Administrative Code

Virginia Administrative Code
Title 20. Public Utilities and Telecommunications
Agency 5. State Corporation Commission
1/21/2020

Chapter 306. Standards for Integrated Resource Planning and Investments in Conservation and Demand Management for Natural Gas

20VAC5-306-10. Procedural history.

On October 24, 1992, Congress enacted the Energy Policy Act of 1992 ("EPACT" or "the Act"), P.L. 102-486, 106 Stat. 2776 et seq. (1992). Section 115 of that Act amended the Public Utility Regulatory Policies Act of 1978 ("PURPA"), 15 USC § 3202, to add provisions requiring state regulatory commissions to consider standards governing integrated resource planning ("IRP") and investments in conservation and demand management for natural gas utilities. Specifically, the Act requires state commissions to consider whether:

.........each gas utility shall employ an integrated resource plan, in order to provide adequate and reliable service to its gas customers at the lowest system cost. All plans or filings of a State regulated gas utility before a State regulatory authority to meet the requirements of this paragraph shall (A) be updated on a regular basis, (B) provide the opportunity for public participation and comment, (C) provide for methods of validating predicted performance, and (D) contain a requirement that the plan be implemented after approval of the State regulatory authority. Subsection (c) shall not apply to this paragraph to the extent that it could be construed to require the State regulatory authority to extend the record of a State proceeding in submitting reports to the Federal Government.

15 USC § 3203(b)(3).

With respect to conservation and demand management ("DSM") for natural gas utilities, EPACT provides that

.........the rates charged by any State regulated gas utility shall be such that the utility's prudent investments in, and expenditures for, energy conservation and load shifting programs and for other demand-side management measures which are consistent with the findings and purposes of the Energy Policy Act of 1992 are at least as profitable (taking into account the income lost due to reduced sales resulting from such programs) as prudent investments in, and expenditures for, the acquisition or construction of supplies and facilities. This objective requires that (A) regulators link the utility's net revenues, at least in part, to the utility's performance in implementing cost-effective programs promoted by this section; and (B) regulators ensure that, for purposes of recovering fixed costs, including its authorized return, the utility's performance is not affected by reductions in its retail sales volumes.

15 USC § 3203(b)(4). Further, if a state adopts either of these standards, it must:

(1) consider the impact that implementation of such standard would have on small businesses engaged in the design, sale, supply, installation, or servicing of energy conservation, energy efficiency, or other demand-side management measures; and

(2) implement such standard so as to assure that utility actions would not provide such utilities with unfair competitive advantages over such small businesses.

15 USC § 3203(d)(1),(2).

Section 115 defines "integrated resource planning" for gas utilities to mean

......... planning by the use of any standard, regulation, practice, or policy to undertake a systematic comparison between demand-side management measures and the supply of gas by a gas utility to minimize life-cycle costs of adequate and reliable utility services to gas consumers. Integrated resource planning shall take into account necessary features for system operation such as diversity, reliability, dispatchability, and other factors of risk and shall treat demand and supply to gas consumers on a consistent and integrated basis.

15 USC § 3202(9). "Demand-side management" as used in § 115 includes "energy conservation, energy efficiency, and load management techniques." 15 USC § 3202(10).

EPACT does not require the Commission to implement its standards, but if we do not implement them, we must nonetheless hold a hearing and state why we are rejecting the standards. Further, the Act requires us to complete our consideration of these standards not later than two years after the date of EPACT's enactment, i.e., by October 24, 1994. 15 USC § 3203(a).

EPACT provides separate integrated resource planning and investments in conservation and demand management standards for electric and gas utilities. See P.L. 102-486, 106 Stat. 2795, 2910, 16 USC § 2621(d). The standards for electric utilities, set out in § 111 of the Act, while similar in some respects to the standards for natural gas utilities, differ by allowing consideration of a broader scope of resource options for electric utilities. In addition, § 111 requires a regulatory body to complete its consideration of the relevant standards for electric utilities within three years of the Act's enactment, rather than two years, as required by § 115 for gas utilities. 16 USC § 2622(b)(2). The discrete statutory standards and time frames for consideration lead us to conclude that Congress intended the consideration of IRP and conservation and demand management standards for gas and electric utilities to proceed separately rather than as a single proceeding.

This interpretation of the Act is consistent with the legislative history for § 115. The Joint Explanatory Statement of the Committee of Conference accompanying House Conference Report No. 102-1018 for EPACT demonstrates that the conferees intended that IRP as addressed in § 115 be considered only for local distribution companies serving ultimate consumers of natural gas. The Statement further notes that IRP for natural gas utilities should examine and compare demand-side options with the general option of additional gas supplies. It expressly excludes an examination of the sources, conditions, or other characteristics of upstream gas supply as part of IRP for gas utilities.1

In its April 27, 1994 Order, the Commission directed its Division of Economics and Finance to give notice to the public of the captioned proceeding and set the matter for hearing for September 7, 1994. The same Order established a procedural schedule for interested parties, intervenors, and the Commission Staff, inviting them to address by testimony or comment, the standards, the issues identified in the Order, as well as issues of concern to the parties regarding the standards for natural gas utilities.

