DR Strategic Assessment: A DISCO Perspective

1
DR Strategic Assessment A DISCO Perspective

• Presented at
• Peak Load Management Alliance
• -- Spring Meetings --
• Arlington, VA
• By
• Daniel M Violette, Ph.D.
• Summit Blue Consulting, LLC
• e-mail dviolette_at_summitblue.com
• March 18, 2003

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Review of DR Programs

• 60 programs offered by 30 entities
• CI customers are primary targets
• Programs have become highly automated
• Internet-based communications systems
• Near-real time performance tracking
• Reduced settlement times
• Most programs are voluntary
• Increased customer choice and operational
  flexibility
• Some utilities/DISCOs act as CSPs or enablers of
  ISO programs

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Claimed Benefits of DR

• Enhanced market efficiency
• Reduced market prices
• Increased system reliability
• T D system investments
• Generation system investments
• Mitigate market power
• Additional incentives for innovation
• Enhanced risk management options
• Increased customer choice

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Disco Perspective

• Benefits to the market might be significant
• However, benefits to distribution companies from
  promoting DR are likely to be considerably
  smaller.
• A sizeable gap may exist between benefits that
  accrue to all consumers in regional electricity
  markets and benefits that accrue to a
  distribution company.
• This poses challenges to regulators that may want
  to see an optimal level of DR in electricity
  markets.
• Regulatory options
• 1. Promote competitive curtailment service
  provider industry
• 2. Look to existing players with customer
  relationships to provide DR
• 3. Try to consolidate benefits (e.g. commodity
  and distribution)

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Distribution Company Benefits from Targeted DR

• Increase system planning options
• Hedge against questionable forecasts
• Extreme weather events
• Unforeseen load growth
• Rapid development
• Mitigate TD system constraints
• Increase substation transfer capability
• Assist during contingency/emergency events
• Manage demand

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Distribution Company Benefits from Targeted DR
(cont.)

• Asset Management
• Defer or eliminate capital expenditures
• Extend usable life
• Manage equipment loads
• Prevent catastrophic loss
• Reduce repair, overtime, and loss of revenue
  liability

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Distribution CompanyDR Program Costs

• Staff time (development, marketing,
  implementation)
• Software systems
• Physical infrastructure
• Incentive payments
• Financial assistance to participants
• Revenue differentials due to rate impacts

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DRs Potential Impact on Demand Charges
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Program Categories

• One-year possibilities to defer substation
  investments
• Aggregate existing backup generation in targeted
  areas
• Must be call option with appropriate operational
  provisions.
• Two-year possibilities with incorporation into
  system planning
• Mass market DLC programs.
• Large CI programs based on call options.
• Key provisions needed for distribution planning
• A specified commitment for time and MW is needed.
• Meeting curtailment obligations are mandatory
  with penalties.
• Other pricing programs promote market efficiency,
  but may not be helpful in planning for system
  emergencies at specific locations.

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Innovative Strategies

• Seek out synergies between energy efficiency and
  DR
• Combine with new construction programs where
  switches and thermostats that can support DR are
  installed.
• Add DR options to audit software and include in
  recommendations.
• Visits to sites can include installation of DR
  equipment to make sites DR ready.
• Seek leverage by aggregating existing back-up
  generation into a dispatchable or call-option
  program.
• Look for winter curtailable load through Electric
  Thermal Storage (ETS) and Hot Water (HW) Controls.

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Call Provisions Needed

• Provisions needed to defer substation investments
  are
• Beat target per kW based on equipment
  replacement.
• Provide for curtailments spanning a two-week
  period (but not continuous over the two weeks)
• Daily load reduction requirements might be 8
  hours per day.
• Loads will be called only when equipment outages
  occur AND there is extreme weather -- this makes
  actual called load reductions a low probability
  event.
• DR programs avoid low-probability, but
  high-consequence events at substations.

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DR Programs

• One year out
• Aggregating existing backup generation seems to
  be only one-year out option.
• Need to see where back-up generation currently
  exists and assess any operational constraints.
• Two years and beyond
• Mass market DLC
• Call options program for large CI
• These programs will also allow DISCO to be an
  aggregator in ISO programs.

