Subject 515-7-2 GAS SUPPLY PLANS AND GAS COST ADJUSTMENT FACTORS

Rule 515-7-2-.01 Commission Authority and Scope of Provisions

Consistent with Official Code of Georgia Annotated (O.C.G.A) § 46-2-26.5, each Gas Utility in the state of Georgia subject to the jurisdiction of the Public Service Commission (hereinafter "Commission") shall be required to develop and file for the Commission's review and approval Gas Supply Plans and Adjustments Factors, as described by the regulations in this Rule. These regulations establish guidelines for the development and submission of Gas Supply Plain and Adjustment Factors, including filing requirements enabling Commission oversight, review and monitoring, establish hearing procedures, and provide for the periodic review of each Utility's Gas Supply Plan and Adjustment Factor. Interim monitoring is established through the reporting requirements. These regulations also provide for Gas Supply Plan amendments and Adjustment Factor revisions.

(2)	The requirements of this Rule shall apply to any Purchased Gas Adjustment Rate. The requirements of O.C.G.A. § 46-2-25 shall not apply to filings made or proceedings conducted pursuant to O.C.G.A. § 46-2-26.5 and this Rule.

(3)

In the event of any conflict between the provisions of this Rule and applicable provisions of the Official Code of Georgia Annotated, including O.C.G.A. § 46-2-26.5 as it may be amended from time to time, the applicable provisions of the O.C.G.A. shall take precedence. Any such conflict as to one provision of this rule shall not, however, void or nullify any remaining provisions of this rule.

Rule 515-7-2-.02 Definitions

As used in this Utility Rule 515-7-2, the following terms shall have the following definitions:

(a)	Adjustment Factor: A numerical factor used pursuant to a Purchased Gas Adjustment Rate to recover Purchased Gas Costs.

(b)	Firm Customer: A customer who purchases gas from a Utility on a firm basis which ordinarily is not subject to interruption or curtailment.

(c)	Gas Supply Plan: The particular array of available gas supply, storage, and transportation options selected by a Utility to supply the requirements of its firm customers.

(d)	Utility: A gas Utility providing gas sale and other services subject to the jurisdiction of the Commission.

(e)

Integrated Resource Plan (MP): A Utility resource planning process and the plan which results from that process, in which an integrated combination of demand-side and supply-side resources including load management is selected to satisfy future energy service demands at the best cost (considering direct and indirect costs) to society, balancing the interests of Utility Customers, Utility shareholders and the public interest.

1.

A demand-side resource is any resource that affects the demand for or usage of gas as a result of programs (demand-side programs) to implement demand-side measures. A demand-side measure is any hardware, equipment or practice which is installed or instituted for energy efficiency or energy management purposes.

2.	A supply-side resource is any resource that can provide for a supply of gas on a firm or non-firm basis to the Utility.

(f)	Purchased Gas Adjustment Rate: A Purchased Gas Adjustment rider or similar rate, provision, or clause in the tariff of a Utility pursuant to which Purchased Gas Costs are billed to the firm customers of the Utility.

(g)

Purchased Gas Costs: All costs incurred by a Utility for the purpose of acquiring gas delivered to its system in order to supply its firm customers, including, without limitation, the costs incurred in purchasing gas from sellers; the costs incurred in transactions involving rights to buy and sell gas; the costs incurred in gathering gas for transportation to the Utility; the costs incurred in transporting gas to the facilities of the Utility; the costs incurred in acquiring and using gas storage service from others, including costs of injecting and withdrawing gas from storage; and all charges, fees, and rates incurred in connection with such purchases, rights, gathering, storage, and transportation.

(h)	Recovery Year: The 12 calendar months commencing October 1, 1994, and ending September 30, 1995, and each succeeding 12 calendar month period thereafter.

Rule 515-7-2-.03 Hearing Procedures

(1)	Not less than ten days after any filing by a Utility of its Gas Supply Plan for the following Recovery Year, the Commission shall conduct a public hearing on such filing. The Utility's testimony shall be under oath and shall, with any corrections thereto, constitute the Utility's affirmative case.

(2)	The provisions of law relating to parties, intervention, and discovery in proceedings before the Commission shall apply with respect to proceedings under O.C.G.A. § 46-2-26.5. However, the requirements of O.C.G.A. § 46-2-25 shall not apply to such proceedings.

(3)	At any hearing conducted pursuant to O.C.G.A. § 46-2-26.5, the burden of proof to show that the proposed Gas Supply Plan and Adjustment Factors are appropriate shall be upon the Utility.