In response to the Commission's April 27 Order, Northern Virginia Electric Cooperative ("NOVEC"), the City of Richmond ("the City"), and Southwestern Virginia Gas Company ("Southwestern") each filed Comments. In its Comments, NOVEC noted its interest in the proceeding insofar as the adoption of standards affected gas utilities generally and impacted the service provided by NOVEC, an electric cooperative. Southwestern's filed comments supported the position taken by Roanoke Gas Company ("Roanoke") in Roanoke's prefiled testimony.

The City urged the Commission to adopt IRP and conservation and demand management standards which (i) prevent destructive competition between gas and electric utilities; (ii) encourage fuel substitution practices that reduce the cost of service for both gas and electric ratepayers; (iii) develop a comprehensive energy plan integrating gas and electric IRP; (iv) consider the cost of complying with existing state and federal environmental statutes and regulations; (v) encourage local distribution companies to conduct joint surveys and studies regarding the technical information necessary to evaluate demand-side alternatives at a reasonable cost; (vi) encourage a pilot DSM bidding program; and (vii) discourage policies that would reduce regional supply alternatives.

On the appointed day, the matter came for hearing before the Commission. Counsel appearing were Kristen Brown, Esquire, and John Epps, Esquire, for Commonwealth Gas Services, Inc. ("Commonwealth"); Donald Fickenscher, Esquire, for Virginia Natural Gas, Inc. ("VNG"); Donald R. Hayes, Esquire, for Washington Gas Light Company ("WGL"); James H. Jeffries, Esquire, and Charles H. Carrathers, III, Esquire, for United Cities Gas Company ("United"); Richard D. Gary, Esquire, for Virginia Electric and Power Company ("Virginia Power"); John D. Sharer, Esquire, for the Virginia Industrial Gas Users' Association ("VIGUA"); Edward L. Flippen, Esquire, for NOVEC; and Sherry H. Bridewell, Esquire, for the Commission's Staff. No intervenors appeared.

At the request of the participants, direct and rebuttal testimony were presented together. Witnesses for the Staff, Commonwealth, and WGL took the stand and were subject to cross-examination. By agreement of counsel, the testimonies of Jeffrey L. Huston on behalf of VNG, Richard K. Wrench for United, Robert W. Glenn, Jr. for Roanoke, Mary C. Doswell for Virginia Power, and Dr. Alan Rosenberg and Robert Cooper for VIGUA were received into the record without cross-examination. At the conclusion of the proceeding, the matter was taken under advisement.

1H.R. REP. No. 1018, 102d Cong., 2nd Sess. (1992) reprinted in U.S.C.C.A.N. 2472, 2474-75.

Statutory Authority

Chapter 3 (§ 12.1-12 et seq.) of Title 12.1, Chapter 10 (§ 56-232 et seq.) and Chapter 10.1 (§ 56-265.1 et seq.) of Title 10.1 of the Code of Virginia and 15 USCA § 3202.

Historical Notes

Derived from Case No. PUE940030 §I, eff. October 14, 1994.

20VAC5-306-20. Summary of the participants' positions at the hearing.

Connie Davies presented testimony on behalf of Commonwealth. She testified that the Commission should adopt the EPACT's provisions for gas IRP with modifications, advocating a comprehensive approach to IRP which considers the optimal fuel selection among energy suppliers. Ms. Davies testified that Commonwealth was committed to the development of demand-side management proposals and noted the importance of complete and timely recovery of DSM program cost-recovery as an essential component of IRP activities. Ms. Davies observed that demand-side management programs can influence the fuel use decisions of gas utility customers. She stated that to the extent electric utilities have the opportunity to implement DSM programs and gas utilities are not permitted to offer similar programs, gas utilities were placed at a competitive disadvantage. Witness Davies testified that she did not envision the expansion of IRP and DSM as having a negative impact on small businesses.

Commonwealth also presented testimony that supported the use of an automatic adjustment clause for recovery of lost revenues. Commonwealth witness Stalnaker testified that deferring costs associated with DSM programs without allowing recovery of associated carrying costs or rate base treatment for such costs exposed Commonwealth to under-recovery of program costs and created a regulatory disincentive to implementation of conservation and demand programs.

While Commonwealth witness Davies appeared to support a collaborative IRP process, Commonwealth witness Connell's rebuttal testimony stressed the need to incorporate an ability to make changes within an IRP approved by the Commission. He also recommended a five year planning horizon for IRP but acknowledged that the life cycle of many DSM programs extended beyond five years. He failed to explain how the need to change IRP proposals and the utility's need to keep information confidential could be accommodated within a collaborative process.

