Presentation on theme: "NARUC Summer Committee Meetings:"— Presentation transcript:
1 NARUC Summer Committee Meetings: Electricity and Energy Resources & the Environment CommitteesDOE’s EPACT Report to Congress on Demand Response in Electricity MarketsAugust 2, 2006Larry MansuetiOffice of Electricity Delivery & Energy ReliabilityU.S. Department of EnergyChuck GoldmanLawrence Berkeley National Laboratory
2 Grid Modernization – A Presidential Priority “…We have modern interstate grids for our phone lines and our highways. It's time for America to build a modern electricity grid.”President George W. BushApril 27, 2005…. And now also a priority of Congress due to the Energy Policy Act of 2005
3 EPACT Sec. 1252 Smart Metering [and much more!] Nine subsections on demand response, including:Utilities must offer time-based metering & communications;States must investigate DR & time-based metering;Federal assistance, guidance, and encouragement; and,Encourage regional coordination by states
4 U.S. Congress Demand Response Policy Statement Federal Encouragement of Demand Response“It is the policy of the United States that time-based pricing and other forms of demand response….shall be encouraged, the deployment of such technology and devices….shall be facilitated, and unnecessary barriers to demand response participation in energy, capacity and ancillary service markets shall be eliminated.”– Energy Policy Act of 2005, Sec. 1252(f)
5 DOE’s Informal Demand Response Program Goals Customer-friendly instead of engineer-friendlyPromote both wholesale level demand response and retail level demand responseArrest the continuing slide in legacy retail-level demand response program (regulatory incentives?)Demand response that includes “long-run demand response” (ie. energy efficiency)“Equivalent” treatment in regional and distribution-level planningBottom line: Ensure robust market-oriented demand response capability in U.S. electric markets
6 EPACT Sec. 1252(d) DOE Demand Response Report to Congress The Secretary [of Energy] shall be responsible for… not later than 180 days after the date of enactment of the Energy Policy Act of 2005, providing Congress with a report that  identifies and quantifies the national benefits of demand response and  makes a recommendation on achieving specific levels of such benefits by January 1, 2007.under “EPACT button”FERC also has Report to Congress, but annual report every August
7 DOE Feb 2006 Report to Congress on Nat’l Benefits of Demand Response Identified Demand Response Benefits:Participant financial benefits, market-wide benefits, reliability and market performance benefitsDOE reviewed 10 recent studies and concluded:Lack of standardized and accepted analytic methodsPreferable to quantify DR benefits at state/regional level (rather than nat’l) because tied directly to local system conditions and market structureMade Policy Recommendations in Six Areas:Fostering Price-based Demand ResponseImproving Incentive-based DR ProgramsStrengthening DR Analysis and ValuationIntegrating DR into Resource PlanningIncreased Adoption of Enabling TechnologiesEnhancing Federal Demand Response ActionsDR Benefits : improved resource-efficiency of electricity production due to closer alignment between customers’ electricity prices and the value they place on electricity. Benefits fall into four groups:· Participant financial benefits are bill savings and incentive payments earned by customers that adjust their demand in response to time-varying electricity rates or DR programs.· Market-wide financial benefits are the lower wholesale market prices that result because DR averts the need to use the most costly-to-run power plants during periods of high demand, driving production costs and prices down for all wholesale electricity purchasers. Over the longer term, sustained DR lowers aggregate system capacity requirements, allowing load-serving entities to purchase or build less new capacity.· Reliability benefits are the operational security and adequacy savings that result because DR lowers the likelihood and consequences of forced outages that impose financial costs and inconvenience on customers.· Market performance benefits refer to DR’s value in mitigating suppliers’ ability to exercise market power by raising power prices significantly above production costs.QUANTIFY DR BENEFITS – DOE reviewed 10 recent studiesand concluded that estimated benefits of DR are driven primarily by the analysis method, assumptions regarding customer participation and responsiveness, and market characteristics. Without accepted analytical methods, DOE finds that it is not meaningful to quantify the national benefits of demand response. Moreover, regional differences in market design, operation, and resource balance are important and must be taken into account. Estimates of DR benefits are best done at state/regional level because the magnitude of potential benefits is tied directly to local electric system conditions (e.g., the supply mix, the presence or absence of supply constraints, the rate of demand growth, and resource plans for meeting demand growth).
