Vol. 36 Iss. 18 - April 27, 2020

Chapter 311
Final Regulation

REGISTRAR'S NOTICE: The State Corporation Commission is claiming an exemption from the Administrative Process Act in accordance with § 2.2-4002 A 2 of the Code of Virginia, which exempts courts, any agency of the Supreme Court, and any agency that by the Constitution is expressly granted any of the powers of a court of record.

Titles of Regulations: 20VAC5-200. Public Utility Accounting (repealing 20VAC5-200-10).

20VAC5-300. Energy Regulation; In General (repealing 20VAC5-300-10, 20VAC5-300-30, 20VAC5-300-50, 20VAC5-300-60, 20VAC5-300-80, 20VAC5-300-100).

20VAC5-306. Standards for Integrated Resource Planning and Investments in Conservation and Demand Management for Natural Gas (repealing 20VAC5-306-10 through 20VAC5-306-40).

20VAC5-311. Interim Rules Governing Electric and Natural Gas Retail Access Pilot Programs (repealing 20VAC5-311-10 through 20VAC5-311-60).

20VAC5-317. Rates for Standby Service Furnished to Certain Renewable Cogeneration Facilities Pursuant to § 56-235.1:1 of the Code of Virginia (repealing 20VAC5-317-40).

20VAC5-320. Regulations Governing Transfer of Transmission Assets to Regional Transmission Entities (repealing 20VAC5-320-120).

Statutory Authority: § 12.1-13 of the Code of Virginia.

Effective Date: April 14, 2020.

Agency Contact: Andrea Macgill, Associate General Counsel, State Corporation Commission, P.O. Box 1197, Richmond, VA 23218, telephone (804) 371-9064, FAX (804) 371-9240, or email


The amendments repeal certain obsolete regulations and schedules that (i) have been replaced by regulations in another chapter, (ii) are duplicative of State Corporation Commission orders or partial orders, or (iii) require certain utilities to submit filings with the commission on or before dates in the past.




CASE NO. PUR-2019-00219

Ex Parte: In the matter of repealing regulations


On January 9, 2020, the State Corporation Commission ("Commission") issued an Order Initiating Rulemaking Proceeding in this docket for the purpose of repealing numerous regulations adopted by the Commission pursuant to § 12.1-13 of the Code of Virginia ("Code"), as well as various statutes in Title 56 of the Code. These regulations are codified in Title 20 of the Virginia Administrative Code ("VAC").

The Commission's Order Initiating Rulemaking Proceeding proposed to repeal certain regulations on the basis that they (1) contain certain obsolete rules and schedules that are no longer required, or (2) are duplicative of Commission orders or partial orders and it is not necessary for such orders to be included in the VAC. The regulations that the Commission proposed to repeal included the following: 20 VAC 5-200-10; 20 VAC 5-300-10; 20 VAC 5-300-30; 20 VAC 5-300-50; 20 VAC 5-300-60; 20 VAC 5-300-80; 20 VAC 5-300-100; 20 VAC 5-306-10 et seq. (entire chapter); 20 VAC 5-311-10 el seq. (entire chapter); 20 VAC 5-317-40; and 20 VAC 5-320-120.

Interested persons were given the opportunity to comment or request a hearing on the proposed repeal of these regulations. No person filed comments, nor did anyone request a hearing in this matter.

NOW THE COMMISSION, upon consideration of this matter, is of the opinion and finds that the regulations set forth in the Commission's Order Initiating Rulemaking Proceeding in this docket should be repealed.

Accordingly, IT IS ORDERED THAT:

(1) The regulations appended hereto as Appendix A are hereby repealed effective April 1,2020.

(2) A copy of this Order and the rules repealed herein shall be provided to the Register of Regulations for appropriate publication.

(3) There being nothing further to come before the Commission, this case is hereby dismissed.

AN ATTESTED COPY hereof shall be sent by the Clerk of the Commission to: C. Meade Browder, Jr., Senior Assistant Attorney General, Division of Consumer Counsel, Office of the Attorney General, 202 N. 9th Street, 8th Floor, Richmond, Virginia 23219-3424. A copy hereof shall be delivered to the Commission's Office of General Counsel and the Divisions of Public Utility Regulation and Utility Accounting and Finance.

20VAC5-200-10. Adoption of revised uniform system of accounts for gas utilities. (Repealed.)

At the National Association of Regulatory and Utilities Commissioners' (NARUC) convention held in Phoenix, Arizona, on November 17-20, 1958, resolutions were adopted recommending to the commissions represented by membership in the Association the adoption of revised Uniform Systems of Accounts for Gas Utilities. This system of accounts was published and adopted by a number of state commissions, including this Commission.

Although there have been numerous changes in accounting principles and practices and although the Federal Power Commission has adopted numerous amendments to the systems of accounts that it prescribes for gas utilities, there have been no amendments to the NARUC system since it was issued in 1958.

Realizing the need to bring the NARUC system up-to-date, the NARUC Accounting Committee undertook a complete review of the presently recommended system of accounts. The review of the system of accounts has been completed by the Association's Committee on Accounts and Statistics, and the Committee's recommended revisions have resulted in adoption and recommendation of a new, revised system of accounts by the NARUC.

Also, this Commission is aware that the Federal Power Commission, by order No. 490 issued on August 22, 1973, has eliminated Account No. 271 - Contributions In Aid of Construction - and prescribed disposition of the balance in such account and the treatment of future contributions in aid of construction. This change was not included in the NARUC recommended revised system of accounts.

NOW, UPON CONSIDERATION, the Commission is of the opinion and finds:

1. That the system of accounts for gas utilities prescribed by this Commission should be revised to conform with the recommended revisions of the NARUC except in regard to Account No. 271. The Commission's prescribed treatment of contributions in aid of construction should be substantially the same as that of the Federal Power Commission;

2. That, however, the gas utilities under the jurisdiction of the Commission should continue to maintain the amounts of contributions in aid of construction on a memorandum basis for tax and other related purposes where such detail is needed;

3. That implementation of the revised system of accounts for gas utilities should become effective January 1, 1974, and the gas utilities should implement a memorandum record of contributions in aid of construction at that time; accordingly


1. That the uniform system of accounts for gas utilities prescribed by the Commission, effective January 1, 1961, be discontinued and cancelled as of January 1, 1974;

2. That every gas utility company operating in this Commonwealth shall institute and place into effect a system of accounts in accordance with the rules and regulations set forth in the Uniform System of Accounts for Gas Utilities, Classes A and B, C or D as applicable to it, prepared by the Committee on Accounts and Statistics of the National Association of Regulatory and Utilities Commissioners and filed with this order marked respectively as "Uniform System of Accounts For Class A and B Gas Utilities," "Uniform System of Accounts For Class C Gas Utilities," and Uniform System of Accounts For Class D Gas Utilities," such system of accounts to become effective, except for Account No. 271 - Contributions in Aid of Construction;

3. That the Acting Chief Accountant to the Commission shall cause to be prepared a written directive setting forth treatment for contributions in aid of construction in substantial compliance with the ordering provisions of Federal Power Commission Order No. 490 and upon approval of such directive by the Commission, the same shall be forwarded to each gas utility and shall replace and supersede all prescribed treatment in the NARUC recommended system of accounts in conflict therewith; and, that the Acting Chief Accountant shall cause to be prepared as an addendum to the written directive, an instruction for the approval of the Commission, prescribing the memorandum record which shall be maintained for contributions in aid of construction for tax and other administrative purposes;

4. That effective January 1, 1974, every gas utility operating in this Commonwealth shall commence to keep its books and records in accordance with the system of accounts and the written directive for contributions in aid of construction filed herein;

5. That an attested copy of this order, together with, or as soon hereafter as available, the revised system of accounts and written directive and addendum of the Acting Chief Accountant, shall be sent to each gas utility operating in this Commonwealth.

20VAC5-300-10. Investigation of promotional allowances and practices of public utilities. (Repealed.)


This proceeding was instituted by order of the Commission on April 12, 1966. The order instituted an investigation to determine:

(a) What promotional allowances are offered, made or given to anyone or what promotional practices are used or followed with respect to anyone by the public utilities which are parties to this proceeding in connection with the furnishing or the offer to furnish in this State of either electric energy or gas for heat, light or power;

(b) Whether any such promotional allowances or practices are in violation of the laws of this State; and,

(c) What action should be taken by the Commission in the public interest with respect to any such promotional allowances or practices.

This Commission has had jurisdiction over such matters since its creation as the governmental agency regulating public utilities. Also, utility companies have engaged in promotional practices, including the giving of promotional allowances and similar inducements to the use of their service, for many years. The Commission has received no complaints from consumers in connection with such promotional practices, and in fact no formal complaint has ever been filed with respect to such practices except to the extent that the testimony, arguments and briefs of the parties in this proceeding constitute such complaints.

In the 1966 Session of the Virginia General Assembly representatives of the fuel oil dealers were responsible for the introduction of a bill which would have made unlawful promotional allowances and practices of the types engaged in by many utility companies. This legislation was not passed by the General Assembly, but in its place there was enacted a provision directing the Commission to investigate the promotional allowances and practices of public utilities and take such action as such investigation may indicate to be in the public interest.

On February 7, 1966, prior to the introduction of this bill, the Commission directed each electric and gas utility operating within the State of Virginia to furnish to the Commission a copy of the sales promotional programs which they had in use. This was done by the utilities, and these promotional programs are the subject of this proceeding.

Pursuant to the order of April 12, 1966, a hearing on this matter was held on June 20, 21 and 22, 1966. The electric utilities, the gas utilities and the fuel oil dealers appeared and were represented by counsel. The electric and gas utilities presented a great deal of frequently repetitious evidence in support of their positions. The fuel oil dealers, however, did not offer any evidence, stating that it would only be repetitious of that presented by the gas utilities. Opening briefs were filed by the electric and gas utilities on September 1, 1966, and reply briefs were filed on September 21, 1966.

At the hearing and in their briefs the electric utilities concentrated on justifying their promotional allowances and practices and did not concern themselves with the allowances and practices of their competitors. Conversely, the gas utilities concentrated on challenging the allowances and practices of the electric utilities and made no attempt to justify their own, other than as being necessary to compete with the practices of the electric utilities.