VNG presented the direct and rebuttal testimonies of Jeffrey L. Huston which were received into the record without cross-examination. Mr. Huston recommended that: (i) the Commission not adopt IRP for gas utilities as envisioned in EPACT; (ii) the Commission permit gas companies in Virginia the flexibility to pursue market responsive demand-side management ("DSM") programs which were in the public interest; and (iii) after gaining further experience with gas conservation and load management ("CLM") programs, the Commission reconsider the issue of gas IRP.

In his rebuttal testimony, Mr. Huston recommended that some gas utility forecast information should be treated as confidential. Witness Huston urged the Commission to recognize that cost recovery standards are potential policy tools that could influence a gas utility's decisions regarding conservation and demand management. VNG acknowledged that little evidence existed to suggest that stronger cost recovery measures are merited at present. VNG attributed this, in part, to the recent adoption of formal cost-benefit tests to evaluate such programs and the relative lack of experience that the natural gas industry has in applying these methods of evaluation.

WGL presented the direct testimony of Sandra K. Holland and the rebuttal testimony of Paul H. Raab. In her testimony, Ms. Holland recommended that the Commission reject the IRP standard set forth in EPACT unless the standard was broadened to include all cost-effective CLM strategies. Ms. Holland asserted that it was important to subject electric and gas utilities to similar standards when considering CLM programs since such programs could be used to induce customers to use one type of fuel over another. She supported adoption of EPACT's conservation and demand management standard in order to remove disincentives to gas utilities to sell less natural gas. Ms. Holland further proposed that mandatory demand-side bidding processes be adopted in order to ensure that small businesses were not adversely impacted by the adoption of the IRP standard.

In his rebuttal presented on behalf of WGL, witness Raab testified that the increasingly competitive environment confronting local distribution companies ("LDCs") required a broad definition of IRP. In his view, IRP defined narrowly as conservation or load management was incompatible with a competitive environment for gas utilities. Witness Raab also characterized lost revenue adjustments and decoupling mechanisms as inappropriate options to encourage conservation and load management investments in a competitive environment. He supported all-source bidding as an appropriate strategy to encourage cost effective CLM programs and to address the conflict between electric and gas utilities in an increasingly competitive environment. He asserted that revisions to gas utility purchased gas adjustment ("PGA") mechanisms and capacity release proposals found in VIGUA's testimony were beyond the scope of this investigation. He testified that giving LDC industrial customers a right of first refusal on the release of capacity may not maximize the value obtained for that capacity or benefit firm ratepayers.

United presented the direct and rebuttal testimonies of Richard K. Wrench. While witness Wrench supported IRP, Wrench urged the Commission to refrain from adopting specific rules that would require LDCs to adopt IRP plans or DSM programs that do not appropriately consider the uniqueness of each LDC and its market. He urged the Commission to allow fuel substitution and load shifting programs to be a part of a utility's IRP analysis. Mr. Wrench recommended that the Commission allow flexibility for a utility to cancel or change an IRP or DSM program that does not achieve expected results. He encouraged the Commission to develop guidelines providing a level playing field for gas and electric utilities in order to prevent the IRP process from impeding normal competition between these industries.

In his rebuttal testimony, Mr. Wrench asserted that gas planning was too uncertain to use forecasted data extending beyond five years. He testified that the supply-side of IRP should begin within a five year forecast of current needs, unaffected by any demand-side planning programs. Witness Wrench also noted that a degree of confidentiality was necessary for such plans and that the issue of confidentiality should be addressed on a case-by-case basis.

The testimony of witness Robert W. Glenn, Jr. was received into the record on behalf of Roanoke without cross-examination. Through Mr. Glenn's testimony, Roanoke urged the Commission not to adopt the IRP standard set out in § 115 without modification. It asserted that the standard be modified to include fuel switching and load growth programs. It questioned the cost effectiveness of formal IRP and DSM procedures. Roanoke was concerned about the additional costs formal IRP programs could add to the operating costs of small gas utilities. It requested that if the Commission adopted a mandatory IRP procedure for all gas utilities, that such a procedure provide for the complete and timely recovery of costs associated with IRP and DSM. It urged the Commission not to give electric companies an unfair market advantage over their gas utility competitors.

Mary Doswell's prefiled direct and rebuttal testimony on behalf of Virginia Power was received into the record without cross-examination. Through Ms. Doswell's testimony, Virginia Power asserted that a formal IRP process was unnecessary. It urged the continued practice of requiring annual resource plans to be filed with the Commission Staff for review. It stated that CLM programs should continue to be subject to Commission approval as contemplated by the Promotional Allowance Rules adopted in Case No. PUE900070. Virginia Power asserted that there would be little incremental benefit to utility ratepayers from a formal IRP process. It argued that a formal process could hinder the natural competitive processes currently driving IRP. Virginia Power urged the Commission to eliminate any financial disincentives which could be associated with the selection of demand-side resource options over supply-side options.

