Alexander Smart Meter

SMART METERS, DEMAND RESPONSE AND “REAL TIME” PRICING: TOO MANY QUESTIONS AND NOT MANY ANSWERS

Barbara R. AlexanderConsumer Affairs Consultant83 Wedgewood Dr.Winthrop, ME 04364(207) 395-4143E-mail: [email protected]

Disclaimer: This presentation does not reflect the views of ORNL or any other client

November 17, 2008 NASUCA 2008 2

ENERGY POLICY ACT OF 2005 AND

ENERGY SECURITY ACT OF 2007

Both Acts amend PURPA to establish a federal policy in favor smart meters, smart grid, and access to time-based pricing for all customers upon request

PURPA is not a federal mandate, but requires state investigation and consideration of federal standard within 18 mos.

Authorizes federal funding for smart meter and smart grid projects, but appropriations of these funds is required

2007 Act endorses decoupling and changing rate structures to reflect efficiency and conservation objectives


THERE IS MORE: 2008 STIMULUS BILL a/ka/ BAILOUT BILL

Section 306 in Title III authorizes accelerated depreciation (10 years instead of 20 years) for smart metering and smart grid systems

This significant tax advantage can ONLY be used by installing meters and T&D systems that meet the law’s definition of “smart” (two way communication; hourly readings; supporting demand response)


METERS AND PRICING RESIDENTIAL ELECTRIC SERVICE

“ADVANCED METERS”: Includes new digital meters, two-way communications capability; new communications network; meter data management systems; remote disconnect/reconnect switch

Costs? Not much public information, but utilities typically seek pre-approval and guaranteed cost recovery with distribution-based surcharge

WHY? Operation of distribution system: reliability; reduce

meter reading expenses; “manage the grid” New Pricing options: “real-time pricing” to manage

customer demand; reduce peak usage


REAL TIME PRICING: WHAT IS IT?

Dynamic retail pricing varies the price of electricity as wholesale prices fluctuate over the course of the day; rely on “spot” or “day ahead” prices

Theory: customers can shift usage or reduce usage according to their “sensitivity to price”

Are these pricing options for residential customers the most cost effective way to reduce system peak load and reduce generation supply prices?

Is this designed to allow customers to reduce their electricity bill? Or just shift usage to off-peak hours to avoid higher critical peak prices?


PREVIOUS EXPERIENCE WITH TOU FOR RESIDENTIAL CUSTOMERS

PUGET SOUND ENERGY: Mandatory TOU prices for all residential customers abandoned in 2002 when analysis showed negative cost benefit and higher, not lower, customer bills

Customers with most adverse bill impacts: multi-family and mobile homes

MAINE: Mandatory TOU prices for high use electricity customers made voluntary with onset of restructuring and widespread customer dissatisfaction in face of higher electricity prices

Elderly customers in newly built multi-unit condos and senior and low income housing complexes most adversely affected and without alternative options

NEW YORK: Previous efforts to push for Time of Use pricing resulted in state law that prohibits such time-based pricing except as voluntary options.

Many utilities offer Time of Use rate options to residential customers using interval meters; little customer interest

RESTRUCTURING STATES: Most abandoned mandatory TOU and other rate design structures associated with generation supply management and assumed that the competitive market would provide such products.


SMART METERS AND REAL TIME PRICING

Utilities in many states, some Governors, and state legislatures are endorsing smart meters and smart grid investments PA mandates smart meters for all within 15 years

Proponents emphasize customer “control” and ability to lower bill by using electricity at lower cost hours

Proponents emphasize importance of cutting peak usage and reducing price of electricity in long run

Environmentalists support as well to reduce need for new future generation, likely to be polluting


SMART METERS: KEY IMPACTS ON LOW INCOME CUSTOMERS

Costs of new systems run into billions for large utilities and will increase prices for all customers

Remote disconnection for nonpayment—no more premise visits to obtain payment, declare medical emergency, or detect unsafe and dangerous conditions for very young, old, or infirm

Prepayment metering easily the next step Encourages more reliance on volatile spot market

prices based on wholesale markets Can low income customers really shift usage

sufficiently to save on overall bill? What about elderly faced with paying 75 cents/kWh for air conditioning on hot summer days?


