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Virginia Administrative Code
Title 20. Public Utilities and Telecommunications
Agency 5. State Corporation Commission
Chapter 306. Standards for Integrated Resource Planning and Investments in Conservation and Demand Management for Natural Gas

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.

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