Through its rebuttal testimony, among other things, Virginia Power noted that: (i) any standards or requirements which emerge from the investigation should apply equally to gas and electric companies; (ii) under "least-cost" planning, supply-side and demand-side options should be evaluated on an equal basis, including regulatory treatment of cost-recovery; (iii) the policies and procedures currently in place allow effective competition among Virginia's gas and electric utilities; and (iv) the policies and procedures now in place with the filing modifications proposed by Staff are sufficient to achieve IRP objectives.

The direct and rebuttal testimony of Dr. Alan Rosenberg, together with the direct testimony of Robert Cooper, were received into the record on behalf of VIGUA without cross-examination. VIGUA urged the Commission to reject a formal IRP process and maintained that the objectives of IRP - the lowest reasonable rates consistent with reliable service and efficient use of resources - could be achieved effectively within the current regulatory framework. It cited the administrative costs associated with a formal IRP process, utility expectations that approval of its IRP guaranteed recovery of costs associated with programs approved as part of the IRP, and the tendency for special interest groups to view the IRP process as a vehicle through which they may achieve their preconceived agendas as reasons why the Commission should reject a formal IRP process.

VIGUA recommended that the Commission direct gas utilities to achieve reliable service at the lowest reasonable cost through the use of a modified PGA which would allow an LDC to retain a portion of the savings achieved by lowering the cost of gas until its subsequent rate case. VIGUA proposed that the balance of gas purchase savings be passed through to its sales customers. As another step to minimize gas costs, VIGUA recommended the use of cost-based, unbundled transportation rates and capacity release programs. With respect to capacity release, VIGUA asked the Commission to require LDCs to negotiate with their end-users for capacity packages sized in a fashion that does not preclude end-users from using such capacity.

Staff presented the testimony of three witnesses -- Robert L. Lacy, Cody D. Walker, and Richard W. Taylor. Witnesses Lacy and Walker recommended that the Commission reject the § 115 IRP standard as administratively burdensome and costly. Staff suggested that the Commission's existing procedures through its five-year forecast review, with modifications, and its conservation and load management procedures adopted in Case No. PUE900070 were sufficient to address planning needs for gas utilities. Staff witness Lacy testified that adoption of the § 115 IRP and the investments in conservation and demand management standards would represent a departure from recently developed policies.

Witness Lacy also recommended that several changes be incorporated into the five-year forecast data request. He suggested that the long term plans submitted by gas utilities should provide fundamental information concerning demand-side management plans. He proposed the use of a longer planning horizon, i.e., 10 years, for gas utilities with significant demand-side management activities. Further, witness Lacy stated that much of the data in the forecasts filed by gas utilities could be made available for public review.

Staff witness Walker also urged rejection of the § 115 standards as vague, narrow, and costly to administer. He noted that the Commission's current policies provide sufficient flexibility for evaluation of CLM programs. He testified that the objectives of the § 115 standards could be addressed through incentive programs and improved pricing. He observed that continued movement towards cost-based rates and further rate unbundling would provide additional information to ratepayers, enabling them to make informed end-use decisions.

Witness Walker commented that improperly structured IRP policies could conflict with competitive forces and may result in the subsidization of appliances or equipment that would not otherwise be competitive in an open market. He observed that many commentators advocating fuel substitution as a part of IRP appeared to be attempting to provide natural gas utilities with a competitive marketing advantage over electric utilities.

Witness Walker addressed VIGUA's proposals to implement revisions to the PGA and to develop capacity release procedures for LDCs. He characterized these proposals as beyond the scope of the present investigation. Mr. Walker acknowledged that it may be appropriate to explore these issues in future proceedings.

Mr. Walker also explained the Staff's review of gas utility acquisition practices. He stated that Staff reviewed gas utility capacity release programs through informal data requests in the context of PGA filings and in rate cases. He testified that upon request of an industrial customer, Staff would make data filed in response to these informal data requests available to requesting customers. Mr. Walker also stated that Staff would consider expanding the five-year forecast data to include information concerning LDCs' capacity release programs. He cautioned that because capacity release programs were relatively new, it was inappropriate to develop formalized filing requirements for such programs.

Staff witness Taylor testified about the accounting treatment to be accorded DSM programs. He concluded that it was unnecessary to adopt the standards set out in § 115 because existing ratemaking and accounting policies provide sufficient opportunity for gas utilities to recover their costs and investments in CLM programs. The Staff opposed cost recovery for such programs through an automatic adjustment mechanism because, in Staff's view, automatic recovery of such costs would remove them from the rigorous review to which they would be subjected in a rate proceeding. All Staff witnesses acknowledged that the traditional rate setting process provided little incentive for gas utilities to promote programs that conserved natural gas. They recommended that rate recovery for CLM programs be treated on a case-by-case basis. Witness Taylor concluded that the accounting conventions available for supply-side costs under Commission policies should also be available for demand-side costs.