FERC REPORT (2006 and 2007) ON DEMAND RESPONSE AND ADVANCED METERING

Still a relatively small penetration of “advanced metering”, particularly for residential class

Statistics heavily influenced by “announcements” and “plans” and “pending proceedings.”

Few residential customers on some form of time-based rates or incentive-based load control programs

UNDERLYING MESSAGE: WE NEED MORE ADVANCED METERING TO SUPPORT DR PROGRAMS; NO ANALYSIS OF COST EFFECTIVE PROGRAMS TO ACHIEVE DR OUTSIDE OF THE ADVANCED METER APPROACH


FERC REPORT (CON’T)

REGULATORY BARRIERS TO INCREASE DEMAND RESPONSE AND PEAK PRICING PROGRAMS

Disconnect between retail prices and wholesale markets Utility disincentives: DR reduces utility revenues based

one sales—rate decoupling? Cost recovery and incentives for new technologies—pre-

approved cost recovery? More research on cost-effectiveness State-level barriers to DR: state laws and policies about

exposing customers to real time prices Retail and wholesale market rules that limit DR: hard to

link retail actions with wholesale market payments Barriers re role of third parties: providers need long term

regulatory assurance or long term contracts Insufficient market transparency and access to data Better coordination of federal-state jurisdiction: retail and

wholesale market coordination


CALIFORNIA DECISION: BILLION DOLLAR SMART METER PROGRAM APPROVED

In July 2006, California PUC approved PG&E’s proposal to replace all electric and gas meters with “smart meter” technology over five years

Price tag of $1.7 billion (20-year pay back) Statewide policy to rely on smart meters and DR to

reduce peak load HOWEVER, other benefits were major source of

“benefits” in analysis: remote meter reading; remote connection/disconnection; outage management

Existing TOU rates will be promoted and remain voluntary for time being

State law prohibits mandatory participation in Critical Peak Pricing for residential customers, but new voluntary CPP option will be implemented for certain hours in summer (1 cent/kWh discount)

PUC rejected TURN’s evidence that investment not cost effective for all customers and that more modest and targeted investment should be approved at this time


CALIFORNIA RESIDENTIAL TOU AND CRITICAL PEAK PRICING PILOTS

The California statewide pilot programs for 2,500 residential customers in 2002-2004 tested a variety of options (with constraints on bill and revenue impacts) and found:

Regular TOU prices did not result in any sustained usage impact even with prices TWO times the off peak price

Critical peak pricing reduced usage on Critical Peak days by 13-16% with prices FIVE TIMES higher as standard price (13 cents/kWh) or SIX TIMES higher than off-peak price; impacts varied across climate zones

Usage reduction significantly improved with installation of “smart thermostat” (27%) which were provided free of charge

Most usage reduction by higher use customers with central air conditioning systems and higher income, but lower usage customers were also able to shift usage at a lower impact

NO change in annual energy usage Lower income customers had lowest level of impact on usage

reduction and this impact was negligible.


SUBSEQUENT CALIFORNIA DEVELOPMENTS

During its installation of smart meters and communication system, PG&E decided that they had chosen the wrong communication system

PG&E has filed for change in technology at an additional cost of $600 million

SCE’s smart meter proposal now also approved by PUC

San Diego Power’s AMI proposal still pending

Southern California Gas has a smart meter proposal pending


CALIFORNIA PILOT RESULTS: ANALYSIS BY TURN

The pilot programs did not factor in the costs of the AMI and smart thermostats in analysis of bill impacts!

DR response by residential customers is closely aligned with appliance usage, climate, and demographic (income) factors

Almost 50% of residential customers have very low price elasticities (less than -0.10); half will make very little usage changes

YET all must pay for program; TURN found that 60% of customers who use less than 6,000 kWh annually would have to shift more than half their peak load to see bill savings when costs of AMI taken into account

TURN concluded that only a relatively small group of high usage residential customers can realistically shift sufficient peak load to find bill savings.

Several consultants have used the California pilot program results to create a model that is used to predict the demand response results of smart metering proposals in other states, measuring residential customer “elasticity of demand.”