(4)

Following such a hearing, the Commission shall issue an order approving the Gas Supply Plan filed by the Utility or adopting a Gas Supply Plan for the Utility that the Commission deems appropriate. In addition, the Commission in its order shall approve the Adjustment Factors proposed by the Utility or adopt Adjustment Factors that the Commission deems appropriate.

(5)

If, for any reason, the Commission does not issue an order by the 45th day after the Utility's filing which either approves the Gas Supply Plan filed by the Utility or adopts a different Gas Supply Plan for the Utility, the Gas Supply Plan proposed by the Utility shall thereupon be deemed approved by operation of law.

(6)

If, for any reason, the Commission does not issue an order by the 45th day after the Utility's filing which either approves the Adjustment Factor(s) proposed by the Utility or adopts a different Adjustment Factor(s) for the Utility, the Adjustment Factors proposed by the Utility shall thereupon deemed approved by operation of law.

(7)

All Commission orders issued pursuant to O.C.G.A. § 46-2-26.5 shall contain the Commission's findings of fact and conclusions of law upon which the Commission's action is based. Any such order shall be deemed a final order subject to judicial review under Chapter 13 of O.C.G.A. Title 50, the "Georgia Administrative Procedure Act."

Rule 515-7-2-.04 Minimum Filing Requirements

(1)

On or before August 1 of each year, each Utility shall file with the Commission its Gas Supply Plan for the following Recovery Year. Such filing shall be in addition to any compliance filing the Commission may require for the current Recovery Year. The Utility shall include with such filing the Adjustment Factors it proposes for recovering its Purchased Gas Costs during such following Recovery Year, together with the calculation that produced such factors.

(2)

As part of its annual gas Supply Plan and Adjustment Factor filing, each Utility shall include the following as minimum filing requirements:

(a)

A five year forecast. This forecast need not be in the same detail as the Recovery Year forecast. Nevertheless, there must be sufficient information in this forecast to enable the Commission to evaluate the reasonableness of the Utility's long-term contracts and the effectiveness of any IRP applicable to the Utility.

(b)	A summary of the impact of any IRP on the Supply Plan. In view of the relative importance of capacity costs to the Utility's Adjustment Factor, the emphasis of this section of the Supply Plan shall reflect the success of reducing peak load requirements and improving load factors.

(c)

The Utility's most recent 12-month actual data pertaining to requirements and gas supply costs, together with an explanation of how such data support the reasonableness of the Utility's forecast for the Recovery Year.

Actual data shall include the following:

1.	Actual firm and interruptible sales and transportation volumes by rate schedule or customer class.

2.

For the Utility's most recent peak day, a summary of:

(i)	The gas supply, storage, and transportation options in the applicable Supply Plan that were available and utilized; and

(ii)	The actual throughput to firm and interruptible customers, which in the case of firm customers shall be broken down by rate schedule or customer type, and in the case of interruptible customers shall be broken down by sales and transportation volumes.

3.

A complete history of the Utility's capacity release and acquisition activity during the historic period, including for each transaction:

(i)	The applicable pipeline, quantity, price, release period, and revenues or costs;

(ii)	The maximum lawful rate for capacity release on the pipeline;

(iii)

Whether recall conditions were placed on the release and whether the capacity was recalled prior to the expiration of the release period;

(iv)	Whether the capacity release had been prearranged at a price other than the maximum lawful price and had not been subject to bid; and

(v)	Whether the capacity release had been listed on the pipeline's bulletin board.

4.	The utilization of all firm capacity and all contracted supply the Utility purchased from pipelines individually and well-head purchases in the aggregate. The pipeline information shall include data separately stated for all firm transportation and storage contracts.

5.	End-of-month storage level by storage service.

(d)

A Gas Supply Plan and Adjustment Factor for the Recovery Year, which shall consist of at least the following:

1.

For the Utility's Gas Supply Plan design day, monthly and annual requirements:

(i)	Detailed description of forecast methodology(ies);

(ii)	Level of projected requirements of firm and interruptible customers, which in the case of firm customers shall be broken down by rate schedule or customer class, and in the case of interruptible customers shall be broken down by sales and transportation volumes;

(iii)

Supply options selected to meet requirements; and

(iv)	Projected utilization of supply options selected to meet requirements.

2.

Summary of all individual contracts with interstate pipelines, gas suppliers, or any other party whose contract, or purchase agreement, affects the Utility's Gas Supply Plan and Adjustment Factor. At a minimum, summaries will include: parties, terms, volumes (annual, seasonal, daily and minimum purchases requirement), prices and rates, and description of all services provided. Summaries of storage services shall include a description of the method of transportation to and from storage, and whether transportation services are included in the contracts with the storage services.