Statutory Authority

Chapter 3 (§ 12.1-12 et seq.) of Title 12.1, Chapter 10 (§ 56-232 et seq.) and Chapter 10.1 (§ 56-265.1 et seq.) of Title 10.1 of the Code of Virginia and 15 USCA § 3202.

Historical Notes

Derived from Case No. PUE940030 §II, eff. October 14, 1994.

20VAC5-306-30. Discussion.

In recent years, both the framework for federal regulation of the natural gas industry and the industry itself have undergone a radical transformation. Prior to the enactment of the Natural Gas Policy Act of 1978 ("NGPA"), 15 USC §§ 3301-3442, the interstate distribution of natural gas was regulated under a "just and reasonable" standard established by the Natural Gas Act ("NGA"), 15 USC §§ 717-717w, under which the Federal Power Commission ("FPC") prescribed "just and reasonable" rates for pipelines and producers selling natural gas for resale in interstate commerce. See 15 USC § 717c. During the late 1960s and the early 1970s, the wellhead prices for interstate natural gas were low, while the prices for gas in intrastate markets were unrestrained and rose to meet demand. The federal price restraints at the wellhead encouraged the consumption of gas in intrastate markets and, at the same time, discouraged producers from dedicating reserves to the pipelines serving the interstate markets. Gas shortages resulted.2

In reaction to the shortages of natural gas in the interstate market, Congress enacted the NGPA, establishing a framework for the partial decontrol of natural gas at the wellhead. The NGPA also included provisions to restrain demand for natural gas. Under the law's incremental pricing scheme, P.L. No. 95-621, §§ 221-08, 92 Stat. 3371-81 (Repealed 1987), pipelines and LDCs were required to charge higher prices for natural gas to industrial gas users.3 Further, the Power Plant and Industrial Fuel Use Act of 1978 ("FUA"), P.L. No. 95-620, 92 Stat. 3289 (codified in scattered sections of 15, 42, 45, and 49 USC), prohibited burning natural gas in industrial facilities and electric power plants.

At the same time, other forces worked to control the demand for natural gas. The economic recession of the early 1980's shrunk natural gas markets, and consumers reacted to higher natural gas prices by reducing consumption and switching to less expensive fuels. Thus, the interstate natural gas market was transformed from one in which there was a perceived shortage of supply to one in which there was an actual excess of deliverability.

Since 1987, Congress has repealed the incremental pricing provisions of the NGPA, amended FUA to eliminate virtually all restrictions on the use of natural gas in electric power plants and other major fuel burning installations, and decontrolled all of the remaining NGPA regulated gas. Further, enactment of the Clean Air Act Amendments of 1990, P.L. No. 101-549, 104 Stat. 2399 (1990), has created a role for natural gas as a cost-effective option for compliance with the market based acid rain program. This program is designed to reduce sulfur dioxide emissions through an allowance and emissions trading program.

EPACT itself contains provisions intended to stimulate natural gas production and usage and to promote the development of new markets for natural gas usage. See for example, provisions dealing with alternative minimum tax preferences for depletion and intangible drilling cost of independent oil and gas producers and royalty owners, 106 Stat. at 3023-24; and § 2013 of the Act, 106 Stat. at 3059, which directs the Secretary of Energy to conduct a five-year program to increase the recoverable natural gas resource base.

The Federal Energy Regulatory Commission ("FERC"), the successor to FPC, has also responded to the changes in the natural gas market. In 1984, for example, it created an opportunity for LDCs to take advantage of competitive wellhead markets with the issuance of Order No. 380, which invalidated fixed cost minimum bills and minimum take obligations in pipeline tariffs.4 In 1985, it issued Order No. 436 which further redefined the role of interstate pipelines.5 Order No. 436 in effect required pipelines to become open access, non-discriminatory transporters of natural gas. Pipelines were encouraged to permit their firm sales customers to convert their entitlement of firm sales service to volumetrically equivalent entitlement of firm transportation service over five years. Order No. 436, and its successor, Order No. 500, 52 F.R. 30,334, effectively began to phase out the aggregator/merchant role of interstate pipelines.

FERC's Order No. 636 further altered the structure of services provided by interstate natural gas pipelines.6 This restructuring rule expressly sought to promote greater competition among natural gas suppliers by requiring pipelines to provide equal quality transportation service to customers regardless of whether natural gas was purchased from the pipeline or from another supplier.7 It further limited the role of interstate pipelines to that of transporters and providers of storage rather than the role of merchants.