8 Demand Response Definitions Used: Two Categories of DR Price-based OptionsReal-Time Pricing (RTP)Critical Peak Pricing (CPP)Time-of-use (TOU) rateIncentive-based DR ProgramsDirect Load ControlInterruptible/curtailable serviceEmergency DR ProgramsCapacity Market ProgramsDemand Bidding/Buyback programsDemand response can be classified according to how load changes are brought about.· Price-based demand response refers to changes in usage by customers in response to changes in the prices they pay; include RTP, CPP and TOU rates. Customers’ load use modifications are entirely voluntary.· Incentive-based demand response programs are established by utilities, load-serving entities, or a regional grid operator. These programs give customers load-reduction incentives that are separate from, or additional to, their retail electricity rate. The load reductions are needed and requested either when the grid operator thinks reliability conditions are compromised or when prices are too high.Over the long term, the maximum benefits of demand response will come about as the entire range of demand response programs are made available to customers
9 Role of Demand Response in Electric Power Systems DR options include price-based DR (time-varying electricity tariffs) and incentive-based DR (programs that pay for load reductions)
10 Recommendation #1: Fostering Price-Based Demand Response Marginal cost of supplying electricity varies significantly; but nearly all customers face time-averaged, fixed retail ratesCustomers have little or no incentive to adjust their demand to supply-side conditions, which leads to inefficient use of resourcesPolicy Issues:What hard evidence is there that RTP or CPP delivers DR?Lack of advanced metering is major barrier to widespread implementationDo state PUCs have political will to aggressively promote price-based DR, given the risks of price volatility?Disconnect between short-term marginal electricity production costs and retail rates paid by consumers leads to an inefficient use of resources. Because customers don’t see the underlying short-term cost of supplying electricity, they have little or no incentive to adjust their demand to supply-side conditions.Thus, flat electricity prices encourage customers to over-consume in hours when actual electricity prices are higher than the average rates, and under-consume in hours when the cost of producing electricity is lower than average rates. As a result, electricity costs may be higher than they would otherwise be because high-cost generators must sometimes run to meet the non-price-responsive demands of consumers.What Evidence that RTP or CPP delivers DR?a) In voluntary tariffs, two essential elements to success:Customers must enrollAnd must respond “significantly” in aggregate
11 Optional RTP Tariffs: Overview RTP offered as Optional Tariff by more than 40 utilitiesPopular in Southeast, Midwest and Mid-AtlanticNot offered by many utilities in the West or New England1) Figure provides geographic overview of utilities in each state with RTP as Optional Tariff that were included in our survey – 43 distinct programs2) RTP is most popular in Southeast and TVA;also in Ill and NY because of regulatory requirements3) Not offered in the West or in New England
12 Customer Response to High Prices in RTP Programs RTP programs have reduced utility system peaks by ~1%, except for Georgia Power (5% of utility peak)Public Service of Oklahoma40 MWDuke Power200 MWCom EdJersey Central Power & Light60 MWFlorida Power & LightKansas City Power & LightOtter Tail PowerPacific Gas & Electric10 pgm managers provided information on max. load reduction when RTP prices were high –a) prices ranged from $030/kwh to $6.50/kWh (Ga Power)b) $0.45 at Pub. Service of Oklahoma;2) Agg. Load reductions are modest; <1% of utility system peak:- due to modest amount of load enrolled (<60 MW)- RTP prices relative low or most partiicpants not responsive3) Two essential elements to success:Customers must enrollAnd must respond “significantly” in aggregateGeorgia Power750 MWGulf Power23 MW0%1%2%3%4%5%6%Maximum Load Reduction(% of Utility's Peak)
13 RTP as Default Service: Customers Exposed to Spot Market Prices This figure shows the amount of load exposed to hourly spot market prices through the utility RTP rate and competitive supply contracts, in terms of the percentage of the system peak.The purpose is to give some sense of the potential market impact of RTP as part of default service.In these three cases, we estimated that between 4% and 8% of the total system load is exposed to hourly spot market prices.One of the challenges for FERC (and EIA) is to collect information from retail suppliers on the type and mix of contracts with customers so we have some idea how much load is exposed to hourly prices (vs. fixed prices)Customers face spot prices through default RTP and contracts with competitive retailersLarge C/I customers facing spot prices ranges from 4-8% of total system peak load
