Dealing with Free Markets and Demand Response

1
Dealing with Free Markets and Demand Response

• PLMA Fall Conference
• September 29, 2004
• William P. McNeil
• Director Regulatory Strategy

2
Background on Illinois Restructuring

• General Assembly passed Electric Service
  Customer Choice and Rate Relief Law of 1997
• Adopted a phase-in approach to customer choice
  (from large to small) beginning on 10/1/99
  through 5/1/02
• For largest utilities, residential rates were
  reduced 20 from their 1997 levels (15 on 8/1/98
  and 5 on 5/1/02)
• Base rates were frozen (other than for rate cuts)
  at their 1996 levels through a mandatory
  transition period, which goes through 2006
• Utilities were allowed to collect transition
  charges (CTCs) from shopping customers through
  2006

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The IDC Model

• The Illinois law permitted utilities to compete
  for customers (and pre-qualified them as RESs)
  both within their service territories and
  anywhere else in the State
• In 1998, the Commission opened a rulemaking
  proceeding to establish Codes of Conduct
  providing competitive safeguards (i.e.
  separation) between a utilitys merchant
  functions and its delivery functions
• One of the models proposed by the ComEd was
  called the Integrated Distribution Company model,
  or IDC.
• Under this model, if a utility agreed to strict
  limitations on its ability to market its
  generation services in any way, it would receive
  a waiver from the functional separation rules.
• All of the Illinois utilities are currently
  operating under this approved model

4
Competitive Service Declarations

• The Illinois Restructuring Act contains a
  provision allowing utilities to petition the ICC
  to declare a specific service Competitive
• The utility must show that there are competitive
  suppliers of the service, and that customers can
  reasonably obtain the service from the market,
  and if fact, the utility has already lost
  significant market share of that service
• If the Commission approves the petition, the
  utilities obligation to offer the service under a
  tariff (cost based) expires after 3 years
• ComEd has successfully petitioned the ICC to
  declare bundled electric service for customers
  over 3 MW competitive

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Current update on retail competition (for ComEd)
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ComEd has built a significant DR portfolio
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Current stakeholder process for post 2006

• The Commission sponsored a statewide stakeholder
  workshop process which kicked off on April 29th,
  and concluded early September.
• A variety of issues regarding the regulatory
  framework for post 2006 were examined and
  debated. Five separate workshops were conducted
  (meeting weekly or bi-weekly through the summer).
  Focus areas included
• Power Procurement Utility Service Obligations
• Rate Design Energy Assistance
• Competition
• Demand Response was identified early in the
  process (by Commission staff) as an important
  element of the post 2006 framework. This has
  been reinforced by the Lt. Governors Task Force
  and public positions of the ICC

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Questions raised in Workshop process

• Should incentives be put in place to encourage
  consumers to make their demands more
  price-responsive?
• What form might such incentives take?
• How should costs related to energy efficiency and
  demand reduction be charged in rates?
• Should there be an interruptible rate option for
  transmission and distribution services and/or
  generation services? How should such a rate be
  designed?
• Should existing real-time tariffs be modified to
  encourage customer interest in such tariffs? If
  so, what modifications are necessary?
• Which types of time-based rates, ranging from TOU
  to Critical Peak Pricing to Day Ahead Real Time,
  are appropriate for which customer classes? What
  has customer acceptance of such been in Illinois
  and other states to date?
• To what extent is existing infrastructure a
  barrier to wider deployment of time-based rates?
  