ILLINOIS HOURLY PRICING PILOTS AND NEW PROGRAMS

Community Energy Cooperative operated an hourly price program with 1,500 residential ComEd customers in 2003-2006

Used day ahead price notifications (e-mail, website, phone) Compared to flat rates in effect at that time, most customers had

lower bills Usage reductions occurred during peak price hours (summer) No analysis of new metering or communication system costs

(used older technology) Illinois legislation requires utilities to offer “real time” or

hourly pricing to all residential customers ICC approved statewide voluntary hourly pricing programs for

residential customers in early 2007 with onset of auction-based default service prices (100,000-200,00 customers)

All customers will pay small fee for new programs and participating customers will pay $2.25/month

Analysis of costs and benefits will occur by 2008, but very low enrollment in 2007


WHAT ABOUT SMART GAS METERS?

PG&E and Southern California Edison in California are upgrading or replacing all its gas meters as part of its electric smart meter program

Most combined gas-electric utilities can document economies of scale in use of new communication system for both gas and electric meters

But what about stand alone gas utility AMI proposals?


Southern California Gas

SoCal Gas applied for a stand alone smart metering program in September 2008

$1.09 billion for 2009-2015 installation Approval sought without hearing on grounds that California

policy supports AMI Ratepayer Advocate: filed protest

NPV of benefits only slightly above costs, even accepting utility statements (2% return)

No demand response benefits for gas! No real time or critical peak pricing options

Gas can be stored; no significant differential between peak and off peak prices

Cannot justify stand alone communication system costs for gas metering alone

No evidence that gas customers will conserve based on access to “real time” pricing information of gas

Utilities failed to consider other least cost alternatives to achieve its identified benefits


Duke Energy

Duke Energy in Ohio is a combined gas/electric utility

Duke is proposing new gas modules as part of its electric smart grid initiative

Combined communication system Existing gas meters not replaced;

proposing to add on “modules” to enable the two-way communication at 1/3 cost of new electric meter


WHAT IS LIKELY TO HAPPEN WITH SMART METERS

While these time-based pricing options may be proposed initially as voluntary, there is every reason to suggest that mandatory time-based rates will be the next step Ontario: smart meters being installed for every

customer and Time of Use rates are now mandatory Pepco’s filings in DC, MD, and DE state that benefits

will be greatly increased if all customers are required to accept time-based rates or critical peak pricing

DC Commission has publicly asked if default service prices should reflect hourly or time-based prices for all customers

California Commission exploring mandatory time-based pricing for all customers


QUESTIONS THAT SHOULD BE CONFRONTED

Has anyone evaluated the impact of the new metering technology or the new volatile pricing systems on low income or low use customers? Any such analysis would show different results in different climates, pricing zones, and customer demographics. It is wrong to use the California data as “gospel.” E.g., very few residential customers in Maine have central

air conditioning systems Move to more volatile and “real time” pricing of

essential electric service Impact on lower use customers, particularly the

elderly, disabled, very young Impact on payment troubled customers Impact on structure of current low income bill

assistance programs: benefit levels and participation rate


SMART METERS: IMPLICATIONS FOR RATE DESIGN FOR ALL CUSTOMERS

Commissioner Rick Morgan (D.C. Public Service Commission): “There is no point in having smart meters if you’re still going to have dumb rates.”


SMART METERS AND REAL TIME PRICING PROMOTED AS NEXT STAGE OF RESTRUCTURING

“We can get rid of every bit of that [wholesale power price caps, regional capacity market auctions] tomorrow, if every state will allow the full floating price every five minutes to be reflected in the customer’s bill.”

Philip G. Harris, President of PJM Interconnection, interview in Public Utilities Fortnightly, October 2006, page 41.


HOW CAN T&D SHOW DEMAND RESPONSE BENEFITS IN RESTRUCTURING STATES?

Pepco in District of Columbia (also in MD, DE) recently filed a proposal to install advanced meters with two-way communication throughout its system at a cost of $60 M; analysis of costs and benefits shows that only half of costs recovered through operational savings; relies on demand response programs (for which Pepco is not responsible) to estimate benefits

Central Maine Power Co. in Maine recently filed for system-wide advanced metering with a 15-year NPV analysis showing a $108 M increase in revenue requirement with half recovered in “net operating benefits”, which requires that there is no net overall benefit to customers without heavy emphasis on demand response/real time pricing programs. Note: CMP has moved to withdraw its proposal, due in part to changing technologies AND lack of supplier interest in offering these pricing programs as part of Standard Offer Service to residential customers.