14 Recommendation #2: Improving Incentive-Based Demand Response Programs Trends in ISO DR programsIssues:Not all ISOs have integrated DR into their wholesale marketsRetail-level traditional load mgmt programs (direct load control and interruptible customers) need to be adapted to new market structures and circumstancesLoad Mgmt programs must be adapted to new market structures or circumstances, which involvesrethinking program design features related to triggering events (e.g., only system emergencies or other economic and emergency criteria),linking payments to actual performance, considering improvements or enhancements to control technologies, improving system communications,or enhancing monitoring/verification capabilities to allow LM programs to participate in various wholesale electricity markets (e.g., capacity, reserves).A key issue to address is the fact that with the proliferation of market actors (e.g. competitive retailers, “wires-only” utilities), no single entity has the incentive to pursue the full benefits of demand response.
15 ISO “Reliability-based” DR Programs: Enrollment is increasing
16 Emergency DR programs can be very cost-effective Cost-effectiveness driven by:number of eventscustomer response & program paymentsassumed value of lost load“supply curve” flexibility
17 Recommendation #5: Increased Adoption of Enabling Technologies Lack of interval metering is significant barrier to deployment of price-based demand response among residential and small C/I customersMany large C/I customers do not fully utilize capabilities of automated (EMCS and EIS) systems, advanced HVAC and lighting controlsEnabling technologies that automate load response provide opportunity to improve persistence of load impacts and increase number of customers willing to curtail loads
18 Average Critical Peak Day Load Response from Critical Peak Pricing and Enabling Technologies: Residential customersAverage Critical Peak Day0%10%20%30%40%50%Peak Load ReductionAEP 41991Gulf Power 3GPU 21997California SPP 12003/04Source:CA Statewide Pricing Pilot CRA 2005Residential TOU pilot study Braithwait 2000.Results of the Pilot Residential Advanced Energy Management System, Gulf Power, November 1994.Levy Associates case study report, July 1994.
19 Recommendation #3: Strengthening DR Analysis and Valuation Challenges in measuring DR ImpactsDirect Load Control impacts are reasonably well-characterized, but impacts from price-based DR depend on customer behaviors that are price- or incentive-drivenChallenges in estimating net benefits of DRCost reporting issues (participant costs)Value of DR not fully reflected in standard B/C testsReliability benefits valued differently by customersOther benefits difficult to quantifyBottom Line: More comprehensive evaluation framework needed to fully value benefits of DRDR Impacts – Challenge to using standard B/C tests is ability to characterize “savings” or load impacts and participation RATES ---- many types of DR, particularly price-based DR, depend on customer behaviors that are price-driven or incentive-driven. Contributes to uncertainties in estimating DR impacts over a multi-year periodCost Reporting – utilities/ISOs report program admin costs,including incentive payments – but rarely report costs incurred by participantsValue of DR –SPM tests use avoided costs to characterize benefits – limited ability to reflect value of capacity in critical peak hours and thus potential of DR to mitigate episodic high spot market prices is undervaluedReliability Benefits – research on customer’s outage costs suggests wide range in customer’s value of lost loadOTHER BENEFITS Some benefits, such as market power deterrence, risk mitigation and avoided pollutant emissions are difficult to quantify, but are presumed to be substantial Care must be taken to avoid double-counting benefits from other sourcesRECOMMENDATION A voluntary and coordinated effort should be undertaken to strengthen demand response analysis capabilities. This effort should include participation from regional entities, state regulatory authorities, electric utilities, trade associations, demand response equipment manufacturers and providers, customers, environmental and public interest groups, and technical experts. The goal should be to establish universally applicable methods and practices for quantifying the benefits of demand response.