Exceptions to this filing requirement are:

(i)	Short term (31 days or less) gas supply contracts; and

(ii)	Contracts that contain "Trade Secret" documents.

(iii)

With respect to the "Trade Secret" contracts, the Utility must state the number of "Trade Secret" contracts, state reasons why they are "Trade Secret" documents, provide a summary of these contracts in aggregate form, and flow the Commission Staff (or Staff representatives subject to appropriate confidentiality agreements) to review these contracts as part of the Supply Plan review. With respect to the short term contracts, the Utility must state the number of short term contracts and provide a summary of these contracts in aggregate form.

3.	The proposed utilization of all projected capacity and gas supply the Utility will purchase from pipelines and producers. This information will be provided on a contract-by-contract basis. "Trade Secret" contract information can be provided in aggregate.

4.	An explanation of how the Utility determined any estimated Gas Supply Realignment (GSR) and transition costs, including the levels of such costs, the outstanding balance at the commencement of the Recovery Year and the expected outstanding balance at the end of the Recovery Year.

5.	Projected end-of-month storage levels by storage service.

6.

A disaggregation of the commodity and demand charges reflected in the Adjustment Factors. At a minimum, the actual pipeline rates for each service shall be shown, and commodity costs shall be stated separately for projected gas costs, variable pipeline costs and fuel rates. Pipeline fuel costs should be shown as they are projected to be incurred, either as gas delivered in kind or as the dollar amount expected to be paid by the Utility to the pipeline.

(e)	The requirements of O.C.G.A. § 46-2-25 shall not apply to filings made pursuant to O.C.G.A. § 46-2-26.5 and this Rule.

Rule 515-7-2-.05 Plan and Adjustment Factor Requirements

(1)	The Adjustment Factor approved or adopted by the Commission, or otherwise made effective under O.C.G.A. § 46-2-25, shall be applied uniformly to all firm customers upon the effective date of such factors.

(2)

The Adjustment Factor to be effective during the Recovery Year commencing October 1, 1994 shall be set at a level appropriate to account for under-recoveries or over-recoveries, if any, under the Purchased Gas Adjustment Rate of the Utility in effect prior to October 1, 1994. The Adjustment Factor to be applicable during each Recovery Year commencing October 1, 1995, and thereafter, shall be set at a level appropriate to account for under-recoveries or over-recoveries during the preceding Recovery Year.

(3)

The Commission shall not prohibit or limit the operation of a Purchased Gas Adjustment Rate of a Utility to the extent that the adjustment permits increases or decreases to adjust for increased or decreased Purchased Gas Costs when such increased or decreased Purchased Gas Costs shall have become effective under the procedures of a federal regulatory agency or under a contract approved by a federal regulatory agency. Any subsequent refunds received by a Utility which become effective under procedures of a federal regulatory agency, or otherwise, shall be treated by the Utility in such manner as the Commission may direct. Unless the Commission directs otherwise, if a Utility receives such refunds in an amount in excess of the product of $2.00 and the average number of customers of the Utility during the preceding fiscal year, the Utility shall notify the Commission of such refunds, and submit a proposal for the regulatory treatment of such refunds, within 30 days of receipt of the same. Unless otherwise directed, the Utility shall include any other refund in subsequent Adjustment Factor calculations.

(4)

Any Purchased Gas Costs which are incurred by a Utility in accordance with a Gas Supply Plan which was in effect pursuant to the provisions of O.C.G.A. § 46-2-26.5 at the time such costs were incurred may be recovered by the Utility under its Purchased Gas Adjustment Rate, and shall not be disallowed retroactively by the Commission in the absence of fraud or willful misconduct on the part of the Utility. The Commission may, however, disallow and make appropriate adjustments to any Purchased Gas Costs that were not incurred in accordance with the Utility's Gas Supply Plan if the same resulted in higher Purchased Gas Costs and were the result of clearly imprudent conduct on the part of the Utility. The provisions of this Rule shall not prohibit the Commission from authorizing a Utility to recover under a Purchased Gas Adjustment Rate costs or amounts in addition to the Recovery Year. The Utility must also file a statement describing the reason for the proposed revision.