The basic position of the electric utilities may be summarized generally as follows: promotional allowances and underground wiring programs are desirable and in the public interest because they stimulate the growth of use of electricity and this growth is necessary to keep electric rates low; the uses of electricity which are promoted in this fashion are uses which have high revenues in relation to costs and therefore are desirable uses from the utility's point of view; the allowances and underground wiring practices are not discriminatory because the benefits of them are available to all customers who meet the objective requirements which have been established; the size of the allowances and costs of other promotional practices are not large enough to impose a burden on customers in other classes and are recovered in a reasonably short period of time; and it is in the public interest for utility management to be flexible and imaginative in promoting increased sales of electricity. In opposition to this, the contentions of the gas utilities may be likewise generally summarized; promotional allowances and underground wiring programs are unjustly discriminatory in that they confer benefits upon some customers and deny those benefits to others within the same general classification of service; the practices of the electric companies are in violation of their filed tariffs; the revenues generated as a result of the challenged promotions, when all the costs of generating those revenues are taken into account, are insufficient to permit the electric companies to recover those costs in a reasonable time and therefore there is discrimination against other customers; and the public interest requires that all cash allowances and similar inducements be prohibited and that underground electric service be furnished only upon payment of the additional cost of such service by the person who benefits from it.

At the outset the electric utilities also defended certain promotional programs which guaranteed to electric heating customers that their heating bills would not exceed certain amounts or that they would be satisfied in every respect with such electric heat, and the gas utilities likewise opposed these programs. During the hearing the Commission, in an interim ruling which is hereby reaffirmed1, declared that such programs were unlawful and had to be discontinued, and the electric utilities have not pursued this matter any further.

The principal questions to be determined in this proceeding are whether utility promotional allowances and practices constitute "unjust discrimination" in violation of § 56-247 of the Code of Virginia, and what action is necessary to eliminate or prevent such unjust discrimination.

The evidence in this proceeding, particularly the report of Ernest M. Jordan, Jr., Assistant Engineer of the Commission (Exhibit No. 1), shows a variety of promotional allowances and practices by the utilities. The principal challenge (other than with respect to those guarantees of cost and satisfaction which have already been held to be invalid) has been to the payment of cash incentives for the installation of certain electric appliances and to the furnishing of underground distribution at partial or no cost to customers who make certain uses of electricity.

In general the payment of cash allowances or incentives was not shown to be illegal or contrary to the public interest in this case. The programs under which such payments are made do provide for varying treatment of customers within residential, commercial and industrial classifications. However, these classifications are not exclusive, and reasonable subclassifications may be made. In general, the classifications made by the electric utilities in their promotional programs are those based on the amount and character of the consumption of electricity: Gold Medallion homes, homes with electric heat, homes with electric water heaters, homes with certain other electric appliances. The evidence showed that the uses of electricity promoted tended to improve the utilization of the installed plant of the utilities and thereby improve the annual load factor of those utilities. Moreover, it was shown that the additional revenues generated by the uses of electricity promoted was sufficient to enable the utilities to recover those costs within a reasonable period of time - generally speaking, less than a year on the basis of gross revenues and less than two years if gross revenues are reduced by application of the system operating ratio. We believe this effectively prevents any discrimination against other customers and actually operates to the benefit of all the customers. The weight of decided authority from other States is to the same effect. See, for example, Gifford v. Central Maine Power Co., 217 A. 2d 200 (1966); Rossi v. Garton, 60 PUR 3d 210 (1965); Re Delaware Power & Light Co., 56 PUR 3d 1(1964); Re Savannah Electric and Power Company, 45 PUR 3d 88 (1962).

It would be against the public interest to hamper the growth of a utility's business for the purpose of enabling an unregulated industry to make more money. The fuel oil dealers object to letting the utilities offer inducements to increase the consumption of their products. But if the utilities could not attract new business their customers would have to pay higher rates, so that the economic consequences of the fuel oil dealers' proposal would be the same as if they were demanding that utility rates be increased to the point where nobody could afford to heat his house with gas or electricity. That would not be in the public interest.

In recent years the gas companies have been taking business from the oil companies, and, still more recently, the electric companies have been getting a small percentage of the heating business. The gas companies find themselves in much the same predicament that the railroads found themselves in when their former customers began to prefer to travel by bus or plane. The principle involved is that the public interest requires that the public be allowed to choose between competing public service companies the service that it prefers.

Motor buses have put the trolley lines out of business. In Petersburg, Hopewell and City Point Railway Company v. Commonwealth, 152 Va. 193, a trolley-car line was rendering perfectly adequate service between Petersburg and Hopewell, but the Commission nevertheless issued a certificate to a motor bus carrier to parallel the car line. The court said (p. 202):

"The State is under no obligation to protect the car line, or to see that its operations are financially successful."

And at page 205:

"When people generally wish to travel in this way, they should be permitted to do so, and it is no sufficient answer to say that other carriers, in other ways, stand ready to give the necessary service."

It is the duty of the managers of a utility to do all they can to reduce costs. Every year the electric companies, for example, are buying bigger and more economical generators, they are building plants in the coal fields (which hurts the railroads), they are developing nuclear power plants (which hurts the coal industry), they are installing transmission lines of higher voltages, and they seek to persuade governments to lower their taxes. When their costs are reduced the savings inure to the benefit of the consumers in lower rates. The promotional allowances of gas and electric companies are likewise designed to reduce unit costs by increasing consumption.

Although the general concept of promotional allowances for certain uses of gas or electricity is not unlawful, several applications of it revealed by the record are. Virginia Electric and Power Company (Vepco) gives an allowance of $20 for an electric range when it is installed at the same time as an electric water heater (the water heater installation brings $40) but an electric range otherwise installed entitles the owner to no allowance. There is no rational basis for this distinction, and therefore it is discriminatory. Vepco's gas department gives allowances for conversion to gas from all fuels other than electricity. It is understandable that Vepco does not wish to pay to induce an electric customer to become a gas customer, but if it is to offer allowances for conversions to gas it must do so uniformly and not discriminate against customers who convert from electricity.

In contrast, Washington Gas Light Company pays up to four times as much for conversions from electricity as it does for conversions from coal or oil. This discriminates against the consumers who receive the smaller allowances.

Of course, any promotional allowance that is not uniformly applied among the customers meeting its requirements is unjustly discriminatory. Both Appalachian Power Company and Natural Gas Service Company have adjusted bills or furnished free service in certain instances where heat was required to dry out a newly constructed house. The record showed other instances where incentives had been negotiated on a case-by-case basis. This is clearly unlawful. All of these specific discriminatory allowances are hereby disapproved.

The second major area of contention in this proceeding has been the development by the electric companies of underground distribution plans. These plans vary in detail considerably, but the basic concept is that a customer or builder desiring underground service must pay the average difference between underground and overhead construction cost to obtain it unless the residence or development is Gold Medallion or All-Electric, in which event all or part of the difference in actual cost will be absorbed by the electric company.

The public is becoming more and more interested in underground distribution of electricity, and it is in the public interest to encourage such underground distribution. However, so long as the cost of underground is substantially more than the cost of overhead, the customer who receives the underground service must, in one way or another pay for it, regardless of whether underground distribution is voluntarily chosen or required by local ordinance. Otherwise, there would be an unjust burden on customers who are served by the less expensive but less desirable overhead method. There are a number of methods by which the customer can be required to pay for underground service. It can be done through cash payment of the actual difference in cost between underground and overhead, payment of the average difference in cost between underground and overhead, the establishment of a separate rate for underground electric service, the addition of an underground surcharge to existing rates or a credit based on anticipated revenues. So long as the method of repayment selected by the utility company is reasonable and not unjustly discriminatory, the method should be determined by the company and not by the Commission.

The underground distribution plans considered in this proceeding are, in general, combinations of the "average difference in cost plan" and the "credit for anticipated revenue plan." However, the credit is not given on a pure revenue basis, but rather is tied generally to the total electric concept, and this is what the gas companies find objectionable. In the future, beginning with the year 1967, we will require such plans to be based primarily on a pure revenue basis.

This proceeding has revealed that whereas most of the promotional allowances and practices of the electric and gas utilities are lawful and nondiscriminatory, not all of them are, and it appears that without adequate supervision in the heat of competition there is substantial opportunity for discriminatory concessions to be made. For these reasons we consider it to be in the public interest for the Commission to be fully and constantly aware of the promotional allowances and practices which the utilities have in effect in order that it may insure that none of them are unlawfully discriminatory and that none of them are administered in an unlawfully discriminatory way. To this end, henceforth each utility shall file a description of its promotional allowances and practices with the Commission.

1. Each utility shall, before January 1, 1967, file with the Commission new schedules giving in detail the terms and conditions governing charges for underground wiring or governing construction on the customer's side of the meter, and giving in detail all allowances of any kind. The schedules shall define each class of customer and each charge and each allowance so specifically as to leave no room for bargaining between the utility and the customer. The new schedules shall be effective on and after February 1, 1967, and shall supersede the schedules heretofore filed. Thereafter, no change in any such schedule shall become effective until thirty days after it has been accepted for filing by the Commission.

2. A utility may not, directly, or indirectly through a third person, promise that a customer will be satisfied with the cost of service. If it gives estimates of costs it must make it perfectly clear that an estimate is an estimate and not a guaranty or warranty.

3. A utility that sells appliances can guarantee that they will work properly and that it will take them back if they do not. It cannot guarantee that the customer will be "satisfied" in the sense that the customer can get his money back merely by saying that he is dissatisfied. Such a promise would enable the customer to get his money back if the costs exceeded the estimate and would give the estimate the force of a promise. For the same reason a utility may not agree to reimburse in whole or in part an independent contractor who gives a guaranty that the utility could not give.

4. Allowances against charges for underground wiring must be based on estimated consumption and not on specified kinds of appliances used by the consumer.

5. An allowance given to any person for installing or procuring the installation of an appliance must be the same whether or not the appliance is substituted for an appliance already in use. If the appliance is substituted for an appliance already in use, the allowance must be the same regardless of the fuel used in the appliance already in use.

6. An allowance given for the installation of two or more appliances must be the sum of the allowances given for the installation of each of the appliances separately.

1There is no objection to a reasonable guarantee of satisfaction so long as it excludes satisfaction with respect to cost of the electric or gas service.

20VAC5-300-30. Final order; implementing federal rules concerning cogeneration and small power production facilities. (Repealed.)

Pursuant to § 210 of the Public Utility Regulatory Policies Act of 1978 ("PURPA") (Public Law 95-617, Title II, § 210, 92 Stat. 3144, 16 USCS § 824a-3) the Commission entered an order on November 26, 1980, establishing the present case for the purpose of determining appropriate rates and provisions under said section for the above listed Virginia electric cooperatives ("Cooperatives"). By that same order, Cooperatives were directed to file proposed rates and information relating to the development of rates pursuant to PURPA § 210. The Commission also scheduled a public hearing for January 20, 1981.

