submit its final version of the RFP and RFP Document to the Commission for approval or modification. Once approved by the Commission, the final RFP and RFP Document shall be posted on the IE website. At any time after the RFP is issued, through the time the winning bid is selected by the soliciting entity, the schedule for the solicitation may be modified upon mutual agreement among the soliciting entity, the IE and the Staff, or upon approval by the Commission.

ix.

At the time the content of the RFP is considered for approval, the Commission may determine whether there will a single round of bidding, or whether a "competitive tier and refreshed bid" process will be used. The Commission will consider comments and views of the soliciting entity and any interested party, including potential bidders, on this issue. In the event that the Commission does not expressly determine that a "competitive tier and refreshed bid" process shall be used, there will be only one round of bidding.

x.	Notwithstanding the foregoing, there shall be a single round of bidding to obtain the next supply-side resource identified in the current IRP case and that block of supply-side resource shall be procured through the RFP Process.

2.

Issuance of RFP and Bidder Communications.

i.	The IE will transmit the final RFP and RFP Document to the bidder list via the IE's website, pursuant to the solicitation schedule contained in the RFP and RFP Document.

ii.

The only bidder communications permitted prior to submission of bids shall be conducted through the IE. Bidder questions and IE responses shall be posted on the IE website. To the extent such questions and responses contain competitively sensitive information for a particular bidder, this information may be redacted.

iii.

The soliciting entity may not communicate with any bidder regarding the RFP Process, the content of the RFP and RFP Document, or the substance of any potential response by a bidder to the RFP; provided, however, the soliciting entity shall provide timely, accurate responses to an IE request for information regarding any aspect of the RFP and RFP Document or the RFP Process.

iv.	Bidders shall submit bids pursuant to the solicitation schedule contained in the RFP and RFP Document. The soliciting entity, Staff, and the IE shall have access to all bids and all supporting documentation submitted by bidders in the course of the RFP Process.

v.	The soliciting entity shall cause native load growth reservations to be made on the Southern Company OASIS for all bids that are not otherwise capable of using an existing native load growth reservation for evaluation purposes.

3.

Evaluation of Responses to RFP.

i.

The evaluation stage of the RFP Process will proceed on two tracks. On one track, the soliciting entity will evaluate all bids based on a total cost impact analysis such as was applied in the 2005/2006 Georgia RFP (the "TCI Analysis"). The soliciting entity will conduct this track in an appropriate manner, consistent with the principles and procedures contained in this Proposed RFP/IE Structure.

ii.

A second track will be conducted by the Staff and the IE. The Staff and IE shall have discretion to utilize whatever they consider the optimum combination of auditing the soliciting entity track and conducting its own independent evaluation in order to evaluate the resource options submitted to the soliciting entity in the RFP Process. The Staff and IE may apply the TCI Analysis as part of conducting their independent evaluation.

iii.

The soliciting entity, the Staff or the IE may request further information from any bidder regarding its bid. Any communications between the soliciting entity and a bidder in this regard shall be conducted through the IE. The soliciting entity shall be informed of the content of any communications between the Staff/IE and a bidder. Should it be determined necessary by the IE, the soliciting entity and the bidder, conference calls between the soliciting entity and a bidder may be conducted for the sole purpose of clarification and understanding of a particular bid. All conference calls must be initiated by the IE and the IE will be present on each call for its duration. Communications will be conducted on a confidential basis between the IE and the bidder, and may include one face-to-face meeting between the IE, the soliciting entity, and each bidder to discuss the proposal, unless a bidder declines such a meeting.

iv.

In order to conduct both its independent evaluation function and its auditing function, the IE and the Staff shall have access to all information and resources utilized by the soliciting entity in conducting its TCI Analysis. The soliciting entity shall provide complete and open access to all documents and information utilized by the soliciting entity in its TCI Analysis; and the IE and Staff shall be allowed to actively and contemporaneously monitor all aspects of the soliciting entity evaluation process in the manner they deem appropriate. The soliciting entity shall facilitate this access so that the soliciting entity evaluation process is transparent to the Staff and the IE. The soliciting entity shall have an affirmative responsibility to respond to any request for access or information made by the Staff and/or the IE. To the extent the IE determines that the evaluation processes of the two tracks are yielding different results, the IE shall notify the soliciting entity and attempt to identify the reasons for the differences as early as practicable. Where practicable, the soliciting entity and the IE shall attempt to reconcile such differences.

v.

The Staff and the IE, as well as the soliciting entity, may rely on the Southern Services Transmission Planning ("SSTP") group to conduct all necessary transmission analyses concerning bids received. SSTP analyses provided to the Staff and the IE shall be equivalent in quality and content as that provided to the soliciting entity. No bidder, including any bidder that is an affiliate of the soliciting entity, shall communicate with the SSTP group during the course of the RFP Process regarding any aspect of the RFP.

4.

Bidding Stages.

i.	If the Commission has directed that a "competitive tier and refreshed bid" process be used, the IE and the soliciting entity will follow steps 22 through 26 in the evaluation process.

ii.

The soliciting entity shall perform its evaluation of the bids and shall develop a competitive tier that narrows the bids to a manageable number that the soliciting entity believes are the best competitive options ("soliciting entity Competitive Tier"). The Staff and the IE also shall perform their independent evaluation of the bids and develop their own competitive tier that narrows the bids to a manageable number that the Staff and the IE believe are the best competitive options ("Staff/IE Competitive Tier").

iii.	The soliciting entity shall provide the soliciting entity Competitive Tier to the Staff and the IE. Simultaneously, the Staff and the IE shall provide the Staff/IE Competitive Tier to the soliciting entity.

iv.

If the soliciting entity Competitive Tier and the Staff/IE Competitive Tier are identical, the IE shall notify all companies on the Competitive Tier lists that they have the opportunity to better their bids as final best offers. The IE shall post the Competitive Tier list on the IE website showing each bidder's relative rank and the total evaluated cost of each bid. Each bidder on this list will be identified blindly so each bidder knows the identity of the bidder for only its bid but sees its rank compared to those of all other anonymous bidders who made the Competitive Tier.

v.

If there are differences between the soliciting entity Competitive Tier and the Staff/IE Competitive Tier, the soliciting entity, the Staff, and the IE shall meet to try to resolve such differences in order to agree on a single Competitive Tier list. To the extent that such agreement cannot be reached, the IE shall notify all parties on each list that they have the opportunity to better their bids as final best offers. The IE shall post the combined Competitive Tier list on the IE website showing each bidder's relative rank and the total evaluated cost of each bid. Each bidder on this list will be identified blindly so each bidder knows the identity of the bidder for only its bid but sees its rank compared to those of all other anonymous bidders who made the Competitive Tier.

vi.

The refreshed "better" bids/final best offers shall be evaluated independently by:

(1)	the soliciting entity; and

(2)	the Staff and the IE, in each case consistent with the process outlined above for initial bids.

5.

Certification of Resource(s).

i.	After it has completed its evaluation, and pursuant to the RFP schedule, the soliciting entity shall notify the Staff and the IE of which resource(s) the soliciting entity has selected to win the bid.

ii.	The Staff and the IE shall notify the soliciting entity whether they agree with the determination by the soliciting entity. The Staff/IE shall also notify the soliciting entity of the results of their independent evaluation.

iii.	If the Staff and IE do not agree with the selection made by the soliciting entity, they shall meet to discuss the differences in their selections.

iv.	The soliciting entity is responsible for determining which resource(s) it will submit to the Commission for certification. The soliciting entity may consider the Staff/IE evaluation in making its decision, but the soliciting entity remains ultimately responsible for the selection.

v.

Based on the pro-forma PPA included in the RFP Document, the soliciting entity may negotiate a final PPA with the bidder for each resource it has selected so that the Commission may consider the exact terms under which the resource will be certified.

