Website:

http://www.raponline.org

The Regulatory Assistance Project177 Water St.

Gardiner, Maine USA 04345Tel: 207.582.1135

Fax: 207.582.1176

50 State Street, Suite 3Montpelier, Vermont USA 05602Tel: 802.223.8199Fax: 802.223.8172

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

June 16, 2003Harrisburg, PA

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

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

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?

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.

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

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%

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%

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

PBRFormula 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

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

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.

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

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

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 ruralTypically, around 5% of a distribution

system is "high cost" at any time

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 pricesEquity and customer acceptance issues

would be large

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

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.

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.

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.

Interconnection Issues

Technical and equipment standards.Degree of standardization.Organization of utility review.Level of review and treatment for large vs

small systems.

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.

For Larger SystemsOften 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

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?

Topics of Standardized Interconnection Procedures

Standard ApplicationExpeditious Review

– Screening criteria (size, drawings, devices)Standard Agreement

– Technical requirementsUtility ActionsTestingDispute Resolution

Technical Standards

Provide specific technical/equipment requirements for interconnection.

Primary focus is IEEE stakeholder process to define standards.

IEEE 1547 nearly complete.