By order dated January 13, 1981, the Commission allowed the Division of Consumer Counsel (Office of the Attorney General) additional time to file its information and made similar changes for filing protests and protestant testimony.

A public hearing was held before Charles W. Hundley, Hearing Examiner, on January 20, 1981, in the Jefferson Building, Richmond, Virginia. Counsel appearing were James V. Lane, for Cooperatives; Walter A. Marston, Jr., for the Virginia Hydro Power Association ("Hydro"); Eric M. Page, for the Division of Consumer Counsel, Office of Attorney General; and Glenn P. Richardson and A. Lynn Ivey, III, for the Commission. Protestant Jerry S. Rosenthal appeared pro se.

One intervenor appeared at the hearing.

On March 6, 1981, the Hearing Examiner filed his report. Subsequent to that date, the Attorney General, Jerry Rosenthal, and Hydro filed exceptions to the report.

NOW, THE COMMISSION, having considered the record and the applicable law FINDS:

1. That Cooperatives avoided costs based upon Cooperatives cost of wholesale power is reasonable;

2. That each Qualifying Facility ("QF") with a capacity exceeding 100 KW shall negotiate the terms of its sale of electricity with Cooperative and that the Commission will stand ready to arbitrate in the event that an agreement cannot be reached;

3. That interconnection costs, as defined by FERC Rule, 18 CFR § 292.101(7), should be prepaid at the time of installation or over a period of up to three years, at the option of the QF, or over such longer period of time as may be mutually agreeable to the parties;

4. That, in cases in which QF's pay interconnection costs over a period of time, Cooperatives should be allowed to collect interest, the rate of such interest not to exceed the cost of Cooperatives most recent issue of long term debt;

5. That the record is inadequate to establish a metering charge, however, the costs associated with the installation of additional metering may be included as an interconnection cost;

6. That the QF should have the option of either a simultaneous purchase-sale transaction or the sale only of its excess power; selection of such option shall be expressed in its contract and shall be for a period of not less than one year;

7. That Cooperatives shall revise their rates for the purpose of power from QF's in accordance with any permanent change in wholesale power costs;

8. That Cooperatives shall comply with the Staff proposal for the annual filing of cogeneration information with this Commission; accordingly,


1. That on or before September 1, 1981, each Cooperative shall file revised schedules in accordance with the findings herein;

2. That each Cooperative shall file the following data with the Commission on or before March 1 of each year, beginning March 1, 1982 (such data shall cover the twelve months ending the previous December 31):

- The name and location of each QF interconnected with Cooperative

- The design capacity of each QF

- The amount of energy purchased from each QF

- The amount of energy sold to each QF

- Copies of any contracts entered into between Cooperative and QF's

- Avoided cost data of the type required by 18 CFR § 292.302

3. That, there appearing nothing further to be done in this matter, the case be dismissed from the docket and the papers placed in the file for ended causes.

20VAC5-300-50. Natural gas industrial rates and transportation policies. (Repealed.)

On April 4, 1986, the Commission issued an order establishing a rulemaking proceeding to reassess natural gas industrial rates and transportation policies in Virginia. This hearing resulted from the changes in the natural gas industry most immediately caused by the issuance of Order 436 by the Federal Energy Regulatory Commission (FERC). This Order is altering the traditional roles of the various components of the industry - producer, pipeline, local distribution company and end user. While the impetus and control of much of the change remains at the federal level, the successful operation of the FERC induced programs will be determined by the approach taken by state commissions in the implementation on the state level.

The changes have been fueled by a number of factors: decontrol of wellhead gas prices, the decline in oil prices, the competition given our domestic gas industry by Mexican and Canadian gas, the advent of the spot market and contract carriage provisions. Since 1980 the industry has seen an excess supply of gas. This has resulted in increased risk to producers and pipelines under the traditional marketing functions and increased pressure by industrial users to have available a mechanism to obtain natural gas at lower prices. Devices such as Special Marketing Programs, shifts in the allocation of fixed costs in demand and commodity charge components of the minimum bill, and elimination of variable costs from the minimum bill were precursors of the present FERC attempts to enable the natural gas industry to respond to the very real competitive forces in the marketplace.

The federal government through FERC has determined that users of natural gas in this country will benefit if they are given the option to purchase gas directly from the producers and have it transported by the pipelines to their point of use. This policy dramatically alters the traditional role of the interstate pipeline, the intrastate pipeline and the local distribution company. This policy decision, embodied in FERC Order 436 and now expanded in Order 451, poses substantial practical and philosophical problems. The restructuring of this industry cannot happen quickly and the fruits or disadvantages of this move will take even more time to realize and evaluate.

While this shift began on the federal level and initially involved those entities subject to the jurisdiction of FERC, local distribution companies and intrastate pipelines as an integral part on the industry, must also adjust to the new way of doing business. Failure to do so clearly would frustrate national policy. As in the telecommunications industry, it is now incumbent on the local utilities and state regulators to make federal policies work for the public good.

In our April order, we invited interested parties to participate in this rulemaking proceeding, directed Staff to complete its investigation and file its analysis and report, and further, identified several critical issues which the Commission hoped parties to the proceeding would address and which the Commission believed needed to be addressed to facilitate the transition of the natural gas industry in Virginia to a more competitive environment.

As noted in the order establishing the rulemaking proceeding, the Commission has received numerous formal as well as informal requests for guidance and analysis of specific problems related to industrial rate design and transportation policies. Some of the problems which have been raised in those inquiries and proceedings can and should be most effectively decided on a general basis to facilitate a more orderly development of the regulatory scheme. However, although we intend to address many of the problems, this proceeding and this order are intended to provide only a framework for the development of the natural gas industry in Virginia. Actual rates and company specific considerations should and will be taken into account on a company by company basis within the framework established herein.

Beginning on June 17, 1986, the Commission conducted public hearings to receive testimony and comments from interested parties on the development of an appropriate rate design for industrial rates and transportation policies in general. A number of diverse parties provided input on the issues raised by the Commission and by the Staff report. The Commission would like to thank all parties for their contributions in this proceeding and their efforts to suggest a reasoned and equitable approach to this new and still changing environment.

Appearances were entered by Edward L. Flippen for Anheuser-Busch Companies, Inc. (Anheuser-Busch), BASF Corporation (BASF), James River Corporation (James River), Owens-Illinois, Inc. (Owens-Illinois), Reynolds Metals Company (Reynolds), and Westvaco Corporation (Westvaco); Fielding L. Williams, Jr. for Celanese Smoking Products, a Division of Celanese Corporation (Celanese); Charles F. Midkiff and Louis N. Monacell for Allied Corporation (Allied); Anthony Gambardella for the Division of Consumer Counsel, Office of the Attorney General (Consumer Counsel); Eric M. Page and David B. Kearney for the City of Richmond (Richmond); Guy T. Tripp, III and James F. Bowe, Jr. for Virginia Natural Gas (VNG); Donald R. Hayes for Northern Virginia Natural Gas, a Division of Washington Gas Light Company (NVNG); Wilbur L. Hazlegrove for Roanoke Gas Company (Roanoke); Stephen H. Watts, II for Commonwealth Gas Services, Inc. (Services), Lynchburg Gas Company (Lynchburg), Columbia Gas of Virginia, Inc. (Columbia) and Commonwealth Gas Pipeline Corporation (Pipeline); Allan E. Roth for Columbia; John S. Graham, III for Equitable Resources Energy Company; and Deborah V. Ellenberg for Staff.


Representatives from Anheuser-Busch, BASF, James River, Owens-Illinois, Reynolds and Westvaco came forward to testify on their own behalf. In addition, those industrial companies jointly supported the testimony of Dr. Roy Shanker, an economic consultant. That group of industrial end-users urged the Commission to recognize that competition and increased transportation are in the public interest. They further urged the Commission to unbundle transportation related services, develop cost of service rates for those services and allow such rates to be downwardly flexible to the variable cost of service. They also stated that the Commission should require Pipeline to make its upstream Columbia Gulf transportation capacity entitlement available to its contract demand customers upon their request. The industrial companies further recommended that, to implement the policies developed in this proceeding, utilities be directed to develop and file cost of service studies and to file embedded cost of service transportation rates pursuant to those studies within twelve months of the date of this order. Dr. Shanker testified that embedded cost rates will eliminate most of the economic incentives for bypass. Mr. Flippen, counsel for the six industrials, stated further that the Commission need not address the question of bypass unless and until an actual case arises. Finally, those parties supported the concept of flexible interruptible retail rates and recommended the ceiling be based on the embedded cost of service and the floor on the utility's marginal cost of service.

Celanese presented one witness who urged the Commission to adopt flexible transportation rates within cost of service parameters. Celanese's witness also stated that standby service for transportation customers should be provided at carefully considered and unbundled rates.

Allied presented one witness, John Brickhill, who urged the Commission to encourage voluntary transportation by taking a company's participation into account in establishing an appropriate return on equity or by not allowing utilities to pass on to remaining customers the fixed costs associated with lost load which could have been averted through transportation. He also testified that the Commission should address the problems associated with the allocation of upstream transportation capacity and urged the Commission to look at the long term impact on end-users, not simply at Pipeline's current cost of gas. He asserted that customers must rely on the long term ability to transport gas, not simply transportation of spot market purchases. Allied argued that transportation rates should be based on an embedded cost of service design and should be downwardly flexible if retail sales rates are downwardly flexible. It said that flexible pricing must be closely scrutinized to prevent anti-competitive abuses. Mr. Brickhill stated that rate design should,promote competition and fairness by application of cost causation principles in a manner which would avoid undue rate shock. He observed that now would be a good time to move to parity as gas costs overall are declining. The impact therefore would be minimized.

The Consumer Counsel presented the testimony of Mr. Steven Ruback. He stated that local distribution companies (LDCs) should lower their system average cost of gas and that the Commission should concentrate on reviewing the utility companies' purchasing practices. With regard to rate design, the Consumer Counsel recommended rates be based on the same non-gas margin contribution as if the customer had purchased gas from the LDC under a non-flexible rate schedule. This, he argued, would make both customers and utility companies indifferent as to whether a customer transports or purchases gas from the utility. Mr. Ruback stated that such a margin approach would avoid price signals which encouraged a customer to switch to transportation and thereby make a lower contribution to a utility's fixed costs. He further urged that interruptible flexible retail rates be addressed on a company specific basis and that the floor should be based on the highest commodity cost of gas. Further, the Consumer Counsel cautioned the Commission against making spot market purchase dedications to particular customers and stated that such inappropriate dedications would result in unjust and preferential rates.