Any such PPA shall be expressly conditioned on the final decision of the Commission in the certification proceeding. If the soliciting entity conducts such negotiations, the IE and the Staff shall have the right, but not the obligation, to attend any and all negotiating sessions for the purpose of monitoring them. In the alternative, the soliciting entity may wait until the certification proceedings are complete to begin negotiations with the bidder for each selected resource based on the pro-forma PPA included in the RFP Document.

vi.	The soliciting entity shall file with the Commission a request for certification of the resource(s) chosen by the soliciting entity.

vii.

The Staff and the IE shall participate in the certification proceeding and testify regarding:

(1)	their independent evaluation of whether the resource selected by the soliciting entity should be selected and if not, which resource(s) in their view should be selected as a result of the RFP process; and

(2)	whether the soliciting entity conducted the RFP process in a fair and impartial manner.

viii.

The Commission will conduct the certification proceeding and may take any actions it deems appropriate as allowed by law.

ix.

If the soliciting entity has not yet negotiated a specific PPA prior to the certification, upon approval of PPA award recommendations by the Commission, the soliciting entity will proceed to negotiate or finalize appropriate contractual arrangements consistent with the approved award(s). The IE and the Staff shall have the right, but not the obligation, to attend any and all negotiating sessions for the purpose of monitoring them. The soliciting entity will make a compliance filing once the PPA is executed and the IE and the Staff will report to the Commission their opinion as to whether the PPA as executed complies with the Commission's certification order.

x.

The soliciting entity will maintain a complete record of all materials developed for, generated during, or used in the RFP Process for (3) three years beyond the date of certification of the selected proposal(s), including any such materials prepared and/or used by the IE, as well as hard copies or electronically stored copies of all materials and exchanges posted on the IE's website.

xi.	The IE will enter into an appropriate agreement pertaining to the disclosure and use of any models, analytical tools, data, or other materials of a confidential or proprietary nature that are provided or made available by the soliciting entity in conjunction with the RFP Process.

(f)

The only exceptions from the requirement to procure supply-side capacity through competitive bidding shall be the following:

1.	Purchases from Qualifying Facilities (30 MW or less) as required by 16 U.S.C. Section 796;

2.	Repowering, life extension or efficiency improvement of an existing generating plant that does not require significant capital investment;

3.	Supply-side capacity resources of extraordinary advantage that require immediate action, as demonstrated in a joint petition for certification by the utility and, where applicable, the potential provider;

4.	Modification to comply with environmental regulatory requirements; and

5.	Any supply-side resource that would provide power at a capacity level of 30 MW or less.

6.	The Commission shall expressly consider in each IRP, and make a determination in each IRP Plan, whether to exclude from the RFP Process any new supply-side resources identified in the soliciting entity's approved IRP Plan; and

7.

It is the Commission policy that investor-owned electric utilities under its regulation shall maintain a minimum percentage of their capacity as "self-owned" rate-based assets. Such percentage shall be set by Commission order and may be changed from time to time. In those situations in which the soliciting utility is nearing or finds that it would fall below this minimum percentage level, the soliciting utility shall inform the Commission of this eventuality in advance of the RFP Process at which time the Commission, in its discretion, may suspend these rules and provide guidance to the soliciting utility as to how it should proceed.

At the time when the utility decides to consider one of these options as an exception to the RFP solicitation requirement of Rule 515-3-4-.04(3)(f), the utility must so notify the Commission through an informational filing. The informational filing shall not constitute a certificate application for the resource option being considered, although an application is required if such a resource is selected.

(g)

If the utility selects a purchase option, it must either include in the proposed contract each of the following four provisions, or show as a part of its resulting certificate application why other benefits of the proposed purchase warrant the Commission's approval:

1.	A "regulatory out" clause written in terms acceptable to the contracting parties;

2.

A "take-and-pay" provision that the utility will pay the variable charges associated with energy generated by the seller's facility only when it actually purchases that energy. It will pay capacity charges only when the seller's unit is effectively available for service, subject to appropriate contractual provisions regarding routine maintenance. "Take-orpay" provisions, under which the utility would be committed to pay for power regardless of the seller's performance, will not be approved;

3.

Security deposits to ensure that if the seller's facility fails to produce power, the utility is covered such as for the extra costs of purchasing or generating replacement power. The parties should negotiate the form of such deposits such as whether they are separate or joined with general deposits securing contract performance generally; and

4.

An option for the utility to purchase the seller's facility if for any reason the seller is unwilling or unable to meet its contractual obligations after a reasonable opportunity for cure. The contract should allow the utility to submit a price offer, or to have a right of first refusal to match an outstanding bona fide offer. The contract should also specify that the seller may not force the utility to undertake such a purchase of the facility; that the utility may, without waiving any other contract rights, elect to operate and maintain the facility if the seller fails to operate and maintain the facility after a reasonable opportunity for cure; and that the seller may not sell its facility or delegate its contractual obligations without notice to and consent of the utility, which consent shall not be unreasonably withheld. The utility must provide an informational notification to the Commission if it elects to operate and maintain the facility, if it elects to purchase the facility, if the seller sells the facility to a third party, or if the seller delegates its contractual obligations to a third party.

(h)

In conducting evaluation of the bids received in the RFP process, the utility shall not:

1.	add any adjustments on the basis of expected impacts to the utility's cost of capital; and

2.

impose a penalty on the price of purchased power or discount on the cost of utility self generation on the basis of reliability of purchased power as part of the utility's resource mix.

These requirements are without prejudice to the utility at its option also performing evaluations taking into account all aspects of cost and risk it believes appropriate as a matter of information for the Commission for case-by-case review during resulting certificate application proceedings.

(4)

Potential New Demand-Side Resources.

(a)

Demand-side Resource Assessment and Initial Cost Screening:

1.

Assessing Demand-Side Measures. A comprehensive range of demand-side measures shall be evaluated for each customer segment, and the utility shall compile a list of measures based upon an inventory of end-use devices and consumption patterns developed for energy and demand forecasting. For each DSM measure included on this list, the applicant shall provide the following information:

(i)	A brief description of the measure;

(ii)	Measure costs and basis for costs;

(iii)

Measure kW and kWh load impacts and associated avoided costs;

(iv)	Measure useful life;

(v)	Forecast of market potential;

(vi)	Current saturation of the measure;

(vii)

Assumptions on participant benefits, if any, other than electricity savings; and

(viii)

Any other supporting data deem pertinent by the utility.

2.

Screening. The utility shall screen all demand-side measure utilizing the fate impact measure test, the participant's test, the total resource cost test and the societal cost test. The utility shall perform a final screening of demand-side programs based on current Commission policy.

(i)	Program administrative costs shall not be included in the total cost for the initial screening of the measure because programs have yet to be designed. After programs are designed, program administrative costs are estimated and included in subsequent screening of demand-side programs;

(ii)

Program costs include the participant's direct cost of a demand-side measure, the utility's direct cost of a demand-side measure, and the utility's administrative cost for developing and implementing the demand-side measure. Participant's costs are incremental costs and include only those costs which would not have been incurred but for participation in the program;

(iii)

Utility estimates of these costs and benefits should, to the extent practicable, be evaluated on the same basis as electric supply-side resources;

3.	Measure elimination. Those measures which fail the Total Resource Cost test shall be eliminated from program consideration. If the utility eliminates any demand-side measures, each such measure shall be identified, and the reason for rejection shall be fully explained.

(b)

Development of Program Design for Measures Passing Initial Screening:

1.	All demand-side measures which passed the Total Resource Cost test may be incorporated into one or more demand-side programs, taking into account the program administrative costs and interactions between measures; and

2.	Programs should pass the final screening test and be designed as either full scale or pilot programs.

Rule 515-3-4-.05 Development of Integrated Resource Plan

(1)

Development of Integrated Resource Plans.

(a)

Each utility shall develop a base case integrated resource plan based on the most economic and reliable combination of potental demand and supply-side resources, to meet the needs identified by the base case demand forecast scenario. The overall objective of the plan should be based on current Commission policy concerning minimizing customer bills, minimizing overall rates and maximizing net societal benefit. All potential resources which were identified and described as required in Rule 515-3-4-.04, and which were not excluded by the appropriate screening tests and where applicable to the Request for Proposal process, shall be considered for inclusion in the utility's integrated resource plan;

(b)

The utility shall provide the following information for its integrated resource plan:

1.

