FERC Demand-Side Roadmap by AQsSl25P

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									           Demand Response:
        Turning Theory into Reality
     (“This is not your father’s DSM”)
                  NECPUC Annual Symposium
                              June 18, 2002
                            Richard Cowart

                            The Regulatory Assistance Project
50 State Street, Suite 3
Montpelier, Vermont 05602
                                              email: rapcowart@aol.com
Tel: 802.223.8199
Fax: 802.223.8172
                                              web: www.raponline.org
Old Lessons…New twist
       • Productivity and
         environmental quality--
         still count
       • Market barriers and
         failures -- still real
       • Demand-side potential
         remains very large
       • New markets - new
         challenges and
         opportunities
Electric Restructuring
      Year 2000
               Electricity:
             Market Lessons
• Early market problems: price volatility,
  price spikes, reliability challenges,
  generator market power
• “Plain vanilla” pricing ignores reality
• Physical reality: electricity has
  distinctive time and location values
• Policy responses: cost-causers should
  pay; those providing high-value benefits
  should be rewarded
State of Energy -- 2002
          Wholesale barriers to
           demand response
• Supply-only bidding
• Load profiling by pools and RTOs
• Reliability rules and practices excluding
  demand-side resources
• Historic subsidies for wires and turbines
• Transmission pricing and expansion
  policies can undercut low-cost demand-
  side resources
                 Retail barriers to
                demand response
• Averaged rates and default service plans
  block price signals, slow innovation
• Disco rate designs promote throughput
• Uniform buy-back rates don’t include
  premium for avoided distribution costs
• Utility as gatekeeper vs. utility as facilitator
  – Can customers or their agents sell directly
    into wholesale markets?
• Metering traditions, costs and standards
           New England Demand
            Response Initiative
• Goal: balanced energy markets
• Breadth: Remove market and policy barriers
  to all customer-based resources: load response,
  energy efficiency, and distributed generation
• Depth: Propose coordinated policies and
  programs for wholesale, wires, and retail
• Facilitated stakeholder process
  – ISO-NE, 6 state PUCs, DOE , EPA, state air
    directors, market participants and advocates
• New England can lead
         Demand Response:
        Five substantive areas
• (A) Price-response in wholesale markets
• (B) Reliability programs: ancillary
  services, emergency curtailments
• (C) Retail pricing, advanced metering
• (D) Long-term Demand Response:
  Embedded energy efficiency
• (E) Transmission -- congestion relief,
  prices, and expansion plans
                                The Market Value of Price-
                      100
                                    Responsive Load

                       80
                                              Price-
 BID PRICES ($/MWh)




                                              Responsive
                                              Demand
                       60                     Bid
                                                                 Inelastic
                                                                 Demand
                       40



                       20                     Supply
                                              Bid


                        0
                            0     5   10    15         20   25   30          35   40

2016
                                           ENERGY AMOUNT (GW)
        Demand Response (A)
       Wholesale market features

• Demand-side bidding
    • Price-sensitive load bids reveal a real demand
      curve
• Multi-settlements markets
    • Day-ahead settlement permits economic
      resales of planned load reductions
• Demand release resales
    • Resales into short-term markets will moderate
      price spikes and generator market power
                      Actual Performance of PRL
                       Programs: Summer 2001
      500
                  Subscribed Load
      400         Actual Average Curtailed Load


      300
MW




      200

      100

        0
                                           NewEnergy




                                                                          DomInion
            Class 2




                               Economic




                                                                    BPA




                                                                                                   PGE
            ISO-NE




                                                                                      PacifiCorp
                      DADRP




                                                       BG&E LRP
                               PJM ISO
             LRP –




                                                       – Option 1
                       NYISO




                                                                           Virginia
                                                                            ELCP
                                LRP –



                                             AES




     • Several programs successfully enrolled ~300-400 MW
     • Most PRL programs achieved modest actual reductions
       (Average = 19 MW)
          Demand Response (B) Reliability
                  Resources

• Retail Loads Should Be Able to
  Participate in All Wholesale Markets
• Day-ahead ancillary services
                                     Loads should
   – Spinning reserves
                                     be able to set
   – Nonspinning reserves
                                     prices, not
   – Replacement reserves
                                     just be price
• Real-time (intrahour) energy and   takers!
• congestion management
• Emergency load interruptions
                                      Can Demand Participate in More
                                        Valuable Reserve Markets?
                               5
                                                                         Spin = $3.0/MW-hr
                                                                         Nonspin = $2.0/MW-hr
 NY RESERVE PRICES ($/MW-hr)