20 Recommendation #4: Integrating DR into Resource Planning How much DR is needed for ensuring resource adequacy, given market structures and system conditions?Improve characterization of DR in Resource Planning ModelsOrganized Markets: ISO/RTO evaluations focus only on short-term impacts and benefits of DRMore effort needed to characterize long-term impacts and potential DR benefits, as part of ISO long-range planning studiesHow much DR is enough? A number of DR studies confirm that a little DR can go a long way towards improving the efficiency and operations of electricity markets, both in theory and practice.However, challenge is to identify optimal, or target, levels of DR in specific market settings. Initiatives should be launched at the appropriate market level (e.g. state or region) to establish relevant goals and appropriate targets for demand response. Need to address appropriate mix of different types of DR optionsImprove characterization of DR - DR modeled as generation resource (as an energy-limited resource); price-based DR needs to be characterized more accurately – change in demand in response to prices; not as resource dispatched to serve demand (doesn’t include reliability value of load impacts)In Organized Markets – More work needed to assess potential LT benefits of DR as part of long-range planning studies for coordinated system expansion plans that identify projects that can ensure system reliability, reduce congestion, and provide market signals for new investments in generation, transmission or demand-side – can provide info on future value of DR within their regional marketsRECOMMENDATIONFERC and state regulatory agencies should work with interested ISOs/RTOs, utilities, other market participants and customer groups to examine how much demand response is needed to improve the efficiency and reliability of their wholesale and retail markets.Resource planning initiatives should review existing demand response characterization methods and improve existing planning models to better incorporate different types of demand response as resource options.ISOs and RTOs, in conjunction with other stakeholders, should conduct studies to understand demand response benefits under foreseeable future circumstances as part of regional transmission planning and under current market conditions in their demand response performance studies.
21 Recommendation #6: Enhancing Federal Demand Response Actions Federal government can and should lead by example on DRDOE should continue to:provide technical assistance on DR to state and regional policymakers, utilities, and ISO/RTOscoordinate with FERC on DR activitiesthrough Federal Energy Mgt Program, investigate and evaluate costs/benefits of metering and continue DR audits at Federal facilitiesWork with EPA to explore efforts to include DR programs in Energy Star programs
22 Conclusions on EPACT Effect on DR Some may ask: “Is all this wishful thinking”; “what is going on..or is this just one more policy with no teeth?”EPACT is the most support for DR that will occur from Congress…don’t expect more (due to Federal Power Act)What happens next is up to states, regulators, the electric industry, and the supplier industry
24 Gross Demand Response Benefits: Normalized Results for 10 studies
25 Six Main Policy Recommendations Fostering Price-Based Demand ResponseImproving Incentive-Based Demand Response ProgramsStrengthening DR Analysis and ValuationIntegrating DR into Resource PlanningIncreased Adoption of Enabling TechnologiesEnhancing Federal Demand Response ActionsFollowing slides discuss issues behind each main recommendation. Note there are 24 sub-recommendations.