The utilities program for meeting the requirements shown in its demand and energy forecast in an economic and reliable manner. The utilities's analysis shall be for all capacity resources options, including both demand-side and supply-side options, and set forth the utilities assumptions and conclusions with respect to the effect of each capacity resource option on the future cost and reliability of electric service. These analyses shall be consistent with analyses required by Rules 515-3-4-.04;

2.	A detailed projection of the utilities electric demand and energy forecast for at least a 20-year period as required by Rule 515-3-4-.03(b);

3.	The size and type of facilities which are expected to be owned or operated in whole or in part or to be removed from service as specifically required by Rule 515-3-4-.04;

4.	Practical alternatives to the fuel type and method of generation of the proposed electric generating facilities and set forth in detail the reasons for selecting the fuel type and method of generation;

5.	A statement of the estimated impact of proposed and alternative generating plants on the environment and the means by which potential adverse impacts will be avoided or minimized;

6.

An adequate demonstration of the economic, environmental, and other benefits to the state and to customers of the utility, associated with the possible measures and sources of supply including; improvements in energy efficiency; pooling of power; purchases of power from neighboring states; facilities which operate on alternative sources of energy; facilities which operate on the principal of cogeneration or hydro-generation; and other generation facilities and demand-side options;

7.	A description of the utility's relationship to other utilities in regional associations, power pools, and networks;

8.	An identification and description of all major research projects and programs which will continue or commence in the succeeding three years and set forth the reasons for selecting specific areas of research;

9.	Identify and describe existing and planned programs and policies to discourage inefficient and excessive use of power;

10.	Net present value of the revenue requirement, including all direct utility costs associated with the resource to measure economics of utility service;

11.	Net present value of the participant's direct costs;

12.	Impact on the utility system and its customers, including non-price criteria such as operating performance of the resource, and ability to meet energy service needs of customers; and

13.	Impact on utility transmission and distribution system requirements, including additional long-term facilities and operating procedures required.

(c)	The utility shall describe the criteria used in developing its integrated resource plan; and

(d)

The utility shall conduct an analysis of the sensitivity of all major assumptions and estimates used in its integrated resource plan. This analysis shall at a minimum include:

1.	Forecast of load;

2.	In-service dates of supply and demand resources;

3.	Unit availability;

4.	Fuel prices;

5.	Inflation in plant construction costs and costs of capital;

6.	Availability and costs of purchased power;

7.	Pending federal or state legislation or regulation; and

8.	Rate Impact Analysis.

(2)

Power Pooling and Coordination.

(a)	The utility will document how its plan, subject to FERC requirements has taken, advantage of the economic, environmental, and other benefits to the state and to customers of the utility associated with cooperative planning and coordination of pooling of power; and

(b)	The utility shall describe and justify its reserve margin requirement for the planning period, and set forth the method used to determine the appropriate reserve margin.

(3)

Financial Information.

(a)

The financial assumptions and models used in the plan shall be described. The plan shall include at a minimum the following financial information, together with supporting documentation and justification:

1.	The general rate of inflation;

2.	The AFUDC rates used in the plan;

3.	The cost of capital rates used in the plan (debt, equity, and weighted) and the assumed capital structure;

4.	The discount rates used in the calculations to determine present worth;

5.	The tax rates used in the plan.

6.	Present worth of revenue requirements for the plan;

7.	Nominal revenue requirements by year;

8.	Average system rates per kWh by year; and

9.	An overall assessment of the business and financial risks associated with the plan including the identification of appropriate financial measures by year.

(4)

Commission Determination. The Commission shall determine which combinations of resource options passing the screening test best serve the public interest considering economics, safety, reliability, flexibility, risk, equity among ratepayers and classes, customer bills, externalities and other factors the Commission deems appropriate.

(5)

The Plan. Every six months after the approval of the integrated resource plan, the utility shall submit to the Commission and other parties to the proceeding a progress report of the actions taken and expenditures incurred to implement the plan. This report shall compare the expenditures budgeted and incurred, the actions proposed and taken, and explain any significant deviations from the utility's plan. If the utility has not complied with a specific provision of its most recently approved plan, the utility should include in its report an explanation of why it has not yet complied with the provision in question. This explanation should also include the utility intended actions over the next six-month period with respect to this provision. Any party of record may request the Commission hold a hearing on the report.

Rule 515-3-4-.06 Integrated Resource Plan Filing Requirements and Procedures

(1)

On or before January 31, 1992, and every three years thereafter, each utility shall file a twenty year integrated resource plan with the Commission (twenty-five copies) and an application for approval of that plan. The application for review and approval of the plan shall clearly identify:

(a)	The name of the applicant(s) and address(es) of the principal place of business of the applicant;

(b)	The name, title, address, voice phone, and facsimile phone number of the person authorized to receive notices and communications with respect to the application;

(c)	The location(s) that the public may inspect a copy of the application; and

(d)	Requests by the utility that any information utilized in the plan which the utility deems trade secret be filed in accordance with the Commission's Trade Secret Rule 515-3-1-.11.

(2)	Copies of the executive summary and technical volumes shall be made available by the utility for public inspection at its region offices located throughout the state.

(3)

Plan Filing: Specific Requirements. Plan filings must contain the following information:

(a)

Executive Summary. Each utility shall prepare an Executive Summary, separately bound and suitable for distribution to the public, which shall be a non-technical description of the plan. This document shall summarize the contents of the Technical Volume(s). The summary shall include:

1.	A brief introduction describing the utility, its existing facilities, purchase power arrangements, demand-side programs, and the purpose of the plan;

2.	A description of the utility's relationship to the utility enterprise and to other utilities in regional associations, power pools and networks;

3.	The base case forecast growth in peak demand and energy for the next twenty years, with and without utility demand-side programs, and a listing of the economic and demographic assumptions associated with each;

4.	A summary of the system configurations proposed to meet expected energy service needs for the next twenty years, clearly showing the demand-side resources and supply-side resources contained in each. For each resource, the utility shall indicate its anticipated timing, magnitude, and cost;

5.	A description of the major research projects and programs the utility will continue or commence during the ensuing three-year period, and the reasons for their selection;

6.	A schedule for the acquisition of data, including planned activities to update and refine the quality of data used in forecasting, and budget for such acquisition;

7.	A section describing any plans to acquire new or additional models for forecasting, or resource integration analysis and evaluation;

8.	A tabulation of all costs associated with the development of the plan;

9.	A tabulation of costs for which the utility will seek recovery and the method and timing of that recovery; and

10.	Such other information as the Commission may determine appropriate.

(b)

Technical Volume(s). Each utility shall prepare Technical volume(s) which shall include:

1.	The information required by Rules 515-3-4-.03 through 515-3-4-.05:

2.

A description detailing the relationship of the utility to the utility enterprise and to other utilities in regional associations, power pools and networks. The utility shall explain how planning and operation are coordinated among the utilities. The utility shall describe the terms of any contracts or agreements that govern the functioning of the enterprise, associations, power pools or networks;

3.	A description of all major research projects and programs which will continue or commence within the next three years after filing the plan; and

4.	Any other information as may be required by the Commission.

(c)

Technical Appendix. A utility's plan must include a technical appendix. The appendix must contain the following:

1.	Sufficient detail to enable the technically proficient reader to understand how the plan and its forecasts were prepared and to verify the adequacy and accuracy of the assumptions, data and the methods used in developing the plan;

2.	All significant information used in the plan; and

3.	Documentation, inputs, and summary outputs for all models and formulas used.

(d)

Waiver of Information. If, after a good-faith effort, the utility cannot provide the data required by these rules, the utility must request a waiver, in writing. This request must be filed no less than 60 days prior to the filing of the plan. The utility must publish in appropriate media of mass dissemination that it has applied for a waiver. The request shall include:

1.	Reference to the requirement for information that is the subject of the waiver request;

2.	An explanation of the reasons the required information was impractical to supply; and

3.	Proposed substitute information, if applicable. If no waiver is granted, materials must be filed as required in the rules.