Richmond presented the testimony of one witness, Michael Moore. Mr. Moore agreed with most other parties that increased competition and transportation are in the public interest. Mr. Moore also urged the Commission to address the allocation of upstream capacity and stated that customers must have the assurance that upstream capacity will be available or there will be a resulting disincentive to transportation. Moreover, he stated that such allocation should be available to Pipeline's customers since they pay the contract demand costs to reserve the capacity.

Virginia Natural Gas, through its witness, Ann Rasnic, also urged the Commission to find as a matter of policy that transportation is in the public interest. It also urged the Commission to consider allocation of upstream capacity and argued that the customers of Pipeline need the assurance that transportation will be available through that upstream capacity to facilitate economic and reliable service to the end-user. VNG supported staff's recommendation that transportation rates be designed on an embedded cost of service basis, with some contribution to contract demand costs included in interruptible rates. Ms. Rasnic urged the Commission to retain interruptible flexible retail rates within specific parameters. She recommended the floor be based on a utility's weighted average commodity cost of gas (WACCOG) unless the utility can show that something less than that WACCOG is necessary to compete with alternate fuels and still provides a net benefit to the firm customer. VNG also recommended that the ceiling of the authorized range should be the firm industrial sales rate. Finally, VNG suggested the Commission support the general concept of an incentive proposal which would encourage a utility company to maximize throughput from interruptible sales and transportation volumes. Under the mechanism, any shortcomings or additional revenue generated over a target level would be shared between stockholders and ratepayers according to the risk borne by each. VNG stated that the proposal is in the public interest because it reduces the need for base rate changes by eliminating severe shifts in utility earnings and further, it provides an incentive to increase throughput resulting from interruptible sales and transportation volumes which, of course, is in the public interest of all parties.

Northern Virginia Natural Gas (NVNG) also participated in the rulemaking proceeding and presented two witnesses, Jack Keane and Frank Hollewa. NVNG stated that, as a general matter, the transition from a regulated environment to a market driven environment will impact each local LDC differently according to each company's size and load profile; accordingly, it recommended that this rule-making should only present broad guidelines to provide flexibility for company operations. Moreover, NVNG supported a gradual phasing out of the industrial subsidy of firm rates. In addition, transportation, the company asserted, should be voluntary or with some provision for waiver or exemption and should only be offered on a interruptible basis until more experience is gained with the service. It also recommended the establishment of minimum criteria, by each LDC, relating to size, delivery point, and contract term. Transportation rates, NVNG stated, should be flexible and market driven. NVNG said interruptible flexible retail rates should be established within a floor based on an LDC's WACCOG and each LDC should be allowed to dedicate a specific package of spot market gas to an industrial customer.

Roanoke did not introduce the testimony of any witnesses; however, its attorney, Wilbur Hazlegrove stated the company's position. As a general policy matter, he stated that the LDC was charged with protecting the firm residential customers and that there was no obligation to serve industrial customers. He was doubtful that the Commission would be able to handle a transition to a market driven environment smoothly and cautioned the Commission to proceed slowly, concentrating on more pressing problems, such as the take-or-pay costs issue before FERC. He stated that there was no need to mandate transportation, as the industry was already responding to the competitive market. He called transportation effectively a bypass of the utility system supply and stated that the traditional distributor monopoly of gas supply would soon be replaced by "a proliferation of purchasers chasing an inadequate gas supply with big bucks." Industrial rates and transportation policies, he urged, should be developed on a company specific basis.

Pipeline, Columbia, Services and Lynchburg presented their comments through their counsel, Stephen H. Watts, II. By its statement of position on future allocation of upstream pipeline capacity dated June 24, 1986, Pipeline stated that it has voluntarily allocated its upstream transportation capacity among its five contract demand customers pursuant to mutual agreement. It recognized the customer's need to be able to rely on such an allocation to make longer term gas purchase commitments and stated that it would not revoke the upstream allocation provided to its customers without thirty days notice. Pipeline stated that the issue relative to the allocation of upstream capacity must be decided in terms of a utility company's public service obligation to use its available resources to offer reliable supply at lower cost for all of the customers. However, it requested Commission guidance on the allocation question.

Pipeline was also concerned that any policy decisions rendered in this proceeding should not displace the stipulation filed by several parties in Pipeline's recently concluded rate case.1 In that case Pipeline had proposed cost based transportation rates within and outside of contract demand (CD), provided a methodology for sharing capacity between CD customers and provided equal priority for transportation and sales gas volumes within firm and interruptible classifications. Pipeline expressed concern with the impact of transportation in the long run since the current market instability is due to temporary and extraordinary conditions. Pipeline also urged the Commission to address the bypass question.

On behalf of Columbia, Mr. Watts stated transportation rates ideally should be based on the non-gas sales rate schedule margin, since there is not a significant difference between the non-gas cost of providing transportation service and the cost of delivering gas for sale to its customers. However, under conditions where the price is being set by the market, he stated fixed transportation rates will result in a loss of throughput and accordingly, Columbia recommended flexible transportation rates.

Services agreed that industrial transportation rates should be fully allocated and distributed according to class cost of service studies with class rates of return moving towards parity. Services also urged that industrial rates be downwardly flexible with a floor based on a utility's variable cost of gas sold to the industrial customer. Transportation rates, it urged, should be the non-gas component of the applicable sales rates and should be downwardly flexible to allow competition and prevent bypass.

Lynchburg urged the Commission to consider and maintain flexibility in any policy or framework adopted in this proceeding to allow LDC's to compete with nonregulated markets. Lynchburg also stated that there was not a need for the Commission to mandate transportation. Lynchburg itself offers firm and interruptible transportation but has not had a request for either type of service.

Mr. Cody Walker appeared on behalf of the staff. He indicated that a mandatory carriage policy was not necessary but incentives should be developed to encourage voluntary participation.

Staff recommended value of service rates be retained for retail interruptible sales. Mr. Walker stated that the parameters between which flexible rates could vary on a month to month basis should be based on cost of service considerations. The fluctuation of the rate within the established range could vary as necessary to compete with competitive alternative fuel prices. staff recommended that the floor of the flexible rate range be equal to a utility company's highest commodity cost of gas plus adjustments for taxes and unaccounted for gas, unless the utility shows that a lower floor is necessary to compete with alternate fuels and further, that a lower floor still provides a net benefit to the firm customers. Mr. Walker supported a ceiling based on the same rate of return as provided by the firm industrial rates.

Staff recommended that transportation rates be designed on an embedded cost of service basis. Incorporated into that recommendation, staff included a contribution to compensate firm customers for the interruptible customer's use of excess capacity because it is reasonable to allocate some of the demand costs to interruptible customers as rent or compensation for use of the facilities. Staff did not support flexible transportation rates.


The increase in competition in the natural gas industry has clearly been in the public interest. Competition at the wellhead has already served to lower gas costs overall and nondiscriminatory transportation has stimulated that competition. Even nonparticipating customers benefit from transportation due to the increased pressures on utility companies to lower gas costs overall to more effectively compete. Moreover, a company which effectively competes can increase the throughput on its system and again lower costs for all its customers. In addition, transportation provides one more market option which a utility can offer its customers and consequently maximizes the requisite flexibility necessary to compete with a variety of alternatives. We agree with the majority of the parties to this proceeding that transportation of natural gas is in the public interest. However, it is not necessary to mandate that all utility companies file transportation tariffs and provide that carriage. As many parties observed, as a practical matter, most Virginia utility companies who have a demand for transportation on their systems have effective transportation tariffs on file with this Commission. Although we will not mandate transportation, we intend to encourage voluntary participation in transportation programs. This Commission will review individual company practices in future rate cases to assure that each company maximizes utilization of its system. Several means to encourage transportation were suggested by several parties in this proceeding. We will be critical in the event load is lost as a result of a company's failure to transport. Such loss will be taken into account in setting rates. Appropriate measures will necessarily be taken into account in each company's rate case to preclude penalizing a company who has no demand for transportation for its failure to provide transportation.


This Commission has historically embraced the flexible rate as a viable mechanism to provide utility companies with the flexibility necessary to compete with unregulated alternate fuels. In January of 1984, the Commission first approved a flexible rate for Washington Gas Light Company.2 In the final order issued in that case we stated that:

We are confident that a flexible rate is required in order for the Company to remain in the competitive market of interruptible customers. If the Company were to lose its entire interruptible load, there would be an automatic shifting of significant non-gas costs to all firm customers. Hence, the economic viability of the Company hinges upon its ability to generate revenues from interruptible customers, and to do so it must have a flexible pricing structure to compete in that market.

That principle has been restated in numerous proceedings addressing flexible rates. As the gas industry moves toward a more competitive market it is even more essential that utility companies retain the flexibility available through measures such as flexible rates to be able to respond to the marketplace.

Although most parties to this proceeding generally supported the basic concept of a flexible rate, the suggested parameters of that mechanism varied. VNG suggested that it was more appropriate to establish the floor based on a company's weighted average commodity cost of gas (WACCOG) plus appropriate adjustments. Further,

VNG suggested that the ceiling be equal to the large volume firm sales rate, rather than simply incorporating the return included in the firm rate as suggested by staff. In addition, several parties recommended establishing a floor based on the utility company's spot market purchases or, in other words, to allow utilities to dedicate their cheapest purchases to the most elastic customers.

Several parties also cautioned that each utility company's situation will be different and will depend in part upon load profiles and purchasing practices. Accordingly, those parties recommended that flexible rates should be reviewed on a company specific basis.

Although we agree that specific provisions may vary based on an individual company's market and operating characteristics, basic guidelines can be established to provide a uniform approach to companies' flexible rates. We conclude that the floor of a flexible rate should be based on the highest commodity cost of gas or if more than one supplier furnishes gas, the floor should be the weighted average commodity cost of gas. If, and we emphasize "if," the utility can demonstrate that a lower cost is necessary to compete with alternate fuels and further, that the firm or core customer still receives a net benefit from retaining the interruptible sale, the lower price will be accepted.

