# Presentation: 040727

## Incentives and Rate Designs for Efficiency and Demand Response 

**Drs. Steven D. Braithwait & Laurence D. Kirsch**
**CA Energy Consulting**
**DRRC/CEC Workshop**
**January 31, 2006**

## Project Objectives 

*Develop:**** ***
- A*** conceptual framework*** for improving rate design incentives for efficiency and demand response
***Prototype rate designs*** that illustrate application of the framework
***Phase 2 plan*** to apply framework, develop specific rates, and address regulatory barriers

## Our Conceptual Framework

*Economic efficiency* – retail pricing that maximizes the *net economic benefits* produced by electricity
- Achieved when:
**Price** (marginal value) = **Marginal cost**, or
*Curtailable service* program credits = market value

## Marginal Cost-based Pricing

- Vast literature supports basing utility pricing and programs on marginal costs
- Walras (1800s)
- Boiteux (1949), Steiner (1957)
- Bonbright (1961)
- Kahn (1970-71)
- Caramanis, Bohn & Schweppe (1987) [LMP]

## Our Conclusion

- Recent efforts to encourage demand-responsive rates such as CPP and RTP in CA are consistent with moving toward economically efficient, *marginal cost-based retail pricing.*
- However, the considerable delays and revised rate proposals suggest that the primary barrier to improving retail rates in California appears to be:
***NOT*** a lack of target rate designs, but
***Constraints*** imposed by traditional rate-making practices of the utilities and regulators

## Our Recommendation:Phase 2 project to...

- Review current rates relative to our Phase 1 conceptual framework:
- Principal current IOU tariffs
- Recent CPP and RTP proposals
- Develop candidate efficient rate designs (*e.g.*, RTP, CPP, day-type TOU), based on data for:
- Agreed-upon marginal cost scenarios
- Customer loads for a case study utility
- Work with stakeholders to assess barriers / determine transition path to acceptance

## Background:The Need for Responsive Demand

- Energy ***market inefficiencies*** exist due to the combination of:
- Varying hourly marginal costs
- Fixed retail prices
- Resulting in:
- Non-responsive electricity demand
- Extra generation capacity and higher costs *to meet non-responsive demand*

## Opportunities for Increased Economic Efficiency:Frequent Differences Between MC and Price

**Opportunities for Increased Economic Efficiency:*****Frequent Differences Between MC and Price***

**Resource costs >**
**customer value**

**No access to **
**low-cost power**

- Load-weighted
- average price

## The Solution:Retail Rates that Reflect Marginal Costs

- Marginal costs vary hourly, in real time
- Efficient retail prices reflect that variation
- Rate features can reduce consumers’ uncertainty
- Greater notice (day-ahead RTP)
- Fixed prices most of time; variable only when most important (CPP, day-type TOU)
- Price cap (RTP with price cap)
- Financial hedges to guarantee fixed price on fixed quantity (RTP with hedging)

##         Effect of Responsive Demand:Avoid uneconomic fuel & capacity costs

*Load reduction serves*
*as “virtual generator” to *
*avoid fuel and capacity costs*

**Supply and Demand in Summer Afternoon Hour**

## Incentives for Responsive Demand

- Marginal costs provide the basis for market-based incentives.  With responsive demand...
***Utility*** can avoid high marginal costs that exceed foregone revenue [*Increase in net revenue*]
***Customers*** facing high prices reduce bill by more than foregone value of load reduction [*Increase in net benefits*]
- Win-win opportunity!

## ...But, Barriers to Efficient Retail Pricing

- Metering costs (not constraint for >200kW)
- Rate complexity
- Lack of incentives under regulation
- Concern about revenue impacts (recovering revenue requirements)
- Concern about bill impacts (distributional impacts on consumers)
**Good design can help overcome barriers**

## Mechanisms for Achieving Responsive Demand

**Pricing** approaches (Dynamic pricing)
**RTP** (hourly prices)
**CPP** – day/hour-ahead critical price(s) called to reflect market cost/reliability conditions
- Combined with flat or TOU pricing
**Day-type TOU** – 3 levels, called day-ahead
**Quantity** approaches – curtailable service
- Reliability action needed on short notice

## Cost Basis for Efficient Retail Rates

- Cost unbundling
- Customer services
- T & D facilities
- Generation services (energy, reserves, transmission losses & constraints)
- Marginal costs of generation
- Marginal energy costs
- Marginal capacity/reliability costs
- Marginal externality costs

## Properties of Efficient Retail Rates

- Recover revenue requirements for *fixed costs*
- Unbundled rates for T & D
- Minimize price distortion to recover above-market generation costs (*e.g.*, DWR contracts)
- Set energy prices (no demand charges) to reflect *expected marginal generation costs*
- Tradeoff between accuracy and uncertainty for fixed vs. dynamic prices
*Fixed* prices reflect higher expected cost & risk
*Dynamic* prices reflect marginal costs when most important
- Customer choice from limited menus