(4)

Hearing and Review of Integrated Resource Plans.

(a)	Proceedings. The Commission shall commence a hearing within sixty days of receipt of a utility's complete integrated resource plan;

(b)

Completeness of the Utility Plan. The commission shall determine whether the utility plan is complete within thirty days following the initial submission of the plan by the utility. The Commission will inform the utility of substantive defects in the content of the plan which would materially affect the Commission's ability to continue the plan review process. If the Commission finds as a matter of fact that the utility plan is not complete, by Order of the Commission the review process may be stayed until the utility has submitted a complete plan.

(c)	Fees. Within sixty days after receipt of the complete plan, the Commission shall establish a fee therefor and notify the applicant. Upon receipt of the fee from the applicant, the Commission shall continue its review of the plan; and

(d)

Standard for Approval. Based upon the evidence of record presented at the hearing on the plan, the Commission shall render a decision either approving the plan, approving it subject to stated conditions, approving it with modifications, approving it in part and rejecting it in part, rejecting it as filed, or provide an alternate plan, within one-hundred-twenty days of receipt of fees related to the utility's completed application. A utility's integrated resource plan shall be approved if found to be in the public interest and to substantially comply with these regulations.

(5)

Amendment of the plan. The utility shall submit an amendment to its plan before it submits its next plan if within the first three years of the approved integrated resource plan:

(a)	It anticipates submitting an application for a certificate to construct or purchase a supply-side capacity resource which was not previously approved as part of the integrated resource plan;

(b)	It anticipates the need to release an RFP, or make a binding commitment for the acquisition or construction of a demand resource or supply resource excepted from the RFP process, which was not previously approved as part of the integrated resource plan;

(c)	The basic data used in the formulation of its last approved plan requires significant modification which affects the choice of a resource or use of an RFP which was approved as part of the integrated resource plan; and

(d)	It finds that other conditions warrant amendment of the plan. The conditions under which such an amendment is sought shall be specifically set forth in the application for amendment.

(6)	Subsequent Plans. Once a plan has been approved, the Commission may limit the scope of issues it will consider in the review of subsequent plans to those issues directly related to material changes.

Rule 515-3-4-.07 Supply-Side Resource Certificate Filing Requirements and Procedures

(1)

Certification of Long-Term Supply-Side Resources. The Utility shall file an application for certification of a Supply-side Resource as required by O.C.G.A. Section 46-3A with the Commission (twenty-five copies). The application for review and approval of the certificate shall clearly identify:

(a)	The name of the applicant(s) and address(es) of the principal place of business of the applicant(s);

(b)	The name, title, address, voice phone, and facsimile phone number of the person authorized to receive notices and communications with respect to the application;

(c)	The location(s) that the public may inspect a copy of the application;

(d)	Requests by the utility that any information utilized in the plan which the utility deems trade secret be filed in accordance with the Commission's Trade Secret Rule 515-3-1-.11; and

(e)

Hearing and Review of Supply-Side Resource Certificate Applications.

1.

Proceedings. The Commission shall commence a hearing no sooner than thirty days after receipt of fees related to the utility's completed application for certification of a Supply-Side Resource. A completed application must include all information required by these Rules as appropriate, as well as documentation that all applicable state and federal permits required to complete the project have been secured, or in the event that the permit is unsecurable until an appropriate later phase of project completion, the application process must have been initiated in accordance with applicable federal, state or local statutes;

2.

Completeness of the Utility Certificate Application. The Commission shall determine whether the utility certificate application filing is complete within thirty days following the initial submission of the certificate application by the utility. The Commission will inform the utility of substantive defects in the content of the certificate application filing which would materially affect the Commission's ability to continue the certificate application review process. If the Commission finds as a matter of fact that the utility certificate application is not complete, by Order of the Commission the review process may be stayed until the utility has submitted a complete certificate application.

3.	Fees. Within sixty days after receipt of the completed application, the Commission shall establish a fee therefor and notify the applicant. Upon receipt of the fee from the applicant, the Commission shall continue its review of the certificate application;

4.

Waiver of Information. If, after a good-faith effort, the utility cannot provide the data required by these rules, the utility must request a waiver, in writing. This request must be filed no less than 60 days prior to the filing of the certificate application. The utility must publish in appropriate media of mass dissemination that it has applied for a waiver. The request shall include:

(i)	Reference to the requirement for information that is the subject of the waiver request;

(ii)	An explanation of the reasons the required information was impractical to supply; and

(iii)

Proposed substitute information, if applicable;

If no waiver is granted, materials must be filed as required in the rules.

5.

Standard for Approval. Based upon the evidence of record presented at the hearing on the application, the Commission shall render a decision either approving the application, approving it subject to stated conditions, approving it in part and rejecting it in part, rejecting it as filed, or providing an alternate capacity resource certification within one hundred eighty days of receipt of fees related to the utility's completed application. A utility's application shall be approved if found to be in the public interest and to substantially comply with these regulations.

A utility's application relative to a contract to buy capacity or energy from an exempt wholesale generator that is an affiliate or associate of the applying utility shall not be approved unless the Commission determines:

(i)

That the Commission has sufficient regulatory authority, resources and access to books and records of the applicant utility and any relevant associate, affiliate or subsidiary company to exercise its duties under this section of the Commission's Rules and under the Energy Policy Act of 1992, Section 711, adding new section 32(k) to the Public Utility Holding Company Act of 1935, 15 U.S.C. Section 79et seq.;

(ii)

That the proposed transaction:

(I)	Will benefit consumers;

(II)	Does not violate any State law;

(III)

Would not provide the exempt wholesale generator any unfair competitive advantage by virtue of its affiliation or association with the electric utility company applicant; and

(IV)	Is in the public interest.

(iii)

Reciprocal arrangements among companies that are not affiliates or associate companies of each other that are entered into in order to avoid the provisions of this subparagraph or Section 32k of the Public Utility Holding Company Act of 1935 as amended are prohibited.

(2)

Construction of New Electric Plant.

(a)

The application itself shall contain at a minimum the following information:

1.	A statement of how the proposed application is consistent with the most currently approved Integrated Resource Plan (IRP) and RFP (Request for Proposal) process. If a revised IRP is available, it shall also be filed;

2.

A cost-benefit analysis covering the estimated useful life of all capacity resource options considered in developing its current integrated resource plan, along with a summary comparison of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the proposed resource is economical and reliable, or justification of the utility's decision to select the self-build construction option as an exception to the RFP requirement pursuant to Rule 515-3-4-.04(3)(i).

3.

A description of the resource to include identification of plant size and type with summary level engineering/design specifications. The description should include at a minimum the following:

(i)	A site selection analysis including alternatives, geological considerations and environmental considerations;

(ii)	Description of fuel use, both primary and back-up, and provisions for transporting and storing fuel;

(iii)

Estimated annual costs, in accordance with the breakdown specified in the FERC Uniform System of Accounts, separately identifying the following:

(I)	Annual depreciation on capital investment:

(II)	Annual return and income taxes on capital investment;

(III)

The operation and maintenance (O&M) costs over the life of the facility decribed as costs which are variable, in current dollars per kWh, with expenses for fuel and other items indicated separately; and costs which are fixed, in current dollars per kW;

(IV)	Insurance;

(V)	Waste handling and disposal; and

(VI)	Property taxes;

(iv)

The rates of escalation of cost, including:

(I)	Capital costs;

(II)	O&M costs which are variable and related to fuel;

(III)

O&M costs which are variable and unrelated to fuel; and

(IV)	O&M costs which are fixed.