As pointed out by several parties, the point at which the price necessary to retain an interruptible sale no longer provides a benefit to the system will vary significantly from company to company. Accordingly, it is reasonable to establish the starting point for the floor at the highest commodity cost and allow companies to offer proof that something less is necessary and still beneficial on a case by case basis. That test will of course reflect an analysis of several factors, foremost of which will be the incremental cost of gas acquired to serve the interruptible load. To facilitate a direct comparison it may be appropriate to assume the benefits of retaining the interruptible load will coincide with the immediate impact on gas costs.

We will necessarily be cautious about allowing companies to dedicate spot market purchases to the most elastic customers. The Commission must be particularly sensitive to the protection of the inelastic core customers. A rate design which results in inelastic customers subsidizing the elastic customer is clearly improper. Economic purchases should not be made solely for elastic customers to the exclusion of purchases for system supply. The authority to make such a dedication to the most elastic customers would also eliminate one incentive for a company to minimize its general system costs. With a low price necessary to compete with alternate fuels in the current market, a captive customer, or one with no ready alternative, might be assessed the higher cost of gas without close regulatory scrutiny. We caution all utility companies to review their general system purchasing practices and to fulfill the statutory obligation to provide reliable utility service at a just and reasonable cost.

The customer charge component of the rate should reflect the fully distributed costs of providing the interruptible service. We will closely review this in rate filings.

Finally, at this point in the evolving competition in the gas industry, we concur with the recommendations of most parties that it is prudent to move gradually toward parity of return in firm industrial rates. Such movement must be gradual to minimize rate shock to residential customers and carefully evaluated at each step.


A number of parties recommended the embedded cost of service rate proposed by staff to be established as a maximum transportation rate and that the utility companies be afforded the flexibility to adjust the transportation rate downward from that embedded cost of service level to the marginal cost of providing transportation service. There are problems, however, associated with flexible transportation rates. The value of transportation to individual customers will vary on the basis of a number of different factors. Unlike the flexible retail rates, there is not a readily identifiable alternate source of competition to transportation. Transportation may occur due to any one of a number of factors ranging from wellhead cost of gas to alternate fuel prices. To respond to these variables, the utility would need to apply a different rate for each customer and would consequently engage in discriminatory ratemaking between similarly situated transportation customers. Such a framework would also result in problems with effective regulatory review problems.

The Consumer Counsel recommended a different approach to the design of transportation rates. Its witness, Mr. Ruback, recommended basing transportation rates on the non-gas margin of the applicable retail sales rate which would otherwise be available to that customer. He stated the benefit of this rate design approach would be the utility's revenue neutrality relative to a customer's election to transport its own gas or purchase from the utility. At the public hearing, the Consumer Counsel further clarified that its margin approach should be limited to nonflexible rate schedule margins.

Other parties observed that such a margin approach could be a goal if industrial retail rates were already based on cost-causation principles, however, based on current rate designs, the nonflexible margin approach results in unworkable and uncompetitive rates. Such an approach would effectively eliminate transportation as a service option in Virginia, thereby compounding the current problems with competitive fuel prices. In addition, the Consumer Counsel's limitation on the margin approach to nonflexible rates would not result in the company's operations being revenue neutral. An alternate fuel user who could purchase gas under an interruptible flexible rate schedule would not be purchasing gas under the firm large volume rate schedule as its alternative to transportation service and accordingly, its choice between a flexible sales or transportation service would not result in a revenue neutral situation. If the limitation to nonflexible rate schedules were removed and transportation rates were based on the appropriate margin, a wide range of rate levels would be charged to transportation customers despite the fact that the customers were all receiving the same type of service.

We will direct that an embedded cost of service approach to transportation rate design be applied on a company by company basis for both firm and interruptible transportation service. Over time, the non-gas margin of the industrial sales rates will be more closely aligned with the transportation rates, however at the present time we must provide viable competitive options for utilities to offer their customers. Moreover, since the growth in transportation service is a recent phenomenon, development of embedded cost of service transportation rates at the present time will not result in rate shock to the captive customers. An immediate elimination of the subsidy currently being provided by industrial customers in the retail rates would, however, result in rate shock. We would note, however, that, with the recent drop in oil prices, the impetus to shift much of the fixed costs of the utility to firm customers is already in place.

An interruptible customer does not contribute to the fixed cost of capacity associated with peak demand and such service is inferior to firm service, since it is interrupted during periods of peak load; however, the interruptible service is provided through the same facilities as firm service. Therefore there should be some compensation by the interruptible customer to the firm customer for the use of that excess capacity. The contribution will vary from company to company, again depending on the customer mix and load profile, and therefore should be specifically addressed on a company by company basis. The demand allocation applied in each case should reflect the operating characteristics of the company.

To facilitate and expedite implementation of the framework established herein, all gas utility companies should conduct class cost of service studies and file them with the Commission within the next 12 months. Exemptions from this filing requirement, upon proper petition, may be considered for small gas utilities with limited industrial loads and who have not received requests for transportation service. Any tariffs filed should be based on cost of service studies. Those companies who do not intend to file rate cases in the next 12 months, should file limited applications to revise their transportation rates where transportation is being offered in accordance with the findings herein within that same 12 month time period.


There was overwhelming support for an approach to rate design which identifies the several services which a utility provides and separately determines the fully allocated costs of providing each service. Unbundling services in this way provides a menu from which a customer can tailor the type of service and degree of reliability appropriate for that customer. The extent to which unbundling occurs will again vary from company to company and accordingly should be evaluated on that basis, however, it provides a reasonable approach to rate design at a time when the industry is becoming more competitive in the services offered. Transportation and standby retail service are two examples of services which can be easily unbundled from the traditional retail sale and provided on an individual basis.


One of the foremost concerns raised in this proceeding relates to the proper allocation of upstream transportation capacity. At the present time few interstate pipeline companies have agreed to become open access transporters. Columbia Gas Transmission Corporation, a primary interstate supplier for Virginia, and Columbia Gulf are, however, open access transporters. Because they represent a major supplier for the east coast, tremendous demand has been placed on them for transportation. This has resulted in demand exceeding capacity available and raised serious questions concerning the allocation of transportation capacity on their pipeline facilities.

The FERC recently addressed the problems with allocation of Columbia Gulf's main line capacity. The FERC defined the "first-come/first-served" methodology which was first described in FERC Order No. 436. The FERC has generally outlined the allocation of transportation capacity to Columbia Gulf's wholesale customers, both for its customers' system supply and for the wholesale customers' end-users through March 31, 1987. The FERC directed that in making monthly nominations, the wholesale customers should include any requests for service by their customers. While addressing the Gulf capacity allocation generally, the FERC by Order Approving a Settlement Offer with modifications in FERC Docket No. RP86-14-004 dated March 28, 1986, stated at page 19 that "the relationships between Columbia Gas' wholesale customers and the end-users they serve is properly a matter of local concern, to be determined by each customer with its end-users and is subject to state regulatory agency oversight and/or regulation."3 Commonwealth Gas Pipeline as a direct customer of Columbia has received an allocation of Gulf capacity pursuant to this settlement. Initially, Pipeline used its allocated capacity to purchase spot gas for its system supply, thereby lowering the per unit cost of gas to all customers equally. Pipeline was informed that this arrangement did not comply with the terms of the PGA settlement with FERC. As result Pipeline released its capacity to its direct customers who in turn agreed to an allocation formula. Pipeline has five direct customers - Virginia Natural Gas, Suffolk Gas, the City of Richmond, Allied and Commonwealth Gas Services. Presently, Pipeline is operating on a shared allocation basis; however, the stated policy of the company continues the ability to revoke the shared allocation on thirty days notice.

Pipeline and its customers have asked for Commission guidance on the proper allocation of Pipeline's entitlement to upstream transportation capacity. Although the problem will be somewhat relieved in the event that other interstate pipelines serving Virginia become open access transporters, the problem clearly must be addressed now at least for the short term period.

Many parties urged the Commission to provide some assurance on the availability of upstream capacity. They are interested in acquiring supply for the longer term, not solely from short term spot market purchases. To do this they need more than thirty days assurance of transportation. Moreover, they argue that Pipeline's customers pay the contract demand associated with reserving capacity upstream and, accordingly, should be able to elect to use that capacity or to ask Pipeline to use the capacity to minimize its commodity cost of gas. In making that decision, those customers of course would weigh their own ability to purchase gas at economic prices relative to the price of their supplier.

The Commission recognizes that if gas transportation is to work effectively and efficiently, those who wish to transport gas must have some assurance that the capacity to transport will be available. Without that assurance, these users are forced to purchase system supply or leave the system for alternate fuels. All of Pipeline's LDC customers have indicated that obligation can be best fulfilled by passing the upstream allocation on to them. Accordingly, the choice should be Pipeline's customers. We will monitor this situation as other interstate pipelines become open access transporters and understand that the time may come when such allocation may be unnecessary, impracticable or impossible. Although not bound by the FERC settlement, we encourage local distribution companies to utilize policies which afford a degree of reliability for transportation capacity usable by their transportation customers.


The issue of bypass was also identified in this proceeding. We define bypass to mean direct connection by an end user to an interstate or intrastate pipeline, thereby bypassing the certificated local distribution company. This issue involves the economic incentives for bypass as well as its legality under present law. The Commission believes that appropriately designed embedded cost of service rates should eliminate the economic incentives for bypass. This will of course require the good faith efforts of both the customer and the utility. In any event, the Commission does not believe the record before us is adequate to resolve the legal issue at this time.


The industrial companies represented in this proceeding generally agreed that they should bear the risk of their election to transport gas for themselves rather than rely upon their traditional local distribution company. Clearly, if a customer elects transportation and should not also elect a standby service, the utility company does not have a continuing public service obligation to sell gas to that customer. By placing the responsibility where it belongs, on the customer to elect what type of service it wants to take, the gas company can retain some predictability in its requirements, a predictability which is necessary for it to make its own system plans. Standby service should be offered at compensatory rates.


Any investments made to specifically serve a new transportation customer should be recovered from that customer; accordingly each utility company should provide some type of guarantee through customer charges, minimal purchase requirements, minimal monthly payments, contract terms or some other means to assure recovery of the investment from the specific customer.

We recognize that there are some circumstances in which penalties may be necessary to prevent gross abuses of system availability and to prevent large or disparate operating practices. Penalties should not be designed to be onerous and a disincentive to transportation, but rather should be compensatory for any additional cost which may result from the operating problems. Application of penalties should be addressed by each company on a company specific basis.

Adjustments for unaccounted for gas should be made to account for any difference in deliveries where such differences can be practically identified, for example deliveries through temperature compensated meters vs. non-temperature compensated meters.