It is against this federal legislative and administrative framework that we are called upon to consider adoption of EPACT standards. Adoption of these standards would require a formal procedure to consider integrated resource plans for each regulated Virginia natural gas utility. By definition, these standards do not expressly include load building programs, but instead encourage energy conservation, energy efficiency, and load management initiatives for LDCs.

In our opinion, integrated resource planning may serve the public good by minimizing unnecessary or excessive energy use, considering the applicability of all fuel resources, and determining the best fuel resource for end use at the lowest possible cost. However, as this record demonstrates, a mandatory, formal approval process provides few benefits to either natural gas utilities, natural gas customers, or regulators. As many gas utility participants noted, use of a formal, generic IRP process requires a commitment of time and resources. Further, once adopted, a plan may become outdated, while circumstances and market conditions continue to change. The need to accommodate changing circumstances by incorporating flexibility in an IRP inhibits the value of the plan approval process, creating problems for those participating in the process. As demonstrated by the testimony received in this record, gas utilities appear to want the safe haven that approval of an IRP provides and the flexibility to change the approved plan whenever they believe necessary. Many of the Virginia LDCs participating in this proceeding are already engaged in some form of IRP and will continue such planning regardless of whether we adopt a formal IRP process. Tr. at 85-86.

No gas utility submitting comments or testimony was able to identify a substantive benefit arising from the adoption of an IRP standard requiring the mandatory submission and formal approval of integrated resource plans. For example, Commonwealth witness Davies admitted that there was nothing Commonwealth could achieve via a formal IRP process that it could not now accomplish under current Commission policies. Tr. at 118-120.

The only benefit cited by gas utility participants arising from a formal IRP process was the likelihood of enhanced recovery of costs for programs approved as part of an overall IRP. Tr. at 119. Even this potential benefit is illusory, as Commonwealth witness Davies conceded, since nothing in our current CLM policies prohibits an LDC from seeking approval of the rate treatment it believes appropriate for such programs. Tr. at 118-120, 122.

Currently, we employ a less formal procedure to scrutinize gas supply and planning practices for Virginia LDCs. This informal review employs a five-year forecast, with an annual Staff review of gas purchasing practices for large LDCs, and biennial review of such practices for smaller gas utilities. Complementing this analysis is a quarterly review by Staff of a Virginia LDC's gas purchasing decisions through review of the utility's PGA data. These procedures were adopted in Commonwealth of Virginia, ex rel. State Corporation Commission, Ex Parte, in the matter of establishing an investigation of gas purchasing, procurement practices, and gas cost recovery for Virginia gas utilities, Case No. PUE880031, 1988 S.C.C. Ann. Rept. 333, 336-337. Any discrepancy in purchasing, planning and acquisition of gas supply may be the subject of a rule to show cause or may be explored further in a gas utility's rate case.

The information collection vehicle for the gas supply forecast is a data request, wherein Staff develops information forecasted over five years. Admittedly, gas forecasting is an uncertain process. However, the advent of capacity release and the implementation of pilot conservation and load management programs by Virginia gas utilities may render it appropriate to broaden the informational context in which we evaluate LDC purchasing decisions. To this end and in exercise of our plenary authority under Virginia Code §§ 56-36, -235.1, and -249 to obtain information about utility operating efficiency and use of resources, we will direct our Staff to gather additional data about demand-side management programs, capacity release programs, and other natural gas utility plans and practices which affect the supply, acquisition, and delivery of natural gas to Virginia end-users. Because DSM programs may extend beyond five years in length, we hereby authorize Staff to request additional forecast and other data from Virginia LDCs with DSM and capacity release programs. In this way, we will develop a more comprehensive picture of the factors affecting Virginia LDC planning.

We will address the issue of accessibility to plan data filed by Virginia LDCs on a case-by-case basis. We encourage Staff to make nonproprietary data available to LDC customers upon request. LDCs should file their data with Staff in both a redacted and nonredacted form to accommodate requests by LDCs' customers for review of this information.

Our policies regarding conservation and load management programs were established in our March 27, 1992 Final Order and June 28, 1993 Order entered in Commonwealth of Virginia, at the relation of the State Corporation Commission, Ex Parte: In re, Investigation of Conservation and Load Management Programs, Case No. PUE900070. As we noted in the March 27 Order, we are encouraged about the role conservation can play in Virginia. However, we noted in that Order that a cautious approach was necessary to avoid promoting uneconomic programs or those that are primarily designed to promote growth of load or market share without serving the overall public interest.8 We therefore promulgated rules establishing the conditions under which gas and electric utilities operating in Virginia could recover reasonable costs associated with promotional allowances to customers.9 We require utility applicants proposing a promotional allowance program to demonstrate that their program is reasonably calculated to promote the maximum effective conservation and use of energy and capital resources in providing energy services. Promotional allowance programs must be cost justified using appropriate cost/benefit methods. Utilities proposing a promotional allowance program that would have a significant effect on the sales level of an alternative energy supplier must consider the effect of the program on the supplier, and demonstrate that the program serves the overall public interest.10 The June 28, 1993 Order Issuing Rules on Cost/Benefit Measures entered in the same docket adopted a multi-perspective approach to evaluate conservation and load management proposals. This Order directed that an applicant seeking approval of a DSM program should analyze the program using, at a minimum, the Participants Test, the Utility Cost Test, the Ratepayer Impact Test, and the Total Resource Cost Test to evaluate such programs.11