While utilities are great at figuring out the costs and seeking automatic cost recovery, questions remain about the estimated operational benefits claimed from these new systems No operational data from full scale deployment How to track benefits and assure that customers

“see” benefits in the form of lower rates What percentage of the proposed system relies on

demand response benefits to achieve the “cost effective” allegation? 10% 40% How can these benefits be assured in lower generation supply prices for states in which the utility does not own generation and purchases energy from the wholesale market?



Most new metering and communications technology allow disconnection or reconnection without premise visit with significant implications for customer contact and premise visit requirements in many state rules Elimination of attempt at personal contact Concerned about inability to detect medical

conditions; avoid disconnection at the door


KEY POLICY ISSUE: LINK TO DEFAULT SERVICE POLICIES

If we are trying to implement long term portfolio management for default service and avoid short-term volatility, how can we justify the use of expensive advanced metering and hourly pricing programs that are designed to offer very volatile wholesale market spot prices? ARE REGULATORS WILLING TO CHARGE 60 CENTS/KwH FOR ESSENTIAL ELECTRICITY SERVICE?

Isn’t this metering technology another “long term contract” for DR resources? If so, how can distribution utilities enter into such contracts without analysis of all cost effective options as part of Default Service portfolio?

Are the meter costs and DR programs the most cost effective way to lower electricity generation supply costs over the long term?

Aren’t we relying on immature and sometimes dysfunctional wholesale markets to price essential electricity service for residential customers? THE RELIANCE ON WHOLESALE SPOT MARKET PRICES RESULTS IN A “FEDERALIZATION” OF ELECTRICITY PRICES.


WHAT IS THE POINT?

If the intent to to assure long term lowest price for essential electricity service, we need to evaluate ALL the options for the energy supply portfolio: EE, DR, generation supply contracts of various terms, utility self-build, bilateral as well as wholesale market contracts

Peak load reduction is part of the portfolio What is the long term cheapest or most cost effective way

to achieve our objectives for the residential class? Viewed from this perspective, is a system wide “smart

meter” program the best approach? This is a long term contract and should be evaluated as

such, but utilities refuse such analysis Shouldn’t we compare EE and DR options to get

residential contribution to peak load reduction or reduction generally?

What is wrong with Direct Load Control?


DIRECT LOAD CONTROL MAY BE MORE COST EFFECTIVE

BG&E in Maryland has been approved to expand an older Direct Load Control program for residential customers with bill credits in return for “cycling” central air systems or heat pumps during critical peak hours in summer

BGE projects that average bill reduction for ALL residential customers will exceed costs within 2-3 years due to reduced costs associated with peak load purchases

Seeks to bid this program into PJM Capacity Market in 2008 and return savings to all retail customers


ARE THERE OPTIONS TO SYSTEM WIDE SMART METERS? CRITERIA FOR ACCEPTABLE DEMAND RESPONSE PROGRAMS

Voluntary Aimed at customers with options to shift usage: high

usage residential customers (central A/C); commercial and industrial

Rewards not penalties Focus on Incentive Programs targeted to specific

appliance interruptions (air conditioning) for short time periods and customer credits

Require modest investment in new communication and metering systems

Emphasize energy efficiency programs Support new building standards; mandatory appliance

efficiency standards


WHAT IS LEAST COST SOLUTION?

Least cost solution to higher electricity prices is robust portfolio of cost effective energy efficiency programs—reduce consumption

Dynamic pricing alone is not likely to result in reduced overall usage or allow customers to see lower annual bills [See recent article by Ahmad Faruqui of Brattle Group, key proponent of AMI, in August 2008 Public Utility Fortnightly]

Focus demand response on higher use customers Long run? Building design; appliance standards;

programmable thermostats Enough of paying utilities incentives and rewards

to encourage folks to go buy a $2 CFL at Home Depot!


WHAT CONSUMERS FEAR

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