## Efficient Pricing Rule

- Retail price in period *T*:
- PT = ∑h *E*{Qh * [PEh + RRh * PRh]}/ ∑h *E*{Qh},
- where *h* is hours in *T*, RR is reserve requirement ratio, PE and PR are energy and reserves prices, and *E* is expected value
- PT** **is *expected cost* to serve load in period T** **
- Implicit risk premium for fixed prices

## Example:  TOU with CPP 

- Separate prices for --
*off-peak *period,
- on-peak period, *except* top 1% of hours,
*top 1%* of hours (CPP)
- No concern about # of CPP events
- Non-CPP peak prices cover expected costs in non-critical hour types
- CPP prices cover costs when MC is high

## Peak TOU & CPP Prices – Summer 2005

- All peak hours

- Excl. top 60 hrs
- (10% discount)

- Top 60 hours

## Reconciling Marginal Costs and Average (Accounting) Costs

- Under competition, reconciliation over time is reflected in generator profitability
- Under regulation, a variety of reconciliation methods have been proposed:
- Ramsey (inverse-elasticity) pricing
- Non-linear pricing
- Block pricing
- Two-part pricing – access charge & energy prices

## Example of Reconciling MC & AC – Unbundled RTP with Hedging

- Unbundled T&D rates apply to all current usage
- Fixed energy price applied to *baseline* load  recovers allowed generation costs
- Marginal cost-based RTP prices apply to *deviations from baseline load** *
- Demand response can benefit both consumers and the utility – not *“zero-sum game”*

## Unbundled RTP with Financial Hedge: 

- kWh

- Price

- PB

- KB

- Demand

**Unbundled RTP with Financial Hedge: **
**Baseline hourly load billed at fixed price P****B**** **

- Base bill

- Fixed price can be TOU
- peak and off-peak, with
- values set by forward
- power contracts.

## Sharing Benefits from Responsive Demand:Consumer Response to Hour of High RTP Price

**Sharing Benefits from Responsive Demand:*****Consumer Response to Hour of High RTP Price***

- Demand (PRL)

- MC = PE ($500)

- PRTP/DR payment
- 	($400)

**Load reduction**
**(1 MW)**

- KA

## Example of Unbundled RTP with Hedging in Competitive Retail Markets

**Constellation NewEnergy** has 6,000 MW of large customer load on similar products
- Customers face hourly prices indexed to RTO day-ahead or real-time prices (*e.g.*, PJM, ERCOT)
- Customer selects amount of load to be covered by fixed-price contracts
- Balancing loads (above and below contract level) settled at indexed prices
- Natural pricing product for commodity with price volatility and existing forward markets

## Efficient Curtailable Service

- Two benefits of curtailable service
*Insurance value* of operating reserves
*Operating value* of cost savings/reliability
- Two program types
*Traditional* – capacity (reserves) credit for mandatory curtailment (covers both sources of value)
*Performance-based* – smaller credit, _*plus*_ payments for actual curtailments (similar to some DR programs)

## Quantifying Curtailment Payments

- Maximum payments for insurance & operating value:
- PMTIns ≤ ∑ *E*{QAv * (PNSR – CAv)} – CFix
- PMTOp ≤ ∑ QCurt * max {0, (PE – PRET – CCurt)}QAv & QCurt are Curtailable (Available) & Curtailed load,PNSR , PE & PRET are prices of non-spin reserves, energy & retail; andCAv , CCurt  & CFix are program costs that depend on curtailable load, actual load curtailed, and fixed
*Performance-based* design aligns benefits to consumers and utility – pays for services actually delivered

## Phase II Plan

- Overall objectives:
**Where are we?**  Assess existing retail rates in California, including proposed CPP & RTP
**What is the ultimate goal?**  Develop “ideal” set of default and optional rates with appropriate incentives for efficiency & DR
**How do we get there?**  Work with stakeholders to assess barriers and determine practical transition approach

## Phase II Research Activities (1)

- Determine objectives & case study
- Identify issues and objectives – regulatory barriers and stakeholder objectives
- Identify case study – Utility involvement crucial to success; need customer data
- Identify candidate rate structures

## Phase II Research Activities (2)

- Review and data preparation
- Review principle utility tariffs & proposed dynamic pricing rates
- Develop marginal cost scenarios
- Assemble customer load data
- Develop price responsiveness assumptions

## Phase II Research Activities (3)

- Analysis and transition strategies
- Develop energy prices based on conceptual framework
- Evaluate recommended menus of rates
- Review short-term & long-term options for transitioning to recommended rates

## Contact Information

- Steven Braithwait
- “SDBraithwait@caenergy.com”
- 608-231-2266
- Laurence Kirsch
- “ldkirsch@caenergy.com”
- 415-663-8608