(v)	The total annual average cost per kWh at projected loads in current dollars for each year of the plan for the proposed facility;

(vi)	Equivalent availability factors, including both scheduled and forced outage rates;

(vii)

Capacity factors for each year in the planning period;

(viii)

Duty cycle (i.e., baseload, intermediate, or peaking), identifying expected hours per year of operation, number of starts per year, and cycling conditions for each year in the planning period;

(ix)	Heat rates (efficiency) for various levels of operation;

(x)	Unit lifetime, both for accounting book purposes and engineering design purposes, with explanations of differences;

(xi)

Estimated environmental impact, including specific emission, production, or usage data for each of the following categories:

(I)	Pounds of sulfur oxides per MMBTU;

(II)	Pounds of oxides of nitrogen and nitrous oxides per MMBTU;

(III)

Pounds of carbon dioxide per MMBTU;

(IV)	Pounds of volatile organic hydrocarbons per MMBTU;

(V)	Pounds of carbon monoxide per MMBTU;

(VI)	Pounds of particulates/air toxics per MMBTU;

(VII)

Pounds of methane per MMBTU;

(VIII)

Pounds of chlorofluorocarbons, halogens, and other ozone-depleting substances per MMBTU;

(IX)	Tons per year of solid waste (ash, scrubber sludge, high- and low-level nuclear waste);

(X)	Gallons per year of water impacts or use (water input, water output, receiving water impacts);

(XI)	Tons per year of spent nuclear fuel;

(XII)

Acres of land use;

(XIII)

Pounds of hydrogen sulfides per MMBTU; and

(XIV)

Pounds of ammonia per MMBTU;

(xii)

Lead time, separately identifying the estimated time required for engineering, permitting and licensing, design, construction and pre-commercial operation date testing;

(xiii)

Potential socioeconomic impacts such as employment, personal income levels, and the competitiveness and health of the marketplace economy of the state; and

(xiv)

Any special design features peculiar to this facility.

4.

The total cost estimate for the proposed project is to include construction and non-construction related costs incurred through commercial operation. This cost estimate should include but not be limited to the following:

(i)	Identification of major contracts, including, where known: scope, type, contractor, cost estimate, contractor selection process and selection criteria;

(ii)	Cost expenditure plan, by year, to include a breakdown of the following areas: planning, licensing, engineering/design, construction, contingency, start-up;

(iii)

Identification of those costs associated with but not defined as construction costs, including separately all cost incurred to date and to-go costs for each area and/or activity;

(iv)	AFUDC, Ad Valorem and Sales Tax expenditures by year;

(v)	Estimated annual capital additions over the life of the resource;

(vii)

Decommissioning/dismantlement costs; and

(viii)

Cost breakout of dedicated transmission and distribution facilities and a statement as to whether or not such costs are included in 515-34-.07(2)(a)4. (i) through (vi) above.

5.

Where available, a cost comparison of projects similar by type/design and capacity completed in the U.S. during the past five years. Include commercial operation date, actual completion cost, and current dollar equivalent with accompanying adjustment assumptions. Identify any major design differences;

6.	The construction and non-construction activities schedule in both milestone summary form and in as much detail as has been used in developing the total cost estimate of the supply-side resource;

7.	A formal Critical Path schedule shall be submitted showing major activities on the critical path and near-critical path activities with their sensitivity to the critical path;

8.	As part of the schedule, provide lead times for major procurement items (turbines, generators, specialty items, etc.) and sensitivity of schedule to variations in duration of major tasks;

9.	A description of the legal relationship between the utility and major vendors, including any affiliate relationship(s); and

10.	Any other information the Commission deems necessary.

(b)

Construction Monitoring. The utility shall file such information periodically as pecified by the Commission to produce an accurate, ongoing evaluation of management decisions, methods, schedules, budget and cost in order to verify and approve expenditures made pursuant to the certificate; or to approve, disapprove, or modify any proposed certificate amendments, including the following:

1.	The information should include sufficient data to confirm that standards of public convenience and necessity are being met in an economic and reliable manner;

2.

Data provided to allow monitoring of a cupply-side construction project shall include:

(i)

Actual project expenditures and a comparison of actual to budgeted expenditures with an explanation of variances in excess of 5 percent or other tolerance as specified by the Commission. In addition, a forecast of the completed cost of the project should be provided and any variance between the budgeted cost and the forecast completed cost should be explained;

(ii)

The status of critical path activities, project milestone events and other significant activities. Status of these activities should include the start date, percent complete and estimated completion date. Significant variances between the existing schedule and the original project schedule should be explained;

(iii)

The procurement status of significant components. The procurement status should include the date that the purchase order or requisition was placed, the date the component is needed on site and the estimated arrival date. All estimated arrival dates later than the required on site date should be explained;

(iv)

The status of all required federal, state, and local licenses and permits including the date when the license or permit is needed, the expected date that the license or permit will be received and a discussion of the impact and planned corrective action for any license or permit whose receipt date is estimated to be after its need date;

(v)

A summary of major contracts including scope of work, estimate of the contract amount used in preparation of the project budget and actual contract amount. Any variance between the estimated and actual contract amount greater than 5 percent (or other tolerance specified by the Commission) shall be fully explained;

(vi)

The utility shall notify the Commission upon determining that the forecast completed cost of the project differs from the certified cost of the project by more than 5 percent (or other tolerance specified by the commission) or that the projected commercial operation date of the project is later thant the commercial operation date submitted in the certification application; and

(vii)

Any other relevant documents, data or information requested by the Commission.

3.

A utility making application for periodic review of construction must provide documentation that summarizes progress-to-date of the application and compares it to that projected in documentation submitted under Rule 515-3-4-.07(2). The utility, on a periodic basis as specified by the Commission during construction monitoring, must provide written explanations of all variances from planned progress, and an estimate on the ultimate impact of the variance on project cost and completion schedule. No utility may submit an application until previous applications have been disposed of, either through hearing or lapse of time; and

4.

Upon commercial operation of the project, completion of the project without commercial operation, or termination of the project, the utility shall within ninety days submit to the Commission a report summarizing the final cost figures for the project. This report shall contain explanations for all cost variations that exceed five percent of the estimates contained in the approved certificate or amendment(s).

(3)

Sale or Purchase of All or Part of an Existing Plant. The utility shall provide the following information in relation to the sale or purchase of an ownership interest in all or part of an existing plant:

(a)	The terms of sale or purchase, including cash proceeds and any other non-cash considerations, along with an evaluation of their cash equivalent, and a copy of the contract for the sale or purchase;

(b)	The construction cost of the property and additions or improvements over the life of the plant;

(c)	The proposed ratemaking treatment of these costs;

(d)	Depreciation through the planned date of transfer;

(e)

The impact on the overall electric power production costs of removing or adding the operating costs associated with the transferred property on the total utility operating costs. This analysis shall include a summary comparison and supporting information of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the proposed purchase or sale is economic and reliable;

(f)	Relationship and impact of the proposed sale or purchase on the currently approved IRP;

(g)	Applicable information specified in Rule 515-3-4-.04(1),(2), and (3);

(h)	A description of the legal relationship between the purchasing and selling entities, including any affiliate relationship(s); and

(i)	Any other information the Commission deems necessary.

(4)

Sale or Purchase of All or Part of a Plant Under Construction. The utility shall provide the following information in relation to the sale or purchase of an ownership interest in all or part of a plant under construction:

(a)	Information on the proceeds of the sale or purchase, and whether the price is fixed independent of the final cost of the total plant, or varies in any manner;

(b)	Allocation of non-specific hard costs to the portions of the plant being sold and retained;

(c)	The treatment of soft costs such as corporate overhead, engineering, design, construction management and utility costs during construction; specifically how both prior and future costs will be allocated between the sold and retained portion of the plant;

(d)

Impact of the sale or purchase on utility operating costs. This analysis shall include a summary comparison and supporting information of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the proposed purchase or sale is economic and reliable;

(e)	Applicable information specified in Rule 515-3-4-.04(1),(2), and (3);

(f)	Relationship and impact of the proposed sale or purchase on the currently approved IRP;

(g)	A description of the legal relationship between the purchasing and selling entities, including any affiliate relationship(s);

(h)	A copy of the contract for the sale or purchase; and .

(i)	Any other information the Commission deems necessary.