We have concern over tariff conditions imposing minimum terms or volumes and other conditions which may be contrary to the market. We will closely review the reasonableness of terms and conditions which may be included in company tariffs.

In conclusion, we want to commend all participants in this proceeding. This is an uncharted course for the industry, consumers and regulators. Proposals other than those adopted herein have been offered. We are confident the changing nature of this industry will give rise to even more approaches to these issues generally and as they relate to a specific company. It is essential that dialogue continue examining the broader policy questions as well as specific rate designs and the performance of the market and industry. We must be aware of all reasonable options to maintain our ability to provide effective and innovative regulation which will allow us to meet the goal of reliable gas service at a reasonable price for the public good.

NOW, THE COMMISSION, having considered the record and the recommendations of the parties is of the opinion and finds:

1. That increased competition and transportation are in the public interest and the voluntary participation in transportation programs should be encouraged;

2. That interruptible flexible rate mechanisms are reasonable and should be retained. The parameters should reflect a floor and ceiling consistent with the discussion above;

3. That interruptible rates should include a customer charge which recovers the fully distributed cost associated with that service;

4. That firm industrial rates should be developed to move gradually towards the fully distributed costs of service;

5 That transportation rates should be based on the fully distributed costs as recommended by staff;

6. That all gas utility companies should conduct cost of service studies to facilitate implementation of the policies established herein and file them within the next 12 months;

7. That the rate design goals and terms and conditions of transportation service discussed herein shall be applied to gas companies in future rate cases;

8. That services should be unbundled to the extent practicable. Standby service at compensatory rates should be made available to all customers. However, those customers not electing such standby service bear the risk associated with the decision to rely on transportation gas; and

9. That the terms and conditions of transportation service should be developed consistent with the discussion herein. Accordingly,


1. The findings and policies discussed and established herein shall be applied in rate cases or limited issue applications filed by gas companies subsequent to the date of this order; and

2. There appearing nothing further to be done in this proceeding, this docket shall be closed and the papers placed in the file for ended causes.

1By Final Order dated July 11, 1986, the Commission did not adopt the Stipulation in its entirety. Case No. PUE850052, Application of Commonwealth Gas Pipeline Corporation, to revise its tariffs - Appeal to the Supreme Court pending.

2Application of Washington Gas Light Company for a change in its gas interruptible rate and other tariff provisions, 1984 SCC Report 395.

3We note that the FERC allocation order is effective only through March of 1987, at which time it will likely be reevaluated.

20VAC5-300-60. Order adopting policy statement for recovery of costs associated with take-or-pay liability. (Repealed.)

On August 7, 1987, the Federal Energy Regulatory Commission ("FERC") entered Order No. 500 in its attempt to mitigate the effects of take-or-pay liability.1 In that Order, FERC announced its adoption, on an interim basis, of two pass-through mechanisms to spread the liability associated with take- or-pay contracts throughout all segments of the gas industry. As we noted in our July 6, 1988 Order for Notice and Comment, as a result of FERC's action, large amounts of take-or-pay liability are being or have been authorized to be passed from interstate gas pipelines to downstream gas utilities, including those in Virginia. Some Virginia gas utilities are currently passing take-or-pay related costs through their purchase gas adjustment ("PGA") clauses to their customers. Because of the potential impact these costs may have on Virginia gas utilities and their ratepayers, we have initiated the instant docket to consider adoption of a policy which will provide for the opportunity to recover these costs in the most equitable and efficient manner possible. We considered the following policies:

(1) Automatic recovery of take-or-pay costs in the same manner that contract demand charges are recovered through utility purchase gas adjustment clauses (hereafter policy option 1);

(2) Allocation of costs associated with fixed surcharges to both firm and interruptible gas commodity costs (hereafter policy option 2);

(3) Recovery of take-or-pay fixed surcharges on the basis of estimated gas transportation volumes and commodity sales. If this approach were adopted, a utility would be permitted an opportunity to recover the costs associated with fixed take-or-pay surcharges during a defined time period. The opportunity to recover these costs would be the same as the opportunity to recover any other costs during the specified period. A formula could be developed to determine the acceptable estimates of throughput, including known and definite load losses, customer growth, normal weather, and the utility's ability to compete. The take-or-pay fixed surcharges would terminate at the end of the specified time period (hereafter, policy option 3).

(4) Allocation of take-or-pay liability on the basis of customer purchase deficiencies. This policy alternative would use a base purchase period against which recent sales purchases could be compared. Costs associated with fixed take-or-pay surcharges could be apportioned in relation to the decreases in sales volumes purchased by gas customers. This policy alternative resembles the Order No. 500 allocation mechanism employed by FERC (hereafter policy option 4).

In our July 6th Order, the Commission invited interested parties, including the staff and jurisdictional gas companies, to file written comments addressing the factual or legal issues related to the four policy alternatives described above. In addition, interested parties were given the opportunity to request oral argument.

In response to that invitation, 22 parties filed comments, and nine requested oral argument. Parties filing comments included: Southwestern Virginia Gas Company ("Southwestern"), United Cities Gas Company ("United"), James River Corporation ("James River"), General Electric Company ("GE"), Commonwealth Gas Pipeline Corporation ("Pipeline"), Columbia Gas of Virginia ("Columbia"), Lynchburg Gas Company ("Lynchburg"), Northern Virginia Natural Gas and Shenandoah Gas Company ("WGL Companies"), the City of Richmond ("City"), Hadson Gas Systems, Inc. ("Hadson"), Westvaco Corporation ("Westvaco"), Anheuser-Busch Companies et als. (Anheuser-Busch), Virginia Industrial Gas Users ("Industrial Users"), Virginia Natural Gas, Inc., ("VNG"), Suffolk Gas Company ("Suffolk"), Allied-Signal, Inc. ("Allied"), Commonwealth Gas Services, Inc. ("Services"), and Roanoke Gas Company ("Roanoke"). The Commission's staff ("staff") also filed comments. The Division of Consumer Counsel did not participate in this proceeding. On July 20, 1988, we issued an order reserving the afternoon of July 29, 1988, for oral argument.


Many of the local gas distribution companies, Pipeline, and industrial customers served by both LDCs and Pipeline supported policy option 1, i.e., recovery of take-or-pay related fixed surcharges through the demand portion of the PGA, in their comments. Commentators supporting option 1 or a variation thereof included Pipeline, Lynchburg, Columbia, WGL, Westvaco, Anheuser-Busch, Cos., Inc., Celanese Fibers, Inc., Owens- Illinois Company, IBM, Allied, and VNG. Advocates of this policy alternative generally argued that since the customers, not the utility, received the benefits of lower wholesale costs of natural gas through the PGA, it was appropriate for these customers to now receive take-or- pay costs through the PGA as offsets to the earlier savings.

Several of the gas utilities supporting option 1 argued that the Commission could not adopt any policy that purposefully disallowed recovery of take-or-pay costs by means of an allocation scheme which would not permit recovery of these costs, nor could it disallow these costs absent a showing that they were imprudently incurred. These companies stated that any disallowance of these costs would, absent a showing of imprudence, violate the filed rate doctrine. Nantahala Power & Light Co. v. Thornburg, 76 U.S. 953 (1986). Appalachian Power Co. v. Public Service Comm'n of West Va., 812 F.2d 898 (4th Cir. 1987). They asserted that these cases held that the Commission could not find that federally-mandated take-or-pay costs were imprudently incurred by Virginia utilities as a group or individually in the context of this proceeding. Indeed one commentator suggested that these cases could be read as preempting the Commission from disallowing Pipeline's recovery of Order No. 500 take-or-pay demand charges. Pipeline's Comments at 25.

Commentators supporting option 1 did so because they found it to be administratively convenient and because it assured complete cost recovery. In addition, many of the industrial end users favoring PGA treatment for take-or-pay dollars depend upon transportation of spot purchases or interruptible sales service to satisfy the bulk of their gas supply needs. End users receiving such services are generally not subject to the PGA of the gas utilities serving them for those services.

Many of these same commentators took the position that the second and third policy options would not allow gas utilities to compete with alternate fuels since addition of associated surcharges would render gas service noncompetitive with the prices of these fuels. Several parties further urged the Commission to reject the cumulative deficiency approach as a form of illegal retroactive ratemaking, and as difficult to administer, given the diverse and changing customer population of LDCs.

Some of the commentators supported options other than PGA recovery or modifications of PGA recovery. For example, United Cities supported recovery of take-or-pay costs on a volumetric throughput basis to be applied to all sales and transportation services. In support of this option, United Cities noted that it would recover costs from the broadest possible base of customers.

Columbia and Lynchburg's joint comments urged that recovery of the fixed surcharges should reflect the distinct nature of the costs. They maintained that reformation costs, which are essentially forward-looking, should be charged through the PGA to both firm and interruptible sales customers. However, because past take-or-pay liabilities represent transitional costs, Lynchburg and Columbia submitted that these costs should be shared between sales and transportation classes on a volumetric basis. During oral argument, these parties stated that if the Commission did not wish to consider any modification of the four policy options under consideration, they would support policy option 3.

The City of Richmond's comments focused upon the appropriate allocation policy for Pipeline. The City urged the Commission to implement option 4 and require Pipeline to allocate costs on the same basis those costs were incurred. Such a sales deficiency approach, in the City's opinion, would be fair, provide appropriate economic signals, and create stability for future take-or-pay cost decisions.

While the Industrial Users' comments recommended that the Commission should permit recovery of take-or-pay costs in the same manner that contract demand charges were recovered through PGA clauses, they also noted that the Commission should find a way for Virginia gas utility shareholders to bear a portion of the costs associated with take-or-pay. The Industrial Users stated that the Commission should recognize the need for flexibility among Virginia utilities to take account of their differing circumstances.

Joint comments filed by VNG and Suffolk joined other Pipeline customers to emphasize the uniqueness of Pipeline's treatment from that of LDCs. They then urged the Commission to employ the purchase deficiency methodology used by the FERC in Order No. 500 to allocate take-or-pay costs among Pipeline's customers but not to use such an approach for LDCs. VNG and Suffolk stated that the cumulative deficiency methodology matched the purchase patterns that resulted in the cost allocation to Pipeline to the customers engaging in such purchasing practices. Finally, VNG and Suffolk urged the Commission to adopt policy option 3 only if:

1. All ceilings were eliminated on interruptible rates to enable LDCs to take full advantage of the market opportunities to recover take-or-pay costs;

2. The Commission also authorized flexible take-or-pay surcharges to enable LDCs to respond to the market;

3. The Commission allowed LDCs with a margin sharing feature to collect take-or-pay costs prior to any sharing of margin with firm customers; and

4. The fixed amortization periods were eliminated to recognize the variable nature of the price differential between gas prices and prices of competing fuels.