                               4                                         Replacement = $0.9/MW-hr




                               3




                               2




                               1




                               0
                                   Apr-00   Jul-00   Oct-00   Jan-01   Apr-01    Jul-01      Oct-01
NYISOASPrices
          Demand Response (B)
          Reliability: Challenges
• Wholesale policy needs:
     • Needed: neutral terms for bidding reserves
     • Can system operators rely on sampling, avoid
       expensive metering on dispersed DR assets?
• Retail policy issues:
     • Can end-users and their agents provide
       ancillary services, or just utilities/LSEs?
     • How to lessen burdensome interconnection
       rules and standby charges?
     • How to coordinate RTO-level and utility-run
       programs?
          Demand Response (C)
          Retail tariffs and meters
• State policy dilemma:
     • Most customers want uniform retail rates; but
     • TOU and market-based rates are needed to
       improve price response in the wholesale market
• “Push-Pull” on Real Time Pricing
  – Market reformers: “show them the price”
  – Consumer advocates: “the ENRON price?”
• Good news - there are lots of options:
  – Flat -- Block -- TOU -- RTP
  – California 20/20 ; Puget TOU program
           Tariffs and metering
          Challenges and options
• How can states add TOU prices or price
  response options to franchise tariffs and default
  service plans?
• Flat, averaged, or deaveraged distribution rates?
• Should standard offer prices track the market?
  How closely?
• Mandatory TOU or RTP rates for C & I?
• Mass deploy advanced metering? Mandatory or
  optional? Who owns the meter and its data?
                                               Demand Response (D)
                                                Long-term Efficiency
                                      Combined Commercial Cooling and Lighting Loadshape
                                   Baseline and Load Management Compared to Energy Efficiency
                        4.50

                        4.00

                        3.50
Watts per Square Foot




                        3.00

                        2.50                                                                               Load Management
                                                                                                           Baseline
                        2.00                                                                               Efficient

                        1.50

                        1.00

                        0.50

                        0.00
                               1   2   3   4   5   6   7 8   9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
                                                                    Hour
Impact of California DSM
Programs and Standards
       (D) Investing in Efficiency:
        Options and challenges
• Can states reform Disco ratemaking to
  eliminate the throughput incentive?
• Financing efficiency: wires charges and other
• Can NE adopt regional codes and standards?
• Should the ISO permit “regional reliability
  charges” to support cost-effective regional
  efficiency programs?
• Can the regional value of long-term EE be
  revealed in ICAP markets?
        Demand Response (E):
         Transmission Policy
• Thinking twice about congestion:
  LMP reveals value of DR, EE, DG in
  load pockets
• The rolled-in facilities problem:
  – generators indifferent to costly
    locations
  – undermines load center resources
• Transmission planning:
  – Transmission AND its alternatives
The geography of congestion




 Load Densities - Southern New England
               The Challenge of
            Transmission Planning

• FERC: RTO has Transmission planning
  responsibility
• NTGS: “Regional planning processes must consider
  transmission and non-transmission alternatives when
  trying to eliminate bottlenecks.”
• Challenges: (a) integrated analysis in a de-
  integrated industry (b) transmission
  system is regional, but siting decisions
  and transmission alternatives are local
• How can the ISOs weigh alternatives?
        Transmission expansion-
          Demand-side issues
• Efficient Reliability Decision Rule -
  – A least cost “hard look” at proposed socialized
    costs
• “Open Season” for transmission
  upgrades and their alternatives
  – Expose proposed grid enhancements to
    marketplace alternatives
• State transmission siting rules
  – Recognize regional needs , but
  – Consider demand-side options in determining
    what those needs really are
             For more information

• New England Demand Response Initiative
   – web links at www.raponline.org and
     www.raabassociates.org
• “Efficient Reliability: The Critical Role of Demand-
  Side Resources in Power Systems and Markets”
  (NARUC June 2001)
• “Demand-Side Resources and Regional Power
  Markets: A Roadmap for FERC”
  (RTO Futures, January 2002)
• papers posted at www.raponline.org

								
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