Rule 515-7-2-.06 Gas Supply Plan Amendments

(1)

After a Gas Supply Plan has become effective under the provisions of O.C.G.A. § 46-2-26.5 and as a result of a proceeding before the Commission, the Commission shall retain jurisdiction for the balance of the Recovery Year for the purposes set forth in this section. Upon the application of the affected Utility or upon its own initiative, the Commission may, after affording due notice and opportunity for hearing to the affected Utility and the intervenors in the proceeding, amend the Gas Supply Plan of the affected Utility for the remainder of the Recovery Year. The amended Gas Supply Plan shall become effective upon the date of the Commission's order and shall not have retroactive effect.

(2)

If the amendment of the Utility's Gas Supply Plan would lead to any change in the Utility's Adjustment Factors, the Utility shall We proposed revisions to the Adjustment Factors, either in its next quarterly adjustment factor proposed revision pursuant to Rule 515-7-2-.07 or within 30 days of the effective date of the amendment, whichever date is sooner. In no event, however, shall the Utility be required to file the proposed revisions sooner than 15 days after the Commission has adopted the amended Gas Supply Plan.

Rule 515-7-2-.07 Gas Cost Adjustment Factor Revisions

(1)

At least every three calendar months, the Utility shall file proposed revisions to its Adjustment Factors based on actual unrecovered Purchased Gas Costs in order that the revenues to be recovered pursuant to such rate during the remainder of the current Recovery Year shall equal, as nearly as possible, the Utility's unrecovered Purchased Gas Costs through the end of such Recovery Year. The revisions to the Adjustment Factors, if any, shall be made to the nearest 0.01¢ per them.

(2)	Unless the Commission directs otherwise, such revised Adjustment Factors shall become effective on the first day of the first calendar month that begins at least 15 days after the date of such filing.

(3)

The format set forth in paragraph 515-7-2-.08 shall be used for any proposed revisions to the Adjustment Factors during the Recovery Year covered by the Gas Supply Plan. In addition, any filing to revise the Adjustment Factors shall report the projected volumes, rates and cost information for the remainder of each month for the Recovery Year. Actual volumes, rates and costs incurred to date shall also be reported. The Utility must demonstrate that the New Adjustment Factors will recover approximately the Purchased Gas Cost (PGC) (plus or minus the existing PGC balance) over the remainder of Purchased Gas Costs, nor shall the provisions of this Rule prohibit the Commission from removing from Purchased Gas Costs those costs incurred by a Utility for the purpose of acquiring gas to supply customers who are not firm customers.

Rule 515-7-2-.08 Monthly and Quarterly Informational Filing Requirements

(1)

The Utility shall file monthly with the Commission information that demonstrates whether its actual monthly Purchased Gas Costs were incurred in accordance with a Gas Supply Plan which had become effective in accordance with the provisions of O.C.G.A. § 46-226.5. This monthly report to the Commission will show these data for the most recent month with not more than a three month lag, each individual previous month of the Recovery Year, and year-to-date totals. The format of such filings will be as set forth in Tables 1, 2, 3, 4, and 5 in the Appendix to this Rule, or in a similar format if it contains substantially the same information. Purchased Gas Costs will be documented by reporting monthly rates and prices for supplies and services purchased, and by reporting monthly billing units and gas supplies volumes. (Rates/prices applied to billing units/volumes should equal monthly costs.)

(2)

Each Utility shall also file monthly with the Commission the most current data available showing over-recoveries or under-recoveries of actual Purchased Gas Costs resulting nol application of its Purchased Gas Adjustment Rate. Such data will be reported for the current month, for each individual previous month of the Recovery Year, and year-to-date (see Table 6 in the Appendix to this Rule).

(3)

Whenever the Utility enters into a new firm contract, or renews, cancels or materially amends an existing contract to purchase gas supply, transportation or underground storage, or any other service authorized in its Gas Supply Plan, it shall notify the Commission by an informational filing within 30 days of the change to the contract's status.

(4)

The Utility shall include in its Supply Plan monthly projections between the conclusion of the twelve month actual historical period and the Recovery Year. These interim data will be provided in a similar format to the monthly reconciliation filings, comparing actual volumes, revenues and Purchased Gas Costs with projections (see Tables 1-5 in the Appendix to lids Rule). These projected data will assist in the determination of the final under-recovery (or over-recovery) of Purchased Gas Costs that will be allowed in the Adjustment Factors for the upcoming Recovery Year.