(5)

Long-term Purchase of Capacity or Energy. The utility shall provide the following information in relation to the long-term purchase of capacity or energy:

(a)	The terms of purchase, including cash proceeds and any other non-cash considerations, along with the evaluation of their cash equivalent, and a copy of the purchase contract;

(b)	The proposed ratemaking treatment of these costs;

(c)

The impact on the overall electric power production costs of removing or adding any operating costs associated with the purchase. This analysis shall include a summary comparison and supporting information of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the proposed purchase is economic and reliable;

(d)	Applicable information specified in Rule 515-3-4-.04(3);

(e)	Impact of the proposed purchase on the currently approved IRP;

(f)	A description of the legal relationship between the purchasing and selling entities, including any affiliate relationship(s);

(g)

The following information shall be filed as part of the certificate application if the utility proposes a contract to purchase electric capacity or energy from an exempt wholesale generator that is an affiliate or associate company of the applying utility:

1.

A statement explaining why the applicant believes that the Commission has sufficient regulatory authority, resources and access to books and records of the electric utility company and any relevant associate, affiliate or subsidiary company to exercise its duties under this section of the Commission's rules and under the Energy Policy Act of 1992, Section 711, adding new section 32(k) to the Public Utility Holding Company Act of 1935, 15 U.S.C. section 79et seq.;

2.

A statement why the applicant believes the Commission should determine that the proposed transaction:

(i)	Will benefit consumers;

(ii)	Does not violate any State law ;

(iii)

Would not provide the exempt wholesale generator any unfair competitive advantage by virtue of its affiliation or association with the electric utility company applicant; and

(iv)	Is in the public interest.

3.	A statement as to whether the approval of any other state utility commission or federal entity is necessary to allow the applicant to enter into the contract, and if so, the status of any application to obtain such approval; and

(h)	Any other information the Commission deems necessary.

(6)

Sale or Purchase of a Portion of the Capacity or Energy Output of a Plant Under Construction. The utility shall provide the following information in relation to the sale or purchase of a portion of the capacity or energy output of a plant under construction:

(a)	Information on the proceeds of the sale or purchase, and whether the price is fixed independent of the final cost of the total plant, or varies in any manner;

(b)	Allocation of non-specific hard costs to the portions of the plant output, being sold and retained;

(c)	The treatment of soft costs such as corporate overhead, engineering, design, construction management and utility costs during construction; specifically how both prior and future costs will be allocated between the sold and retained portion of the output of the plant;

(d)

Impact of the sale or purchase on utility operating costs. This analysis shall include a summary comparison and supporting information of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the proposed purchase or sale is economic direct and reliable;

(e)	Applicable information specified in Rule 515-3-4-.04(1),(2), and (3);

(f)	Relationship and impact of the proposed sale or purchase on the currently approved IRP;

(g)	A description of the legal relationship between the purchasing and selling entities, including any affiliate relationship(s);

(h)	A copy of the contract for the sale or purchase;

(i)	If the applicant proposes purchase of a portion of the capacity or energy output of a plant under construction from an exempt wholesale generator that is an affiliate or associate company of the utility, statements containing the information specified in Rule 515-3-4-.07(5)(g); and

(j)	Any other information the Commission deems necessary.

(7)

Any other long-term supply-side resource. The utility shall provide the following information in relation to any other proposed supply-side resource:

(a)	Information on the nature of the proposed supply-side resource and the costs expected to be incurred in connection therewith, including a copy of any associated contract(s);

(b)	The accounting allocation of the costs associated with the proposed supply-side resource;

(c)	The proposed ratemaking treatment of these costs;

(d)

The impact on the overall electric power production costs of removing or adding any operating costs associated with the supply-side resource. This analysis shall include a summary comparison and supporting information of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the proposed resource is economic and reliable;

(e)	Applicable information specified in Rule 515-3-4-.04(1),(2), and (3);

(f)	Relationship and impact of the proposed supply-side resource on the currently approved IRP;

(g)	A description of the legal relationship between the major entities involved with the proposed supply-side resource, including the utility, major vendors or power sellers, customers providing customer-owned or supplied resources, and/or any affiliate relationship;

(h)	If the proposed supply-side resource involves any payments to be made by the utility directly or indirectly to an exempt wholesale generator that is an affiliate or associate company of the utility, statements containing the information specified in Rule 515-3-4-07(5)(g); and

(i)	Any other information the Commission deems necessary.

Rule 515-3-4-.08 Supply-Side Resource Certificate Amendment Filing Requirements and Procedures

(1)

The Utility shall submit an amended application for certification (as the certificate is described under Rule 515-3-4-.07 ) in the event that:

(a)	The construction schedule has significantly changed;

(b)	The total cost estimate has been revised such that the costs are over the estimates in the approved certificate by more than five percent or some other variation tolerance as specified by the Commission in the approved certificate;

(c)	The scope of the project has changed;

(d)	The load forecast has changed sufficiently such that the need for a resource of the type/size previously approved may not be warranted or sufficient;

(e)	The terms of the purchase contract have or are proposed to be significantly changed, including without limitation substantial changes in the ownership or operation of the plant;

(f)	The utility proposes to change the contractual arrangements pertaining to the project such that it will make any payments to an exempt wholesale generator that is an affiliate or associate of the utility;

(g)	Any sufficient change has occurred or is expected to occur in the conditions under which the original certificate was approved.

(2)	The Utility shall file with the Commission twenty-five copies of the certificate amendment application.

(3)

The application for review and approval of the certificate amendment shall clearly identify:

(a)	The name of the applicant(s) and address(es) of the principal place of business of the applicant;

(b)	The name, title, address, voice phone, and facsimile phone number of the person authorized to receive notices and communications with respect to the application;

(c)	The location(s) that the public may inspect a copy of the application; and

(d)	Requests by the utility that any information utilized in the plan which the utility deems trade secret be filed in accordance with the Commission's Trade Secret Rule 515-3-1-.11.

(4)

Hearing and Review of Supply-Side Resource Certificate Amendments.

(a)	Proceedings. The Commission shall commence a hearing no sooner than thirty days after receipt of fees related to the utility's completed certificate amendment application;

(b)

Completeness of the Utility Certificate Amendment Application. The Commission shall determine whether the utility certificate amendment application filing is complete within thirty days following the initial submission of the certificate amendment application by the utility. The Commission will inform the utility of substantive defects in the content of the certificate amendment application filing which would materially affect the Commission's ability to continue the certificate amendment application review process. If the Commission finds as a matter of fact that the utility certificate amendment application is not complete, by Order of the Commission the review process may be stayed until the utility has submitted a complete certificate amendment application;

(c)	Fees. Within sixty days after receipt of the complete certificate amendment application, the Commission shall establish a fee therefor and notify the applicant. Upon receipt of the fee from the applicant, the Commission shall continue its review of the certificate amendment application;

(d)

Waiver of Information. If, after a good-faith effort, the utility cannot provide the data required by these rules, the utility must request a waiver, in writing. This request must be filed no less than 60 days prior to the filing of the amendment. The utility must publish in appropriate media of mass dissemination that it has applied for a waiver. The request shall include:

1.	Reference to the requirement for information that is the subject of the waiver request;

2.	An explanation of the reasons the required information was impractical to supply;

3.	Proposed substitute information, if applicable; If no waiver is granted, materials must be filed as required in the rules.

(e)

Standard for Approval. Based upon the evidence of record presented at hearing on the certificate amendment application, the Commission shall render a decision either approving the certificate amendment, approving it subject to stated conditions, approving it in part and rejecting it in part, rejecting it, or providing an alternate capacity resource certificate amendment within one-hundred eighty days of receipt of fees related to the utility's completed certificate amendment application.

A utility's application shall be approved if found to be in the public interest and to substantially comply with these regulations; and, in the case of any amendment pursuant to which the utility would make any payments to an exempt wholesale generator that is an affiliate or associate of the utility, if the Commission determines:

1.

That the Commission has sufficient regulatory authority, resources and access to books and records of the utility and any relevant associate, affiliate or subsidiary company to exercise its duties under this section of its Rules and under Section 32(k) of the Public Utility Holding Company Act of 1935, as amended; and

2.