Further, in our June 28, 1993 Order, we permitted gas and electric utilities to file packages of programs, but advised that utilities should assure themselves that the programs collectively benefited their resource plans. We directed that a cost/benefit analysis for each individual program be available, even if the application filed with the Commission sought approval of a package of programs. Further, we required utilities to file reports available to the public with the Staff, which identified all experimental programs at least 30 days prior to the program's implementation, together with periodic updates on the results of the experiment. Comprehensive reports on the status of all experimental or pilot programs were to be filed at least semi-annually with our Division of Economics and Finance. Id., 1993 S.C.C. Ann. Rept. at 245.

The record before us demonstrates that Virginia gas utilities have limited experience in developing conservation and demand-side management programs in Virginia. Virtually all of the gas utilities filing comments and testimony in the proceeding noted that DSM programs influence the fuel choices made by end-users. They opined that the definition of DSM programs should include load building initiatives and allow gas utilities to retain or increase their markets. See Ex. CBD-4 at 7-11. Ex. SKH-12 at 5-6. Ex. PHR-13(R) at 7. Tr. at 94, 127, 130-131. However, little testimony was offered on how specific conservation programs could be designed to reduce gas usage by existing gas customers. For example, Commonwealth witness Davies identified peak clipping as an appropriate DSM objective, Ex. CBD-4 at 9, but during cross-examination, admitted that Commonwealth has not sought approval for any peak clipping CLM programs in Virginia. Tr. at 122-123.

Witnesses Stalnaker, Huston and Holland each testified that there were financial and operational disincentives which discouraged LDCs from developing and implementing programs that reduced natural gas usage. They requested that the Commission consider regulatory incentives to motivate LDCs to develop such programs. Ex. RGS-9(R) at 3; Ex. JLH-11(R) at 4; and Ex. SKH-12 at 27-28.

As we noted in our March 27, 1992 Final Order in the CLM investigation, conservation will play an important role in the development and use of fuel resources in Virginia. However, conservation at any cost is inappropriate. We decline in this case to adopt an approach which encourages Virginia LDCs to implement programs which are primarily designed to promote load growth or market share without serving the overall public interest. As acknowledged by our Staff and several participants in this proceeding, our current CLM policy offers the opportunity and the flexibility for natural gas utilities to develop CLM programs. Our policy specifies minimum tests against which all applicants' CLM proposals may be evaluated. Under this policy, neither gas nor electric CLM programs are treated differently. Thus, neither gas nor electric competitors are offered a competitive advantage.

Moreover, as our June 27, 1994 Final Order entered in Application of Appalachian Power Company, For a general increase in rates, Case No. PUE920081, states, a distinction can and should be made between utility "conservation" and "load management" programs. Under the latter, a utility's sales may be shifted to its off-peak period, preserving some level of utility profit, while reducing the utility's operating expenses. In contrast, with conservation, a utility may actually lose sales and, thus, profits. June 27, 1994 Final Order, Case No. PUE920081 at 13.

We recognize that there may be financial disincentives associated with LDC development and implementation of programs that reduce gas usage. We acknowledge that increased natural gas consumption may be beneficial in many respects. In fact certain federal policies encourage natural gas usage. Increased natural gas usage may facilitate compliance with the Clean Air Act Amendments of 1990 through fuel switching at coal or oil fired generating units and through the use of natural gas powered vehicles. Increased throughput for LDCs and pipelines may also serve to lower natural gas rates if increased throughput does not require additional facilities or result in higher purchased gas demand costs.

However, it is difficult to distinguish between programs which are designed to conserve gas usage and those which are promotional in effect. For example, incentives for higher efficiency gas furnaces may in some instances promote fuel switching rather than decreased natural gas consumption. Therefore, ratemaking incentives designed solely to promote energy conservation may fail to encourage other programs that are in the public interest or that have the unintended consequences of increasing natural gas usage through gains in natural gas market share. Given the difficulty of identifying "pure" conservation programs and the probability of overlooking beneficial programs, we conclude that it is not appropriate to develop ratemaking incentives strictly for the purpose of promoting conservation. Therefore, we encourage LDCs seeking permanent implementation of conservation and load management programs demonstrated to be in the public interest to develop recommendations regarding ratemaking incentives appropriate to each of their circumstances. Such an approach will encourage innovation and provide for flexible regulatory policies that are appropriate for each Virginia LDC's size, load profile and resources.