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Some Pros and Cons

• Mass-market loads at highest availability when
  weather is extreme.
• Selection of mass-market technology may be
  overcome by pricing decisions requiring
  alternative technology.
• CI loads not so weather dependent.
• CI may require longer notification periods and
  are unlikely to be recognized as 30-minute
  reserves by the ISO.
• Revenues dependent upon ISO allowing DISCO
  programs to serve dual purposes.
• Both programs can be put on hold or ramped up
  over time.
• Participation and MW availability tends to be
  more stable in mass-market programs.

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Assessment Framework

• Key Question How to assess whether an
  investment in demand response is appropriate?
• Approach to be taken
• 1. Develop scenarios going forward 5 years. Each
  is termed a View of the World (VOW).
• 2. Market Play -- Define a set of specific
  actions for DR investment and the implications
  for other investments (e.g., deferred
  distribution system expenses). Each set of
  actions is a market play.
• 3. Determine the financial outcome for each
  market play set in context for each VOW. 5 VOWs
  and 5 market plays results in 25 outcomes.
• 4. Probabilities are assigned to VOWs which
  represent the key planning uncertainties.
• 5. The costs of market plays are viewed as
  certain, but the benefits vary by market forces
  as defined in the VOWs.
• 6. Option values are addressed in terms of
  flexibility across VOWs, and over time. A penalty
  function will be developed that assesses the
  penalties associated picking one market play when
  another is actually best.

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Example attributes of a VOW

• 1. Demand Growth -- High, Medium and Low.
• 2. Electricity Price Increases -- High, Medium
  and Low.
• May depend upon natural gas and oil prices, and
  be related to demand growth and generation
  capacity.
• 3. Electric Price Volatility -- High, Medium and
  Low.
• Depends on generator performance and input costs,
  e.g., natural gas.
• 4. ISO policies concerning likelihood of
  receiving revenues from DR programs that serve
  dual purposes, i.e, distribution company needs
  and be available to the ISO for market
  reliability.
• 5. Regulatory environment -- Will regulators
  encourage distribution companies to promote DR
  that serves dual purposes via rates or
  incentives? Depends upon perceived market-wide
  benefits.
• 6. Market environment
• Will LSEs pay for commodity price risk protection
  via DR?
• Will there be competitive curtailment service
  providers (CSPs) that serve the market function?
• Will outsourced DR become an industry convention
  (e.g., the purchase of a Texas LM program by
  Comverge)?

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Go/No Go Scenario Analysis

• Conditions favoring DISCO DR initiatives
• Escalating or volatile energy prices
• Dearth of new or available generation
• Uncertainty in capital markets
• Price caps imposed (could go either way)
• Rapid growth in electric demand
• Wide availability of advanced metering technology
• Conditions hindering DISCO DR initiatives
• Supply/generation technology breakthroughs
• Low cost of capital for plant additions
• Stable or low growth in electric demand at
  distribution system pinch points.
• status quo regulatory posture (e.g. no
  innovative rates, etc.)

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Go/No Go Scenario Analysis

• Environmental permitting considerations
• Contractual obligations and revenue impacts to
  generation suppliers
• Structure of ISO DR programs and potential
  interactions with DISCO programs
• Local customer profiles and characteristics

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Decision Tree Analysis Example
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Framework Questions

• 1. Determine if the specific DR program types to
  be examined for 2003 application and for 2004 and
  beyond are appropriate.
• 2003 limited to aggregation of existing backup
  generation.
• 2004 considers a mass-market program and a large
  CI call option program.
• 2. Are the implications for distribution system
  benefits/costs adequately addressed?
• Focus is on substation costs, but are there other
  considerations?
• 3. Are the upside and downside risks associated
  with different levels and types of commitments to
  DR addressed appropriately by the proposed
  framework?
• Will be addressed through the selection of the
  VOWs.
• 4. What factors should drive the VOW scenarios
  used in the assessment
• Demand growth
• Forward prices (levels and volatility)
• ISO policies and programs
• Regulatory treatment of DR costs
• Market environment -- CSPs, LSEs, default supply,
  risk management, etc.

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Framework Questions (cont.)

• 5. What factors are pivots for the desirability
  of DR from a DISCO perspective?
• Are there go/no-go factors that can be
  identified?
• 6. What will make the results of this study
  actionable?
• Can DR be incorporated into distribution system
  planning (e.g., by this April)?
• What is needed to make DR relevant for planning?
• 7. What information is needed to support
  increased (or decreased) involvement in DR by the
  DISCO?