That the transaction pursuant to which such payments would be made:

(i)	Will benefit consumers;

(ii)	Does not violate any State law;

(iii)

Would not provide the exempt wholesale generator any unfair competitive advantage by virtue of its affiliation or association with the utility; and

(iv)	Is in the public interest.

(f)

Reciprocal arrangements among companies that are not affiliates or associate companies of each other that are entered into in order to avoid the provisions of this rule or of section 32(k) of the Public Utility Holding Company Act of 1935, as amended, relating to approval of any transaction involving payments by the utility to an affiliate or associate exempt wholesale generator are prohibited.

(5)

The amendment application itself shall contain at a minimum the following information:

(a)	A copy of the original approved certificate, as well as any already approved amendments;

(b)	A narrative explanation of the circumstances requiring amendment of the certificate, including a copy of any new or amended contract(s);

(c)	Updated information, as applicable, regarding the supply-side resource, and its known and reasonably expected effects on the currently approved IRP, as required by Rule 515-3-4-.07;

(d)	Updated information regarding the progress of construction or implementation, as required by Rule 515-3-4-.07(2)(b);

(e)	A cost-benefit analysis covering the estimated useful life of the amended resource, along with a summary comparison of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the amended resource is economic and reliable; and

(f)	A statement showing why the Commission should find that the amendment is in the public interest and substantially complies with these regulations, and, if applicable, should make the determinations specified in subsections (4)(e)1. and 2. above.

Rule 515-3-4-.09 Demand-Side Resource Certificate Filing Requirements and Procedures

(1)

The Utility shall file an application for certification of a demand- side resource as required by O.C.G.A. § 46-3A with the Commission (twenty-five copies). The application for review and approval of the certificate shall clearly identify:

(a)	The name of the applicant(s) and address(es) of the principal place of business of the applicant;

(b)	The name, title, address, voice phone, and facsimile phone number of the person authorized to receive notices and communications with respect to the application;

(c)	The location(s) that the public may inspect a copy of the application; and

(d)	Requests by the utility that any information utilized in the plan which the utility deems trade secret be filed in accordance with the Commission's Trade Secret Rule 515-3-1-.11.

(2)

Hearing and Review of Demand-Side Resources Certificate Applications.

(a)

Proceedings. The Commission shall commence a hearing no sooner than thirty days after receipt of fees related to the utility's completed application for certification of a demand-side resource. A completed application must include all information described in Rule 515-3-4-.04(4) as well as documentation that all applicable state and federal permits required to complete the project have been secured, or, in the event that the permit is unsecurable until an appropriate later phase of project completion, the application process must have been initiated in accordance with applicable federal, state, or local statutes;

(b)

Completeness of the Utility Certificate Application. The Commission shall determine whether the utility certificate application filing is complete within thirty days following the initial submission of the certificate application by the utility. The Commission will inform the utility of substantive defects in the content of the certificate application filing which would materially affect the Commission's ability to continue the certificate application review process. If the Commission finds as a matter of fact that the utility certificate application is not complete, by Order of the Commission the review process may be stayed until the utility has submitted a complete certificate application;

(c)	Fees. Within sixty days after receipt of the completed certificate application, the Commission shall establish a fee therefor and notify the applicant. Upon receipt of the fee from the applicant, the Commission shall continue its review of the certificate application;

(d)

Waiver of Information. If, after a good-faith effort, the utility cannot provide the data required by these Rules, the utility must request a waiver, in writing. This request must be filed no less than 60 days prior to the filing of the certificate application. The utility must publish in appropriate media of mass dissemination that it has applied for a waiver. The request shall include:

1.	Reference to the requirement for information that is the subject of the waiver request;

2.	An explanation of the reasons the required information was impractical to supply; and

3.	Proposed substitute information, if applicable; If no waiver is granted, materials must be filed as required in the Rules.

(e)

Standard for Approval. Based upon the evidence of record presented at the hearing on the application, the Commission shall render a decision either approving the application, approving it subject to stated conditions, approving it in part and rejecting it in part, rejecting it as filed, or providing an alternate capacity resource certification within one-hundred eighty days of receipt of the fees related to the utility's completed application. A utility's application shall be approved if found to be in the public interest and to substantially comply with these regulations; and

(f)

Each utility may file annually one application requesting certification of all demand-side resource activities proposed by the utility for implementation during the program year. The Commission approval of the annual consolidated demand-side resource filing will have the same force as approval of the individual component demand-side programs. The Commission encourages this alternative to filing separate certificate applications for each full-scale and pilot demand-side program.

(3)

The application itself shall contain at a minimum the following information:

(a)	A statement of how the proposed application is consistent with or affects the most-currently approved Integrated Resource Plan (IRP). If a revised IRP is available, it shall also be filed;

(b)	If the demand-side resource is a new resource, information must be provided for it that corresponds to information required for demand-side resources in the IRP Rule 515-3-4-.04(4). Information as to how the resource would affect the IRP must also be furnished;

(c)

A summary description of each program or service to be offered shall include customers and markets targeted, projected market penetration levels, implementation and evaluation schedule, projected capacity and energy savings, participant costs and savings, projected program costs and benefits, data collection activities, process and impact evaluation plans, and expected costs;

(d)

A cost-benefit analysis based on current Commission policy, covering the estimated useful life of the proposed demand-side resource as well as the useful life of the energy efficiency and energy management measures which comprise the demand-side resource, along with a summary comparison of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the proposed resource is economic and reliable; and

(e)

A description of the demand-side resource to include identification of the specific energy efficiency and energy management measures and programs, strategies and type of delivery mechanisms proposed. The description should include at a minimum the information contained in Rule 515-3-4-.04(4), including the following:

1.	Resource Assessment and Program Design. Resource assessment and program design must be consistent with Rule 515-3-4-.04(4)(a) and Rule 515-3-4-.04(4)(b);

2.

Demand-Side Resource Costs:

(i)

Delineation of Program Costs. For each program design, detailed estimates of program costs shall be developed by end-use or program as appropriate. In developing these estimates, the following components of cost shall be separately identified:

(I)	Expected demand-side resource expenditures by program participants, if any;

(II)	Expected demand-side resource expenditures by the utility, if any;

(III)

Expected demand-side resource expenditures by third parties (e.g., Southern Company or energy service company), if any;

(IV)	Utility administrative expenses for the program that add to the total cost of the demand-side resource(s);

(V)	Descriptions of demand-side program related contracts, including where known, scope, type, contractor, cost estimate, contractor selection process and criteria;

(VI)	Cost expenditure plan, by year, to include a breakdown of the following areas: end-use data collection, demand-side program planning, marketing, engineering/design, implementation, start-up, monitoring and evaluation;

(VII)

Total cost estimate to include all work papers and assumptions, broken out by demand-side measure and program, hardware, incentive payments, administrative costs, major design features, and other related activities;

(VIII)

In cases where activities (e.g., market research) associated with demand-side programs, also serve other functions, the allocation of costs among those functions, including separately all costs incurred to date and to-go costs for each area and/or activity;

(IX)	Termination costs;

(X)	Estimated annual capital costs over the life of the resource; and

(XI)	The costs of utility educational and informational activities that are focused on demand-side programs, but that do not directly cause demand-side measure implementation must be separately described.

(ii)	The utility shall provide the design, implementation, monitoring and evaluation activities schedule in milestone summary form; and

(iii)

The utility shall provide where available, a comparison of existing demand-side programs similar in type or design implemented by the applicant or a utility elsewhere.

3.	Projected Effects of Demand-Side Resources. The effects on energy consumption and peak demand of each program design shall be estimated by program;

4.

Program Evaluation. Each utility shall file a summary of the process and load impact evaluation plan, concurrently with the development of the programs themselves, to assess the implementation and quantify the impact on energy and capacity use of the demand- side resources. The evaluation plan shall identify the type and timing of the measurement activity used to evaluate each demandside resource. The evaluation plan shall provide a process by which the results will be used to modify impact estimates for future planning and design of demand-side programs. The plan shall identify procedures to be employed with regard to the following aspects of the evaluation of each program:

(i)

Establishment of protocols to collect basic data regarding load impact, participation level, utility costs, third party costs, and total costs. Load impact data should be aimed at determining load shape impacts, net program savings, useful life of measures and persistence of savings, including utility actions to optimize market penetration of programs; and

(ii)	Comparison of demand patterns of similar participant and nonparticipant groups, and/or use of customer bill analysis, engineering estimates, end-use meter data, or other methods to identify the gross and net impacts of program participation on customers' usage and demand patterns.