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Procurement models being considered
Full Requirements Procurement
Portfolio Manager Approach

• Utility procures full requirements in single
  process
• Suppliers carry risk of matching load variances
  (serve a percentage of the load shape)
• Cost of risk made part of competitive process and
  incorporated in rates
• Risk management in the hands of those willing to
  hold it

• A regulatory process decides what products,
  resources or fuel types are to be purchased
• Utility procures products to best fit expected
  load according to plan
• Actual load will be greater than or less than
  procured power in every hour
• The volume risk is increased by the option for
  customers to switch (especially if contracts are
  long term)
• A regulatory process determines prudence (after
  the fact)

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General approach to defining DR strategy

• Step 1 Interview internal stakeholders
• Structure the interviews
• Make sure to cast a wide net
• Close the loop
• Step 2 Create strategic alternative scenarios
• Make sure that all of the beliefs are embedded
  in at least one of the scenarios
• Using the two extremes can be a good approach
• Step 3 Small teams fully develop the case for
  each alternative
• Must agree on common evaluation criteria
• Each team needs a champion
• Step 4 Choose the best alternative and develop
  rationale
• Take to Senior Management
• Internalize with key managers of affected areas

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What we asked in the interviews

• Questions
• How should we value demand response? What are
  the appropriate metrics (time horizon)? Is there
  a value attributable to the wires? What risks
  are there for ComEd to offer / not offer DR?
• What is the business case? How should it be
  funded? Are there non-economic factors? What
  regulatory support is needed?
• What should ComEds role be? Is it OK if we let
  the current portfolio expire?
• What overlap do you see with any other
  strategies? What involvement do you want to have
  in this strategy?

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What we learned from the interviews

• There are very diverse views across an important
  management level of the company -- Some opinions
  were strong
• Views ranged from if customers want it, they can
  get it from PJM to its the right and
  appropriate thing for ComEd to do
• Economics were the major concern. Many existing
  programs do not fund themselves
• All recognized some non-economic value and the
  external support for certain DR programs

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Strategic Option 1 Grow the Business

• The first option analyzed was to not only
  maintain the entire current portfolio
  (economically rationalized), but to set up a
  stand-alone group focused on growing DR as an
  attractive business within ComEd.
• Key considerations include
• Can a business case be made which would pass
  internal thresholds?
• Is it consistent with ComEds business model?
• How would it fit with the expected procurement
  model?
• What risks would ComEd assume?
• Impact / Affect on retail market development?

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Strategic Option 2 Full Exit

• The second option considered was the other
  extreme Full Exit. Under this option ComEd
  would simply eliminate all existing tariffs and
  walk away from all programs at the end of 2006.
• Key considerations include
• Potential loss of gt 1,000 MW of DR
• Inconsistent with State and regulatory policy
  goals
• Reaction of important stakeholders in the post
  2006 debate
• Customer satisfaction / reaction
• Loss of any benefit to the wires

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Strategic Option 3 Transition / Partial Exit

• This represents the middle ground. The option is
  defined as maintaining a presence in DR which is
  acceptable to customers, regulators, and policy
  makers while minimizing risks and costs to ComEd
  and allowing for transition to a markets approach
  over time.
• Key considerations include
• Aligning customer incentives with PJM markets
• Integration with procurement methodology
• Cost recovery, if programs dont self fund
• Transition plan for phasing out legacy programs
• How to facilitate or stimulate development of
  competitive DR markets

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Where did we land?
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How ComEds programs will fit within the PJM
framework
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Final Recommendations

• Update DR portfolio to better fit post 2006
  environment
• Continue current transition toward DR programs
  that are economically viable within PJM
  framework.
• Eliminate legacy programs which no longer make
  sense (Riders 26, 27, 30, 32)
• Maintain DR programs important to key
  stakeholders (e.g. Nature First, Residential real
  time pricing).
• Let the DR markets develop over the next 2-3
  years
• Watch for emergence of Curtailment Service
  Providers (CSP).
• Evaluate changes, and continue in the stakeholder
  process for in PJM DR framework.
• Actively pursue recognition of long-term capacity
  value of DR at PJM.
• Track evolving customer interest and
  participation in DR.
• Reevaluate DR involvement in 2008
• Assess new economics driven by evolving PJM
  programs, wholesale markets, and enabling
  technologies.
• Look for right timing / opportunity to exit
  involvement in competitive retail market segments
  once alternative providers have fully developed
  capabilities