APPENDIX

Table 1

PROJECTED VS. ACTUAL SALES (THROUGHPUT) (Dth)

		Current Month(s)	Current Month(s)	Recovery Year-to-Date
A.	Projected Sales
	Firm Sales by Rate Schedule or Customer Class
	Total Firm Sales
	Total Interruptible Sales
	Transportation
	Total Throughput
B.	Actual Sales
	Firm Sales by Rate Schedule or Customer Class
	Total Firm Sales
	Total Interruptible Sales
	Transportation
	Total Throughput
C.	Over/(Under) Project Volumes (Projected Minus Actual)
	Firm Sales by Rate Schedule or Customer Class
	Total Firm Sales
	Total Interruptible Sales
	Transportation
	Total Throughput

Table 2

PROJECTED VS. ACTUAL REVENUES PURSUANT TO PGA

(Dollars)

		Current Month(s)	Current Month(s)	Recovery Year-to-Date
A.	Projected Sales Revenues Pursuant to PGA^a/
	Firm Sales by Rate Schedule or Customer Schedule
	Total Firm Sales
	Total Interruptible Sales
	Transportation
	Total Revenues
B.	Actual Sales Revenues Purusuant to PGA^b/
	Firm Sales by Rate Schedule or Customer Class
	Total Firm Sales
	Total Interruptible Sales
	Transportation
	Total Revenues
C.	Over/(Under) Projected Volumes (Projected Minus Actual)
	Firm Sales by Rate Schedule or Customer Class
	Total Firm Sales
	Total Interruptible Sales
	Transportation
	Total Revenues

^a/Projected sales times effective PGA gas cost recovery factor.

^b/Actual sales times effective PGA gas cost recovery factor.

Table 3

PROJECTED VS. ACTUAL GAS COSTS

(Dollars)

		Current Month(s)	Previous Month(s)	Recovery Year-to-Date
A.	Projected GPA Gas Cost
	Commodity Component
	FT/FS Purchases
	Storage Commodity
	Other (list)
	TOTAL
	Demand Component
	FT Demand
	Storage Demand
	Supply Reservation Fee
	Transition Cost
	GSR
	Other (list)
	TOTAL
B.	Actual Gas Costs
	Commodity Component
	FT/FS Purchases
	Storage Commodity
	Other (list)
	TOTAL
	Demand Component
	FT Demand
	Storage Commodity
	Supply Reservation Fee
	Transition Cost
	GSR
	Other (list)
	TOTAL
C.	Over/(Under) Projected Costs (Projected Minus Actual)
	Commodity Component
	FT/FS Purchases
	Storage Commodity
	Other (list)
	TOTAL
	Demand Component
	FT Demand
	Storage Demand
	Supply Reservation Fee
	Transition Cost
	GSR
	Other (list)
	TOTAL

Table 4

PROJECTED VS. ACTUAL GAS COSTS

(Dollars)

		Current Month(s)	Previous Month(s)	Recovery Year-to-Date
A.	Projected PGA Rates/Prices
	Commodity Component
	FT/FS Purchases
	Storage Commodity
	Other (list)
	TOTAL
	Demand Component
	FT Demand
	Storage Demand
	Supply Reservation Fee
	Transition Cost
	GSR
	Other (list)
	TOTAL
B.	Actual Rates/Prices
	Commodity Component
	FT/FS Purchases
	Storage Commodity
	Other (list)
	TOTAL
	Demand Component
	FT Demand
	Storage Commodity
	Supply Reservation Fee
	Transition Cost
	GSR
	Other (list)
	TOTAL

Table 5

PROJECTED VS. ACTUAL GAS COSTS

(Dollars)

		Current Month(s)	Previous Month(s)	Recovery Year-to-Date
A.	Projected PGA Purchase Volume
	Commodity Component
	FT/FS Purchases
	Storage Commodity
	Other (list)
	TOTAL
	Demand Component
	FT Demand
	Storage Demand
	Supply Reservation Fee
	Transition Cost
	GSR
	Other (list)
	TOTAL
B.	Actual Gas Purchase Volumes
	Commodity Component
	FT/FS Purchases
	Storage Commodity
	Other (list)
	TOTAL
	Demand Component
	FT Demand
	Storage Commodity
	Supply Reservation Fee
	Transition Cost
	GSR
	Other (list)
	TOTAL

Table 6

PGA REVENUES VS. PGA COSTS

(Dollars)

		Current Month(s)	Previous Month(s)	Recovery Year-to-Date
A.	Actual PGA Revenues (Table 2)
	Firm Sales Revenues
	Interruptible Sales Revenues
	Total PGA Revenues
B.	Actual PGA Costs (Table 3)
	Total Gas Cost
	Capacity Release/IT Credit
	Refunded Total Cost
C.	Revenue/Gas Cost Balance

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