Services' comments observed that all four of the policy options under consideration were flawed. Of the four, Services noted that it supported policy option 3 if the amortization period was flexible to allow full recovery of take-or- pay costs. Services supported this approach because it believed that take-or-pay costs were incurred to serve all markets and customers of Services and other LDCs or provide a more market oriented industry, thereby benefitting both sales and transportation customers alike. Therefore, it believed that all of its sales and transportation customers should pay these costs.

Services criticized option 1, PGA flow through of these surcharges, as placing too much of a burden on firm sales customers. Services noted that ". . . the filed tariffs of Services [did] not break tariff rates into demand and commodity components. All costs [were] rolled into the weighted average cost of gas, making determination of contract demand charges difficult." Services' Comments at 23.

Services found policy option 2 unacceptable because it could force interruptible sales customers to transportation or completely off-line as they converted to alternative fuel. It characterized policy option 4 as unworkable. Services noted that it would be nearly impossible for it to make determinations regarding customer purchase deficiencies for over 62,000 retail customers. Due to a constantly changing customer base, Services asserted that adoption of policy option 4 would leave unanswered questions such as how to treat customers who no longer have gas service, modify the type of service they receive, or join the system as new customers.

Roanoke also submitted comments. In its comments, it urged the Commission to join Virginia LDCs in their participation in FERC proceedings involving interstate pipelines and to encourage LDCs to develop and implement initiatives for the passthrough of take-or-pay surcharges finally approved. In addition, Roanoke supported a variation of policy options 1 and 3.

Roanoke urged the Commission to adopt policies permitting it to amortize the recovery of take-or-pay costs from firm service customers over a 60 month period, together with interest, at the same rates from time to time allowed on customer deposits and refunds. Roanoke also suggested that firm customers be credited with periodic surcharge collections from interruptible sales customers during a five year amortization period under a special incremental surcharge tariff designed to recover from interruptible sales the difference between the PGA adjusted commodity sales rate and as much as the equivalent value of No. 2 fuel oil. Roanoke stated that the foregoing mechanism would permit it to recover fixed and volumetric surcharges related to take-or-pay liability in the same manner that contract demand charges are recovered under Roanoke's PGA. In this way, Roanoke believed it could recover a portion of its take-or-pay costs from industrial customers, who, in Roanoke's opinion, were primarily responsible for creating this cost burden.

In its filed comments, GE took the position that because industrials and other end users within the Commonwealth did not participate in the writing of take-or-pay contracts, they should not participate in the dissolving of these contracts. GE cautioned that tampering with gas prices would cause every end user with the capability to do so to start burning oil.

Finally, the Commission's staff filed comments. Its comments observed that all the players in the industry, including interstate pipelines, local utilities, and end users contributed to take-or-pay problems. The staff stated that efforts to assess take-or-pay culpability directly to any of these groups would be highly subjective and difficult to prove. The staff's comments identified various sources of take-or-pay costs. For example, a portion of take-or-pay costs are associated with buying-out-or-down problem contracts and may be a source of prospective benefits. staff further noted that there were some historical benefits associated with the incurrence of take-or-pay costs. Staff Comments at 4. Staff noted that significant savings to end users resulted from spot market purchases. The staff believed that jurisdictional utilities received no direct benefit from the savings associated with spot purchases and therefore, it could not support a direct assessment of take-or-pay costs to these local utilities. Staff Comments at 6.

Staff also characterized take-or-pay costs as an obstacle to open access transportation and the associated competitive benefits. Viewed in this light, take-or-pay costs may be considered in the nature of an access fee for nondiscriminatory transportation. Staff generally supported recovery of take-or-pay costs through a volumetric surcharge, provided that the policy was applied with flexibility and sensitivity to each LDC's competitive situation. Staff acknowledged that a volumetric surcharge option had certain flaws and recommended that where gas competition with alternate fuels was rendered impossible after application of the surcharge, the Commission permit recovery of these costs through an alternative mechanism.

The staff also joined many of the other commentators and recognized that alternative approaches for allocation of Pipeline's take-or-pay liability may be appropriate in light of Pipeline's unique characteristics. These characteristics include Pipeline's readily identifiable customer population and the significant portion of Pipeline's nongas costs attributable to take-or-pay costs.


As we noted in our July 6th Order for Notice and Comment, the FERC has properly recognized our authority to reallocate the fixed surcharges related to take-or-pay and buy-out and buy-down transactions in Order No. 500:

The Commission [FERC] does not believe that Nantahala precludes state regulators from designing LDC rates, or, in appropriate circumstances, from reviewing the prudence of LDCs' purchasing decisions insofar as they affect take-or-pay costs . . . . Therefore, the Commission believes state regulators could consider reclassifying take-or-pay costs billed as a fixed charge as commodity costs and incorporating such costs into LDC sales or transportation rates, or both, thereby spreading such costs to the maximum possible extent as well as subjecting them to market forces. Alternatively, state agencies may wish to consider the option of not reclassifying fixed take-or-pay charges and instead allocating such charges to the LDC's customers based on their cumulative purchase deficiencies.

The Commission can exercise its jurisdiction only within its legitimate sphere, which in this instance involves establishing cost allocation procedures and rates for recovery by pipelines of take-or-pay costs from their jurisdictional customers. The development of cost allocation procedures and rates for the LDCs are matters to be determined by state regulatory authorities. Order No. 500, III FERC Stats. & Regs., Para. 30,761 at 30,790 (Aug. 14, 1987).

FERC has properly acknowledged our authority to prescribe the design for the rates and charges of jurisdictional gas utilities. Section 1(b) of the Natural Gas Act of 1938 ("NGA"), 15 U.S.C. § 717(b) (1982), and the Hinshaw Amendment, 15 U.S.C. § 717 (c), clearly reserve this area to the regulatory authority of states. The Hinshaw Amendment granted an exemption from federal regulatory jurisdiction to natural gas companies if both the receipt and ultimate consumption of gas occur within a single state, provided the rates, service, and facilities are subject to regulation by a state commission. A certification by a state commission to the FERC that the state is exercising such jurisdiction constitutes conclusive evidence of such regulatory power or jurisdiction. 15 U.S.C. § 717(c).

We have certified to FERC that we regulate one such pipeline - Commonwealth Gas Pipeline Corporation. LDCs are gas companies operating in the local distribution of natural gas. Hence the cases cited by commentators addressing wholesale election power transactions in interstate commerce are inapposite because those cases, unlike the instant case, refer to matters directly affecting wholesale rates which are within the FERC's jurisdiction. Here, the gas companies we regulate are within our jurisdiction under the provisions of the federal law.

Our authority to design rates for our jurisdictional gas companies under the Virginia Constitution, statutes, and case law is unquestioned. As Commonwealth Gas Services, Inc. has observed in its comments at page 16:

Article IX, Section 2 of the Virginia Constitution grants to this Commission the power and charges the Commission with the duty of regulating the rates, charges and services of public utilities within the Commonwealth. Title 56 of the Code of Virginia, dealing with public service companies, and particularly Chapter 10 thereof dealing with heat, light, power, water and other utility companies generally, sets forth the power and authority of the Commission to consider and determine rates, tolls, charges and schedules of public utilities to be just and reasonable and to insure that such rates, tolls, and charges are related to aggregate actual cost incurred by the public utility in servicing its customers. Such rates also are to provide a "fair return on the public utility's rate base used to serve those jurisdictional customers.' § 56-235.2 of the Code of Virginia.

Indeed as the Virginia Supreme Court has observed:

In fixing rates within the limits of what is confiscatory to the utility on the one side, and exorbitant as against the public on the other side . . . there is a reasonably wide area within which the Commission is empowered to exercise its legislative discretion.

Norfolk v. Chesapeake and Potomac Tel. Co. of Va., 192 Va. 292,300 (1951).


The Commission obviously enjoys considerable flexibility under both federal and Virginia statutes to design a mechanism for recovery of take-or-pay liability. Review of the comments demonstrates that all of the policy alternatives have associated problems which must be addressed.

One of the approaches under consideration was the cumulative deficiency methodology to allocate costs associated with the take-or-pay liabilities. We are compelled to find that the cumulative deficiency methodology should be rejected for LDCs. As virtually every LDC that participated in this proceeding has noted, such a methodology would be impossible to administer given the diversity of respective LDC customer populations.

Further, we reject the second policy alternative-allocation of costs associated with the fixed surcharges to both firm and interruptible gas commodity costs. This policy could have a deleterious effect on an LDC's ability to retain interruptible customer loads. As the WGL Companies' comments have observed, any surcharge affecting the rate charged to interruptible customers would probably make that rate less attractive vis-a-vis other fuels. Imposing additional take-or-pay expenses on interruptible customers would, for example, force the WGL Companies to experience reductions in margins on their interruptible sales. Reduced margins are directly absorbed by utilities outside of a rate case. In view of the large percentage of take-or-pay exposure already included in FERC-approved surcharges, additional charges in interruptible rates will inappropriately reduce WGL and other utilities' margins. WGL Comments at 13-14.

The third methodology is, in our opinion, inappropriate because, as VNG and other commentators have noted, it too will severely constrain the relative ability of Virginia LDCs to compete with alternate fuels. To the extent that Virginia utilities must depend on industrial loads for a large percentage of their operating revenues, both the financial viability of these companies and the stability of the base gas rates charged to their firm customers may be jeopardized by the adoption of this policy alternative.

After review of this record, we are compelled to find that option 1 is the most appropriate course of action. While no one option under consideration allocates costs in a completely equitable manner, this approach has the advantages of being easy to administer and assuring complete recovery of take-or-pay related costs. In addition, this approach will not unduly complicate the efforts of Virginia utilities to compete with alternate fuels.

Additionally, a slightly different tack must be taken as to the division of take-or-pay costs for LDCs serving multiple jurisdictions, e.g., WGL. As to these companies, a cumulative deficiency approach must be used to split the Virginia jurisdictional portion of take-or-pay costs out of the total company costs. Once these costs have been identified, then the jurisdictional company may proceed to recover the identified jurisdictional portion of these costs through its PGA.

