Facilitating DR Development: Barriers, Interconnection, Rates, and Ratemaking

1. Facilitating DR Development:Barriers, Interconnection,Rates, and Ratemaking June 16, 2003 Harrisburg, PA Website: http://www.raponline.org

2. Institutional and Regulatory Barriers • Permitting and Siting Processes • Multiple agency approvals may be needed • Potentially complex and time-consuming • Rates and Ratemaking issues • Stand-by rates, exit fees, deferral rates • What is reasonable? How to structure? • Potential financial impacts on utilities • Grid Interconnection Process • Safety, power quality, distribution system capacity constraints vs utility discouragement of DG

3. Institutional and Regulatory Barriers • Market • Day ahead, multi-settlement demand bidding • For all of these issues: • Lack of technology information and generally accepted standards • Large variation in requirements from state-to-state, utility-to-utility, and project to project • Often a lengthy, complex, and expensive process

4. Ratemaking • Revenue erosion • Methods for addressing potential negative financial impacts on utilities • Lost-revenue adjustments • Performance-based rate-making • Revenue caps PBR • Removing the throughput disincentive: why not?

5. Lost Profits Problem • Consider whether regulation may unintentionally cause utilities to be hostile to demand-side (baseload energy efficiency) and distributed resources and, if so, what regulatory fixes are available.

6. Cost-of-Service Regulation • Regulation and utility profits do not work as one might expect • Once a rate case ends prices are all that matter • Profits = revenue - costs • Rev = price * volume • In the short-run, costs are mostly unrelated to volume; instead they vary more directly with number of customers • If demand-side investment causes volume to decrease, utility profits drop

7. Lost Profits Math:Vertically Integrated Utility • Utility with $284 million rate base • ROE at 11% = $15.6 million • Power costs $.04/kWh, retail rates average $.08; sales at 1.776 TWh • At the margin, each saved kWh cuts $.04 from profits • If sales drop 5%, profits drop $3.5 M • Demand reductions equal to 5% of sales will cut profits by 23%

8. Lost Profits Math:Wires-Only Company • Utility now has only a $114 million rate base • ROE at 11% = $6.2 million • Distribution rate of $0.04/kWh; throughput of 1.776 TWh • If DR is located in low-cost areas, each saved kWh cuts $.04 from profits • If sales drop 5%: profits drop $3.5 M • 5% reduction in sales will cut profits by 57%

9. Performance-Based Regulation • All regulation is incentive regulation • Trick is to understand the incentives • PBR structural options • Revenue caps, price caps, hybrids, rate freezes • Scope, duration

10. PBR • Formula for revenue caps PBR • % change in Revenue = It – Xt + Zt • Formula for price caps PBR • % change in Price = It – Xt + Zt • Common elements • It = Inflation in year t • X = Productivity improvement in year t • Z = Exogenous changes in year t

11. PBRPer Customer Revenue Cap • A cap is placed on distribution company revenues • Cap is computed at beginning of first year as average revenue requirement per customer (RPC) • Allowed revenues at end of year computed as RPC times number of customers. • RPC adjusted in following years for inflation, productivity, and other factors • Rates set as usual: per kW and per kWh • Utility and customers both have incentive to be efficient

12. PBR • Revenue caps v. price caps • Cost-cutting incentives are the same • Revenue caps make more sense if costs don’t vary with volume • Per-customer revenue cap more accurately matches utility short-run revenue need with short-run costs • Retail prices still set on unit basis (per kWh, kW)! • Price caps make more sense if costs vary with volume • Primary difference is the incentive for DSM and demand response • Firms under revenue caps want very efficient customers • Revenue caps deals with lost sales disincentives without radical price reforms • Logic also applies to transmission companies • On a total revenue basis, with performance measures for congestion management. Can’t be done on a per-customer basis.

13. Rate Issues • Rate design – how does it encourage or discourage distributed resources? • Standard offer and delivery rates • Time-differentiated rates: TOU, seasonal, etc. • Stand-by or back-up service and exit fees • De-averaged distribution credits

14. Rates • Retail prices: do they send proper economic signals? Do they reveal the value of DR? • Stand-by rates: • How are they calculated? As they set so as to discourage on-site generation? • What is the probability that the self-generating customer will demand grid power at high-cost times? • Generation displacement rates: energy at low rates to deter threat of self-generation • Exit fees: to recover distribution costs “stranded” by departing or self-generating customers

15. Distribution Costs • Distribution costs vary greatly from place to place and time to time • Marginal costs range from 0 to 20 cents per kWh • High cost areas can be urban or rural • Typically, around 5% of a distribution system is "high cost" at any time

16. Distribution Pricing • Geographically de-averaging prices is probably not the answer • Prices would range from 0 to 20 cents per kWh • Neighbors could see widely different prices • Equity and customer acceptance issues would be large

17. Distribution Credits • Offering distribution credits can send economic price signals with much less risk • Calculated with reference to the avoided cost of new distribution investment in high-cost areas • Credits can focus on customer and vendor actions • Credits can be limited to “qualifying DR” • Defined by type, performance, emissions, output, duration, etc. • Can use standard payments and/or bidding

18. Interconnection • Most DG projects need access to the grid • For back-up/standby operation • To supply some portion of power consumption • To sell excess power • Interconnection raises real and complex issues of grid security and worker safety but can also be a means of utility discouragement of DG.

19. Developer Concerns • Interconnection is left to the utility, which may see DG as a direct competitor. • Utility is free to set complex and expensive study and equipment requirements. • Usually handled on a case-by-case basis (except for net metering) • There is little accountability or recourse for delays or unfavorable outcomes.

20. Utility Concerns • DG could disrupt or destabilize the grid either in normal operation or malfunction. • DG could create a safety risk to workers. • Utilities have historically controlled these issues and have their own procedures, which they consider to be best practice. • Widespread DG is new for many utilities.

21. Interconnection Issues • Technical and equipment standards. • Degree of standardization. • Organization of utility review. • Level of review and treatment for large vs small systems.

22. Net Metering • A demonstrated and workable solution for small systems. • “Standardized” rules for small systems behind the meter. • “Small” ranges from 3 to 100 kW • Technology requirements are limited • Still wide variation from state-to-state.

23. For Larger Systems • Often considered with requirements for large merchant plants but issues may be very different: • Cost • Technology • Where is the size cut-off? • Different technical and procedural approaches required for different applications

24. Standardized Interconnection Procedures • Define the procedures, responsibilities, and limitations for various parties • Being developed at different levels • National: FERC, NARUC/NRRI • State: California, Texas, New York, Massachusetts • Too many standards?

25. Topics of Standardized Interconnection Procedures • Standard Application • Expeditious Review • Screening criteria (size, drawings, devices) • Standard Agreement • Technical requirements • Utility Actions • Testing • Dispute Resolution

26. Technical Standards • Provide specific technical/equipment requirements for interconnection. • Primary focus is IEEE stakeholder process to define standards. • IEEE 1547 nearly complete.