26 DOE DR Rpt to Congress Policy Recommendations Fostering Price-Based Demand ResponseIn accordance with EPACT, State regulatory authorities must decide whether their utilities must offer customers time-based rate schedules (i.e., RTP, CPP and TOU rates) and advanced metering and communications technology.Large CustomersIn states that allow retail competition, state regulatory authorities and electric utilities should consider adopting RTP as their default service option for large customers.In states that do not allow retail competition, state regulatory authorities and electric utilities should consider offering RTP to large customers as an optional service.Regional entities and collaborative processes, state regulatory authorities, and electric utilities should provide education, outreach, and technical assistance to customers to maximize the effectiveness of RTP tariffs.Medium and Small Business CustomersState regulatory authorities and electric utilities should investigate new strategies for segmenting medium and small business customers to identify relatively homogeneous sub-sectors that might make them better candidates for price-based demand response approaches.State regulatory authorities and electric utilities should consider conducting business case analysis of CPP for medium and small business customers. Results from existing pilot programs should be carefully evaluated and included in the analysis.State regulatory authorities and electric utilities should consider conducting policy or business case analysis of RTP for medium business customers. Results from existing pilot programs should be carefully evaluated and included in the analysis.Residential CustomersState regulatory authorities and electric utilities should consider conducting business case analysis of CPP for residential customers. Results from existing pilot programs should be carefully evaluated and included in the analysis.State regulatory authorities and electric utilities should investigate the cost-effectiveness of offering technical and/or financial assistance to small business & residential customers to enable their participation in CPP or TOU tariffs and enhance their abilities to reduce demand in response to higher prices.Improving Incentive-Based Demand ResponseTraditional load management (LM) programs such as direct load control of residential and small commercial equipment and appliances (e.g., ACs, water heaters, and pool pumps) with an established track record of providing cost-effective DR should be maintained/expanded.State regulatory authorities and electric utilities should consider offering existing and new participants in these LM programs “pay-for-performance” incentive designs, similar to those implemented by ISOs/RTOs and some utilities, which include a certain level of payment to customers who successfully reduce demand when called upon to do so during events.Regional entities, state regulatory authorities, and electric utilities should consider including these emergency DR program features:Payments that are linked to the higher of real-time market prices or an administratively-determined floor payment that exceeds customers’ transaction costs;“Pay-for-performance” approaches that include methods to measure and verify demand reductions;Low entry barriers for DR providers, and in vertically integrated systems, procedures to ensure that customers have access to these programs; &Multi-year commitments from regional entities for emergency DR programs so that customers and aggregators can make decisions about committing time and resources.State regulatory authorities should investigate whether it would be cost-effective for default service providers to implement demand response. They should also provide cost recovery for DR investments undertaken by distribution utilities.
27 DOE DR Rpt to Congress Policy Recommendations (cont) Strengthening Demand Response Analysis and ValuationA voluntary and coordinated effort should be undertaken to strengthen demand response analysis capabilities. This effort should include participation from regional entities, state regulatory authorities, electric utilities, trade associations, demand response equipment manufacturers and providers, customers, environmental and public interest groups, and technical experts. The goal should be to establish universally applicable methods and practices for quantifying the benefits of demand response.Integrating Demand Response into Resource PlanningFERC and state regulatory agencies should work with interested ISOs/RTOs, utilities, other market participants and customer groups to examine how much demand response is needed to improve the efficiency and reliability of their wholesale and retail markets.Resource planning initiatives should review existing demand response characterization methods and improve existing planning models to better incorporate different types of demand response as resource options.ISOs and RTOs, in conjunction with other stakeholders, should conduct studies to understand demand response benefits under foreseeable future circumstances as part of regional transmission planning and under current market conditions in their demand response performance studies.Adopting Enabling TechnologiesState regulatory authorities and electric utilities should assure that utility consideration of advanced metering systems includes evaluation of their ability to support price-based and reliability-driven demand response, and that the business case analysis includes the potential impacts and benefits of expanded demand response along with the operational benefits to utilities.State regulatory authorities and electric utilities should evaluate enabling technologies that can enhance the attractiveness and effectiveness of demand response to customers and/or electric utilities, particularly when they can be deployed to leverage advanced metering, communications, and control technologies for maximum value and impact.State legislatures should consider adopting new codes and standards that do not discourage deployment of cost-effective demand response and enabling technologies in new residential and commercial buildings and multi-building complexes.Enhancing Federal ActionsDOE, to the extent annual appropriations allow, should continue to provide technical assistance on demand response to states, regions, electric utilities, and the public including activities with stakeholders to enhance information exchange so that lessons learned, best practices, new technologies, barriers, and ways to mitigate the barriers can be identified and discussed.DOE and FERC should continue to coordinate their respective demand response and related activities.FERC should continue to encourage demand response in the wholesale markets it oversees.DOE, through its Federal Energy Management Program, should explore the possibility of conducting demand response audits at Federal facilities.DOE and the Environmental Protection Agency should explore efforts to include appropriate demand response programs and pricing approaches, where appropriate, in the ENERGY STAR® and other voluntary programs.