2Donald F. Santa, Jr. and Patricia J. Beneke, "Federal Natural Gas Policy and the Energy Policy Act of 1992", 14 Energy Law Journal 1, 4-7 (1993).

3Id., 14 Energy Law Journal at 5 (1993).

4See Elimination of Variable Costs from Certain Natural Gas Pipeline Minimum Commodity Bill Provisions, Order No. 380, 49 Fed. Reg. 22,778 (1984), aff'd, Wisconsin Gas Co. v. FERC, 770 F.2d 1144 (D.C. Cir. 1985).

5See Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 50 Fed. Reg. 42,408 (1985) vacated and remanded, Assoc'd. Gas Distrib. v. FERC, 824 F.2d 981 (D.C. Cir. 1987), readopted on an interim basis, Order No. 500, 52 Fed. Reg. 30,334 (1987).

6Order No. 636, III FERC Stat. and Regs., 30,939 at 30,389 (1992).

7Order No. 636, III FERC Stat. and Regs., 30,939 at 30,389, 30,391 (1992).

8March 27, 1992 Final Order, 1992 S.C.C. Ann. Rept. at 263.

9Id., 1992 S.C.C. Ann. Rept. at 265.

10Id., 1992 S.C.C. Ann. Rept. at 265, Slip. Op., Attachment A, §IV A(5).

11Commonwealth of Virginia, ex rel. State Corporation Commission, Ex Parte: In re: Investigation of Conservation and Load Management Programs, Case No. PUE900070, 1993 S.C.C. Ann. Rept. 242, 244-245.

Statutory Authority

Chapter 3 (§ 12.1-12 et seq.) of Title 12.1, Chapter 10 (§ 56-232 et seq.) and Chapter 10.1 (§ 56-265.1 et seq.) of Title 10.1 of the Code of Virginia and 15 USCA § 3202.

Historical Notes

Derived from Case No. PUE940030 §III, eff. October 14, 1994.

20VAC5-306-40. Conclusion.

In sum, adoption of a formal IRP process as envisioned by § 115 of EPACT does not appear to promote and indeed may be detrimental to the public interest. This standard does not appear to offer sufficient flexibility, and may increase regulatory costs to the participants in the IRP approval process, without substantive countervailing benefits. We encourage Virginia natural gas utilities to continue to develop and employ comprehensive planning strategies. Virginia LDCs should use existing CLM procedures to seek approval for CLM programs which they can demonstrate to be in the public interest. As part of Virginia LDCs' planning strategies, we expect LDCs to maintain continuing dialogues with their customers in an effort to better ascertain these customers' energy needs and to respond to those needs. Staff should continue to work with and develop data with respect to LDC planning processes and LDC customer needs to monitor more comprehensively these utilities' planning processes and service performance.

While we do not adopt the investments in conservation and demand management standard set out at § 115 of the Act, we remain sensitive to the need for development of conservation and load management programs that are in the public interest. Because we have not adopted § 115's integrated resource planning or conservation and demand management standards, we find it unnecessary to address the impact of implementation of such standards on small businesses.

Further, the Commission remains committed to the goal of promoting cost-effective conservation programs. We believe conservation programs can promote the public interest in Virginia and can contribute to the realization of a proper balance of demand-side and supply-side resources. Conservation programs are particularly attractive because of the environmental benefits they offer. The environmental benefits of conservation programs, while often difficult to measure, are nevertheless, very real. We encourage utilities to develop conservation programs that are not only economically sound but also contribute to the protection of the environment that we all must share. We also encourage utilities to focus on energy efficiency when developing their long-term strategic plans. Energy efficiency is one of the more important factors considered by consumers in making choices between electric, gas, and oil appliances and equipment. Electric and gas utilities should compete for customers by providing accurate information about the efficiencies and features of various types of HVAC equipment. A healthy competition can be facilitated by integrated resource planning techniques. However, integrated resource planning should not be used as a tool simply to market increased use of gas or electricity or indiscriminately gain market share at the expense of a competitor.

Accordingly, for the reasons set out herein, it is ordered that the standards set out at § 115 of EPACT be rejected; and that this matter be dismissed. The papers filed herein shall be placed in the Commission's files for ended causes.

Statutory Authority

Chapter 3 (§ 12.1-12 et seq.) of Title 12.1, Chapter 10 (§ 56-232 et seq.) and Chapter 10.1 (§ 56-265.1 et seq.) of Title 10.1 of the Code of Virginia and 15 USCA § 3202.

Historical Notes

Derived from Case No. PUE940030 §IV, eff. October 14, 1994.



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