5.

Demand-Side Resource Implementation Monitoring. The utility shall file monthly data on a quarterly basis, except as indicated otherwise, the following information regarding demand-side programs to enable the monitoring and evaluation of the program. If, upon review of the information submitted in a quarterly implementation monitoring report, the Commission determines that a change in program design, schedule, cost, or evaluation methodology is substantial enough to warrant the utility filing for a demand-side certificate amendment and the utility has not done so, the amendment process described in Rule 515-3-4-.10 shall be initiated. The quarterly report shall include:

(i)	Sufficient data to confirm that standards of public convenience and necessity are being met in an economic and reliable manner;

(ii)	Cost/benefit analysis using the screening test under which the program was certified; and

(iii)

Data pertaining to various implementation factors. The data shall include:

(I)	Complete documentation of expenditures with comparisons to and calculated variations from original budget, with explanations of variances in excess of five percent (or some other predetermined variation tolerance as specified by the Commission in the approved certificate);

(II)	A completed schedule showing comparison of planned implementation and completion dates for all significant activities and explanations for major variations in planned vs. actual dates;

(III)

Notification of any modifications to the program that do not automatically require amendment, including changes to program evaluation methodology;

(IV)	Major contracts and their scope, in summary form, at such time as they become available;

(V)

The utility shall notify the Commission immediately upon determining that the cost and/or schedule for any demand-side resource has changed from that included in the approved certificate. Revised cost and schedule estimates shall be provided to the Commission in as much detail as has been developed by the utility; and

(VI)	Any other relevant documents used by management to evaluate implementation, if requested.

Rule 515-3-4-.10 Filing Requirements for a Demand-Side Resource Certificate Amendment

(1)

The Utility shall submit an amended application for certification (as the certificate is described under Rule 515-3-4-.09 ) of a full-scale demand-side program in the event that:

(a)	The implementation schedule has significantly changed;

(b)

The total cost estimate has been revised, for reasons other than variances in projected participation levels, such that the costs are over the estimates in the approved certificate by more than five percent or some other variation tolerance as specified by the Commission in the approved certificate;

(c)	Major program design features have changed;

(d)	The results obtained through program monitoring, process or impact evaluation indicate a necessary change;

(e)	The load forecast has changed sufficiently such that the need for a resource of the type/size previously approved may or may not be warranted or sufficient; and

(f)	Any sufficient change in conditions under which the original certificate was approved.

(2)	The Utility shall file with the Commission twenty-five copies of the certificate amendment application.

(3)

The application for review and approval of the certificate amendment shall clearly identify:

(a)	The name of the applicant(s) and address(es) of the principal place of business of the applicant;

(b)	The name, title, address, voice phone, and facsimile phone number of the person authorized to receive notices and communications with respect to the application;

(c)	The location(s) that the public may inspect a copy of the application; and

(d)	Requests by the utility that any information utilized in the plan which the utility deems trade secret be filed in accordance with the Commission's Trade Secret Rule 515-3-1-.11.

(4)

Hearing and Review of Demand-Side Resource Certificate Amendments.

(a)	Proceedings. The Commission shall commence a hearing within no sooner than thirty days after receipt of fees related to a utility's completed certificate amendment application;

(b)

Completeness of the Utility Certificate Amendment Application. The Commission shall determine whether the utility certificate amendment application filing is complete within thirty days following the initial submission of the certificate amendment application by the utility. The Commission will inform the utility of substantive defects in the content of the certificate amendment application filing which would materially affect the Commission's ability to continue the certificate amendment application review process. If the Commission finds as a matter of fact that the utility certificate amendment application is not complete, by Order of the Commission the review process may be stayed until the utility has submitted a complete certificate amendment application.

(c)	Fees. Within sixty days after receipt of the complete certificate amendment application, the Commission shall establish a fee therefor and notify the applicant. Upon receipt of the fee from the applicant, the Commission shall continue its review of the certificate amendment application.

(d)

Waiver of Information. If, after a good-faith effort, the utility cannot provide the data required by these rules, the utility must request a waiver, in writing. This request must be filed no less than 60 days prior to the filing of the amendment. The utility must publish in appropriate media of mass dissemination that it has applied for a waiver. The request shall include:

1.	Reference to the requirement for information that is the subject of the waiver request;

2.	An explanation of the reasons the required information was impractical to supply; and

3.	Proposed substitute information, if applicable; If no waiver is granted, materials must be filed as required by the rules.

(e)

Standard for Approval. Based upon the evidence of record presented at the hearing on the certificate amendment application, the Commission shall render a decision either approving the certificate amendment, approving it subject to stated conditions, approving it in part and rejecting it in part, or rejecting it, or providing an alternate capacity resource certificate amendment within one-hundred eighty days of receipt of fees related to the utility's completed certificate amendment application. A utility's certificate amendment shall be approved if found to be in the public interest and to substantially comply with these regulations.

(5)

The amendment application itself shall contain at a minimum the following information:

(a)	A statement of how the proposed application is consistent with the most-currently approved Integrated Resource Plan (IRP). If a revised IRP is available, it shall be filed also;

(b)	A copy of the originally approved certificate, as well as any already approved amendments;

(c)	A narrative explanation of the circumstances requiring amendment of the certificate;

(d)	Updated information, as applicable, regarding the demand-side resource, as required by Rule 515-3-4-.09;

(e)	Updated information, as applicable, regarding the progress of construction or implementation, as required by Rule 515-3-4-.09(3)(e)5; and

(f)

A cost-benefit analysis covering the estimated useful life of the amended demand-side resource as well as the useful life of the energy efficiency and energy management measures which comprise the demand-side resource, along with a summary comparison of the benefits and costs of other alternatives considered in the preparation of the applicant's IRP, sufficient to demonstrate that the amended resource is economic and reliable.

Rule 515-3-4-.11 Cost Recovery and Financial Incentives

(1)

Recovery of the costs of developing an integrated resource plan or an amendment thereto.

(a)	Fees paid by the utility accompanying a plan filing are expressly excluded from cost recovery; and

(b)	All costs incurred by a utility in developing its plan must be accounted for in its books and records separately from amounts attributable to any of its other activities. All accounts, including subaccounts, must be maintained in such a manner as will allow these costs to be identified readily.

(2)

Recovery of costs for certificate application and certificate amendments.

(a)	Fees paid by the utility accompanying a certificate application or an amendment application are excluded from cost recovery unless the application or amendment is approved; and

(b)

All costs incurred by a utility in developing its certificate application or amendment must be accounted for in its books and records separately from amounts attributable to any of its other activities. All accounts, including subaccounts, must be maintained in such a manner as will allow these costs to be identified readily.

(3)

Recovery of Certified Costs and Financial Incentive Mechanisms.

(a)

The certified or actual cost, whichever is less, of purchase of any certificated long-term power purchase shall be recovered in rates by the utility along with the additional sum as determined by the Commission to encourage such purchases. The Commission shall consider lost revenues, if any, changed risks, and an equitable sharing of benefits between the utility and its retail customers; and

(b)

The certified or actual cost, whichever is less, of any certificated demand-side capacity option shall be recovered by the utility in rates, along with an additional sum as determined by the Commission to encourage the development of such resources. The Commission shall consider lost revenues, if any, changed risks, and an equitable sharing of benefits between the utility and its retail customers.

Rule 515-3-4-.12 Amendments to Rules and Severability

(1)	These Rules may be amended at any time by the Commission as provided for by the Administrative Procedures Act, O.C.G.A. § 50-13-4; and

(2)	If any provision of this Chapter of the Rules is held invalid, the Commission intends that such invalidity not effect the remaining provisions to the extent that they can be given effect.

Full Name:
Human verification: 6 + 1 =