28 Niagara Mohawk: Barriers to RTP What Customers Told Us Load Response StrategiesBarriers to Price Response (N=76)FrequencyNo barriers encountered9Organization/ Business PracticesInsufficient time to pay attention to prices39Institutional barriers23Inflexible labor schedule16Inadequate incentivesElectricity is not a priority17Cost/inconvenience outweighs savingsRisk averse/ hedgedManagement views price response as too risky10Flat rate or time-of-use contract makesresponding unimportantSurvey results from our evaluation of RTP at Niagara Mohawk,Utility in Upstate NY.Half the customers in our sample responded to written survey;Most customers report multiple barriers to responding to hourly prices –Most common barrier, reported by 50% is lack of time to monitor hourly prices –We also asked customer how frequently they monitor theirPrices --70% of NMPC customers report never or rarely checking day-ahead hourly prices17% consult prices regularly13% check only when other signals (NYISO DR program events or hot weather) suggest prices will be highMost customers report multiple barriers to price response;~15% respond without obstacles
29 ISO “Economic” DR Programs: Enrollment Increasing - Performance Lags Subscribed load increasing, particularly in PJMHowever, scheduled load curtailments are typically low:~10-15 MW peak (NYISO day-ahead market and PJM real-time market)
30 ISO DR Program Costs and Payments Cumulative Payments made to participants by 3 ISOs ( ):- Emergency DR Pgm: $18.1 M- Economic DR Pgms: $5 M
31 Mid-Atlantic Distributed Resource Initiative (MADRI) Developing Regional Policies & Market-Enabling Activities toSupport Distributed Generation and Demand ResponseGoal: Improve the effectiveness of deployment of distributed resources (distributed generation, demand response, energy efficiency) in the Mid-Atlantic region to improve electric reliability and reduce costs….driven by the state commissionsObjectives:Educate stakeholders (especially state officials) on opportunities, barriers, and solutionsPursue consensus on preferred solutionsA stakeholder process with open meetings held every 5-6 weeks, with working groups meeting more oftenFocuses on Mid-Atlantic region/“Classic PJM” with input from neighboring statesEstablished in June 2004 by State PUC Commissioners, U.S. DOE, U.S. EPA, and PJM InterconnectionBuilding on the success of the New England Demand Response Initiative (NEDRI)Web site:
32 Int’l Energy Agency Demand Response Resources Project U.S. is part of this project, DOE is country rep with FERC and DRCC as “country experts”Demand Response Coordinating Committee (DRCC) formed to coalesce US industryPurpose:Review current demand response practices in each project member countriesDevelop tools and recommendations for better integrating DR into member country’s electricity markets
33 IEA DRR Project Subtasks1 Market Characterization - of demand response products, services and enabling technologiesMarket Potential of DRR - methods for assessing the available DR market potential in a given marketDRR Valuation - methods and procedures required to establish the value of DR and to administer them in each country to create a valuation framework to guide development initiativesRole and Value of Technologies - catalogue that describes the technologies and systems available for use in DR programs both from perspective of system operator and participating customerMarket Barriers, DR Solutions and Recommendations - Identify current DR products and market barriers. Develop recommendations for DR implementations.Communications & Workshops - web portal and country workshops on DRR methods, technologies, and applicationsImplementation - delivery of intellectual property created in the DRR Project to the IEA DSM Programme and the participating countries1Green and red text indicate project deliverables that can help a state or utility determine DR market potential or value.