Source: https://law.lis.virginia.gov/admincode/title20/agency5/chapter306/section30/
Timestamp: 2020-01-22 08:43:50
Document Index: 674838638

Matched Legal Cases: ['§ 3301', '§ 717', '§ 717', '§ 221', '§ 2013', '§ 56', '§ 12', '§ 56', '§ 56', '§ 3202']

20VAC5-306-30. Discussion.
Table of Contents » 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 » 20VAC5-306-30. Discussion.
Chapter 306. Standards for Integrated Resource Planning and Investments in Conservation and Demand Management for Natural Gas
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 Under the law's incremental pricing scheme, P.L. No. 95-621, §§ 221-08, 92 Stat. 3371-81 (Repealed 1987), pipelines and LDCs were required to charge higher prices for natural gas to industrial gas users.3 Further, the Power Plant and Industrial Fuel Use Act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.
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.
Derived from Case No. PUE940030 §III, eff. October 14, 1994.