June 7, 2006 Technical Conference
Docket No. 05-057-T01
Conservation Enabling Tariff (CET) Joint Application
Agenda
Purpose of Technical Conference
Introductions
Overview of NRRI Briefing Paper - Ken Costello
Questions and General Discussion
June 7, 2006 Technical Conference
Docket No. 05-057-T01
Conservation Enabling Tariff (CET) Joint Application
Utah Commission Staff Draft Questions
Problem Identification
The Joint Applicant’s propose the CET in order to remove a disincentive to Questar investment in DSM. The disincentive is described as the inability of the utility to earn its authorized return between rate cases because the DSM programs will increase the decline in use of gas per customer and thereby reduce collection of the fixed costs currently recovered in a volumetric charge.
Questar is proposing a change in the way it recovers non-gas fixed costs. The proposed change presents a number of issues concerning whether the advantages of the proposed change outweigh potential disadvantages. Commission staff would like to understand these issues and would also appreciate a discussion of possible alternatives to the Questar proposal that could also remove disincentives to investment in DSM.
I. Relationship of Earnings to Net Revenues
The equation on page 8 of the NRRI Briefing Paper illustrates the relationship of earnings to net revenues (rather than use per customer) between rate cases, holding all other factors constant. The AGA study, “Forecasted Patterns in Residential Gas consumption, 2001-2020, EA 2004-04, Sept. 21, 2004,” cited in the NRRI paper, states that reduced consumption per customer does not imply that utilities’ total gas sales to residential customers will fall in the future. “Most studies expect moderate growth in total residential sales over the next several years, even in view of a continued decline in sales per residential customer (with growth varying by state and region). This means that utilities’ revenues from residential sales should grow between rate cases because of the addition of new customers, notwithstanding a decline in use per customer.”
a. What is the direct relationship of use per customer to earnings? Do the Joint Applicants assume that declining use per customer always results in declining net revenues? Are there factors that offset the effect of declining use per customer on earnings? What does Questar Gas’ history tell us about its net revenues between rate cases?
b. If it is net revenues rather than use per customer that impacts earnings, have the Joint Applicants provided, or do they plan to provide, evidence to support the likelihood and magnitude of declining net revenues attributed to Company-sponsored DSM programs? Is such evidence typically provided in decoupling proceedings?
II. Additional Benefits of Decoupling
Page 21 of the NRRI Briefing Paper states that in addition to promoting energy efficiency initiatives, the following three conditions would support revenue decoupling:
• Consumption per customer is likely to decline in the future.
• The ability to add customers is greatly limited.
• Expected declining use per customer is not recognized in ratemaking.
a. If only one of these three conditions exists, is that adequate support for approving revenue decoupling? Why the focus in the first condition on consumption per customer rather than net revenues?
b. The Company recovers distribution non-gas (DNG) costs on a weather normalized basis, other fixed costs through a fixed monthly charge, and recovers commodity and supplier non-gas costs through a balancing account. How does adoption of these regulatory mechanisms increase or decrease the benefits of revenue decoupling?
c. What information and type of analysis is necessary to determine the Company would under-earn due to Company-sponsored DSM programs?
III. Use Per Customer Data
a. The Joint Applicant’s request revenue decoupling for the GS rate schedule which includes both residential and commercial customers, and have supported this request by providing a temperature adjusted usage per customer graph in which residential and commercial customers are lumped together. Have other utilities lumped residential and commercial customers together when implementing revenue decoupling? If so have they broken their analyses out to reflect the different customer types? Is declining use per customer the same for the two customer classes?
b. Regarding the Joint Applicant’s graph entitled “Utah GS-1 Temperature-Adjusted Usage Per Customer,” how does one identify the individual contribution to the observed declining use per customer due to price impacts, weather impacts, changes to building codes, appliance efficiency standards, customer initiated DSM and the economy? How much will company-sponsored DSM affect the current trend under a variety of scenarios? Can the declining use per customer attributed only to Company-sponsored DSM programs be measured? Can that variable be isolated and tested?
c. What is the reasonable level to which consumption per customer can fall? Have other utilities provided such an estimate in their revenue decoupling applications?
d. Are there any studies which evaluate how much the natural gas price spike in the last couple of years has contributed to decreased usage per customer?
IV. Changes in Risk and Risk Shifting
a. Since the commodity gas costs and supplier non-gas costs are recovered through a balancing account, some fixed costs are collected through a fixed monthly charge, and the DNG costs (pretty much everything else) would be in the new CET balancing account, then over time the utility has a government guaranteed recovery of all prudent costs incurred. Given this type of recovery, what financial risk does the company face over time? Does the provision of gas service become a “cost-plus” contract? If so, what is a reasonable cost of capital to assign? A T-Bill rate? A Utah State Government rate?
b. Under a full decoupling approach to cost recovery the ratepayers assume most of the risk of price movement, and the further additional risk that Questar’s behavior and incentives would change; what benefits do customers receive to compensate them for this increased risk?
c. The proposed CET appears to fully decouple DNG decatherm sales from collection of DNG revenues. Remaining commodity and supplier non-gas costs are currently collected through a balancing account and remaining fixed costs through a fixed monthly charge rather than a volumetric charge. With these regulatory mechanisms in place governing all natural gas service costs, what incentive remains for the utility to be economically efficient?
V. Alternatives Comparison
a. Intervenor testimony raises the question as to why an incentive is needed for Questar Gas to pursue DSM when it is already obligated by Commission Order to pursue the least-cost alternative for the provision of natural gas energy services to its present and future ratepayers. Exhibit 9.23 of Questar Gas Company’s May 2, 2005, Integrated Resource Plan shows Company implementation of DSM programs would reduce Company costs and customer rates. Is it prudent for the Company to forego implementation of these programs in the absence of an approved CET?
b. Given that State law offers the option of a future test period for rate cases - which if done correctly will match revenues to costs on average - are there some other benefits to a decoupling approach (other than cost recovery and energy efficiency) that auger for its adoption?
c. When compared to a program that would only compensate Questar Gas for its direct DSM costs and any under recovery of fixed cost determined to be caused by those DSM programs, what are the advantages and disadvantages of both the decoupling approach and the future test year approach?
d. Is there a decoupling mechanism that addresses only the impact of Company-sponsored DSM programs on declining use per customer (or net revenues should this be the relevant factor affecting earnings)?
e. Are there any other regulatory mechanisms besides the decoupling proposal or the current use of a future test year that should be considered in this case?