Finally, we find that the record supports treating Commonwealth Gas Pipeline as a unique entity. As virtually every party to this proceeding has noted, Pipeline is unique by virtue of, among other things, its limited customer pool and the extremely high percentage of its gas costs which are take-or-pay related. Pipeline's limited number of customers allows a more precise measurement of the benefits associated with take-or-pay. Additionally, Pipeline's unique circumstances provide for a better identification of the causes of take-or-pay liability. Consequently we find that Pipeline should be permitted to develop a mechanism for recovery of its take-or-pay related costs separate and distinct from the policy established herein for LCDs. Its recovery mechanism should reflect the historic as well as the prospective benefits derived from gas purchasing practices which have increased take-or-pay liability. In developing this recovery mechanism, we encourage Pipeline to work actively with its customers. Should Pipeline and its customers be unable to reach agreement with regard to a recovery of the take-or-pay costs in an expeditious manner, this Commission will not hesitate to prescribe a recovery mechanism.

Accordingly, IT IS ORDERED that all jurisdictional gas distribution utilities may recover the fixed demand charges associated with take-or-pay liability and contract reformation through their purchase gas adjustment clauses. It is further Ordered that Pipeline shall forthwith file tariffs complying with the principles identified above with regard to take-or-pay liability. It is finally Ordered that there being nothing further to be done herein, this matter is hereby dismissed.

Lacy, COMMISSIONER, concurring in part and dissenting in part:

For the last two years Virginia natural gas companies and customers have been anticipating the flow-down of costs associated with the buy-out or buy-down of take-or-pay contracts. During that time, we have examined the legality, practicality, and fairness of the available options for recovery of these costs. While no solution is ideal, all involved do agree that these costs are transitional in nature and must be resolved before the natural gas industry can realize its market potential.

The cost recovery mechanism chosen by the majority, automatic recovery through the PGA clause, while the least complex to administer, does not reflect a fair allocation of cost recovery. I believe recovering take-or-pay acquisition costs from a broader customer base, including sales, transportation, and interruptible customers, lessens the financial burden to any one class of customer and more accurately reflects a philosophy that responsibility for these costs cannot be assigned to any one segment of the industry. In my opinion, such a mechanism, combined with the flexibility for each local gas distribution company to justify some variant or modification to allow continued competitive operations, while administratively more complex than the PGA, represents a reasonable and more equitable resolution to this difficult but transitional situation.

I concur with the majority holding regarding take-or-pay related costs for Commonwealth Gas Pipeline.

1Regulation of Natural Gas Pipelines After Partial Well head Decontrol, Docket No. RM87-34-000, III FERC Stats. & Regs., Paragraph 30,761 (Order No. 500) (hereafter Order No. 500).

20VAC5-300-80. Order relating to confidential treatment of Fuel Monitoring Report FM-12. (Repealed.)

By letter dated June 28, 1990, Delmarva Power and Light Company ("Delmarva") requested that certain information which Delmarva provides in conjunction with the Commission's fuel monitoring system be kept confidential and not released to the general public. On July 18, 1990, Appalachian Power Company requested similar treatment. Information to support the preparation of "Fuel Monitoring Report 12 (FM12) - Coal and Oil Purchase Summary Report" and several other reports is filed monthly with the Commission's Division of Economics and Finance to monitor the fuel expenses incurred by electric utilities in the operation of generating facilities. The Commission initiated this proceeding when it became apparent that the fuel monitoring information of all electric utilities presented similar confidentiality issues.

Section 56-249.3 of the Code of Virginia requires certain electric utilities to file such information on fuel transactions and fuel purchases as the Commission deems necessary on a monthly basis. It is pursuant to this statute that utilities file the information to support the preparation of Report FM12 and several additional reports. Report FM12 contains a very specific breakdown of information related to the utilities' purchases of coal and oil. Section 56-249.3 of the Code of Virginia provides that the information required from utilities may include the supplier of the fossil fuel; the cost in cents per MBTU, with a notation of whether the fuel was contracted for, purchased on the spot market, or purchased from an affiliate of the electric utility; total demurrage charges incurred at each generating plant; total cost of transportation incurred at each generating plant; and the average cost of the fossil fuel in cents per MBTU's consumed at each plant with and without handling charges. Section 56-249.4 of the Code of Virginia provides that any information filed in accordance with § 56-249.3 of the Code of Virginia shall be open to the public. Although the Commission has wide discretion to determine the information to be filed under § 56-249.3, we have no discretion under § 56-249.4 to withhold some of the information from public disclosure.

Nevertheless, the Commission finds that the confidentiality concerns of the electric utilities are well-founded in one respect. Under § 56-249.3 of the Code of Virginia we have heretofore required separate reporting of both the delivered price of fossil fuel and the cost of its transportation to various utility facilities. This level of detail is not necessary for the public reports prepared under § 56-249.3, in our view. In the future, for purposes of § 56-249.3, utilities may report total delivered fossil fuel prices without separate reporting of transportation costs. For regulatory monitoring purposes, the staff may require the utilities to continue to provide detailed fossil fuel purchase information outside of the context of § 56-249.3 and under an appropriate agreement of confidentiality.

Our decision here should not be interpreted to permit utility companies to refuse disclosure to our staff of any information which staff deems necessary to accomplish its official duties. Nor should it be read as a defense to discovery by any party to a commission proceeding, subject to appropriate protective orders if necessary. Staff review and the scrutiny of other parties in fuel factor and other Commission proceedings should be sufficient to protect the public interest in reasonable utility fuel purchases. Accordingly,


1. That electric utility companies filing information under § 56-249.3 of the Code of Virginia may report fuel purchase costs on the basis of total delivered prices;

2. That all information reported by electric utility companies pursuant to § 56-249.3 of the Code of Virginia shall continue to be made public by the Commission pursuant to § 56-249.4 of the Code of Virginia; and

3. That, there being nothing further to come before the Commission in this proceeding, Case Number PUE900046 shall be closed and the papers therein placed in the Commission's files for ended causes.

20VAC5-300-100. Standards for fuel cost projections of electric utilities. (Repealed.)

The 1989 Session of the General Assembly adopted Senate Joint Resolution No. 156 ("Resolution") requesting the State Corporation Commission to establish standards for evaluating the reasonableness of the fuel cost projections of electric utilities. The Resolution stated that "such standards need to be established in order to ensure that payments for power purchased by electric utilities from cogenerators are fair, reasonable, and appropriate." Pursuant to that Resolution, the Commission, by an order dated January 10, 1990, directed its staff to complete an investigation and submit its findings and recommendations in a report. On February 15, 1990, staff submitted its Report on the Development of Standards for Fuel Cost Projections ("Staff Report").

By Order dated March 16, 1990, the Commission directed its Division of Energy Regulation to provide notice of the proposed standards contained in the Staff Report and invited interested persons to comment and to request a hearing. Pursuant to that March 16, 1990, Order, the Commission received comments from CRSS Capital, Inc.; Chesapeake Corporation, Stone Container Corporation, and Westvaco Corporation ("Industrial Protestants"); and Delmarva Power ("Delmarva").

Fuel cost projections have several interrelated applications and, accordingly, the accuracy of those projections is very important. First, an electric utility must make fuel cost projections to facilitate optimal resource planning. The more accurate the fuel cost projections, the better the utility can anticipate and plan for its future needs.

As emphasized in the Resolution, fuel cost projections are also essential to ensure payments for power purchased from cogenerators and small power producers are fair and reasonable. Administratively determined payments to such qualifying facilities are based upon an electric utility's avoided costs, which are necessarily calculated by projecting the utility's system costs, but for the purchases from the qualifying facilities. The assumptions underlying that calculation clearly must include fuel cost projections. Again, to ensure payments that are fair to the qualifying facility and to the ratepayer, those projections must be as accurate as possible.

Finally, fuel cost projections must be made to develop the fuel factor which an electric utility adds to its base rates for all electricity sold. Each fuel factor is designed to recover the fuel costs the utility expects to incur during the subsequent twelve months. It also includes a correction factor designed to correct any over or under recovery of prior period fuel expenses. Although the fuel factor includes a true-up mechanism, it is still important for the utility to base the factor on accurate fuel cost projections to minimize extreme fluctuations or variances in customers' bills.

Staff recommends, and we agree, that standards for fuel cost projections should be broad and flexible. Such a framework will allow the standards to be readily applied to each individual utility in differing circumstances. General parameters, however, must be established.

Staff recommends the following minimum standards for fuel cost projections:

1. A sophisticated "state-of-the-art" production costing model should be utilized for projecting fuel expenses.

2. Key input data and assumptions should reflect historic data. Any significant deviation from historic trends should be adequately explained and evaluated for reasonableness.

3. Key input data such as load forecasts, generating unit characteristics, fuel data, and system parameters should be developed in the same relative time frame and reflect consistent assumptions.

4. Demand forecasts should be current and reflect economic growth, normal weather, the price of electricity, elasticity assumptions, appliance saturations, income and population changes in the utility's service area. They should also reflect projections of energy, peak demand and the effects of demand-side options.

5. Expected fuel prices should reflect historic fuel costs adjusted for any known dynamics of the projection: i.e., labor contracts, expected operation of the spot market, current fuel contracts, the world fuel market, inventory levels and fuel availabilities, purchasing volumes, coal severance taxes, etc.

6. Unit operations should consider planned maintenance, forced outages, expected dispatch levels, historical performance levels, seasonal capabilities, as well as ongoing enhancements or unit deterioration.

7. Dispatch orders should reflect such variables as system economics, unit availabilities, minimum operating levels, heat rates, and terms and conditions of purchased power contracts.

8. Purchase power levels should consider need, system economics, power availability and transmission constraints.

9. Projections supporting the development of cogeneration rates should include a comparison of key input data and assumptions from the last fuel projection filed with the Commission. Major changes should be adequately explained.

20VAC5-317-40. Initial implementation of standby rates. (Repealed.)

On or before April 1, 2010, each utility shall submit to the State Corporation Commission (commission) a plan setting forth the utility's plan for compliance with this chapter. A utility may submit its existing standby provisions as its proposed plan for compliance with this chapter. Thereafter, following notice and an opportunity for hearing, the commission will determine whether a utility's plan complies with this chapter.

20VAC5-320-120. Filing schedule. (Repealed.)

Each incumbent electric utility required to obtain commission authorization for the transfer of its transmission assets to an RTE shall file the application required by 20VAC5-320-90 with the Clerk of the Commission not later than October 16, 2000.

VA.R. Doc. No. R20-6264; Filed April 13, 2020, 9:49 a.m.