Transcript TRENDS IN NATURAL GAS AND ELECTRICITY PRICES IN THE …

Least Cost Plan
& Electric Restructuring
Grace Hu
Chief Economist
District of Columbia Public Service
Commission
Thimpu, Bhutan
October 7, 2002
The Public Service Commission
The Public Service Commission of the
District of Columbia was established
by Congress in 1913 as an independent
District Government agency to
regulate the electric, gas and
telephone companies in the District.
Check www.dcpsc.org for more infor.
Type of Proceedings
• (1) Formal Litigation
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(a) Company’s Application
(b) Notice of Intervention
(c) Pre-hearing conference
(d) Order designates issues based on pre-hearing
conference
(e) Company’s Direct Testimony
(f) Intervener's Direct Testimony
(g) Rebuttal Testimony
(h) Pre-hearing briefs
(i) Post-hearing briefs
(j) Commission Order
Type of Proceedings (Cont.)
• Rate case needs to be finished in 9 months.
Both PSC hearings and community hearings
were conducted.
• (2) Paper Proceedings
– Comments
– Reply Comments
– Commission Order
Type of Cases on the Energy Side
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(1) Rate Case
(2) Least Cost Plan Case
(3) Industry Restructuring Case
(4) Merger Case
(5) Tariff Update
Conserve kWh
PEPCO’s Least Cost Plan
• Purpose of the Plan
– An integrated least-cost resource planning strategy
requires the utility to consider all feasible demandside options for implementation in this jurisdiction,
to weigh these options against supply-side options
and to develop a plan which contains the most costeffective strategies for the utility and its customers.
– The Plan considers possibilities of conserving
energy, generating and transmitting power, cutting
costs, serving customers and protecting the
environment. This long-term plan will meet
customers’ growing needs at the lowest costs.
– See Appendix 1, pages 1-11.
Reserve Margin Analysis
• Compute your reserve margin by taking the
difference between the installed capacity and
the net peak demand (gross demand minus
impact of Demand-Side Management
Programs)
• D.C. Commission used to require a 16%
reserve margin
• Regional reserve margin (22%) may be
different from state’s (16% in the case of D.C.)
• See Appendix I, Page 12
System Planning Model
• Based on linear and mixed integer liner
programming techniques.
• Model identifies least cost plan additions.
• Least cost expansion plan is entered into the
linear programming model to determine
marginal capacity and energy costs.
• Objective function: Minimize over the planning
horizon the discounted present value of
incremental capital costs and operating costs of
existing and new generating units.
• See Appendix 1, Page 46.
SPM model (Cont.)
• Constraints include system constraints
and plant or unit constraints
• The sum of all new plus existing plant
capacity must meet or exceed
forecasted peak demand by 16%
(minimum reserve margin)
Planned Investment Approach
• 1. Used to calculate marginal transmission,
marginal subtransmission, marginal
distribution and marginal customers costs
• 2. This approach is not a mathematical or
economic model but a considerably simple
calculation
Planned Investment Approach
(Cont.)
• Components needed to calculate these marginal
costs
– Total demand related additions to transmission
plant
– Growth in system peak
– Incremental cost per CP kW
– Real carrying charge rate
– Annualized cost per CP kW
– See Appendix 1, Page 47.
Avoided Costs and Least Cost
Plan
• Marginal costs are generally used for rate
design purpose and avoided costs are used for
least cost plan purpose.
• Avoided costs: The costs avoided as a result of
conservation measures are used to account for
the benefits for the conservation measures.
• Utilities avoided costs are a major component
to calculate benefits of utilities. If benefits are
greater than costs, the DSM program is cost
effective. The avoided costs play a major role
in screening DSM programs.
Demand-Side Management
Programs
• Program Screening – Various Cost/Benefit
Tests were applied.
• All-Ratepayers Test measures the impact of
DSM on the customers’ bills.
• Rate Impact Measure (RIM) Test measures the
impact of DSM on the customers’ rates.
• We currently consider both. However, many
programs passed the All-Ratepayers Test would
not pass the RIM test.
DSM Programs (Cont.)
• We no longer have LCP requirement since
PEPCO sold its generation assets.
• We have a Reliable Energy Trust Fund
(RETF) which collects a surcharge to
finance (1) Energy Efficiency Programs (2)
Renewable Resource Programs and (3)
Low-Income Direct Assistance Programs.
DSM Programs
• High-Efficiency Air Conditioner Rebate
Program
• Rebate dropped from $600 to $300 from 1992
to 1997 because of market transformation.
• Through the program, PEPCO has increased
customer awareness of the benefits of highefficiency HVAC equipment and has
encouraged HVAC dealers, contractors, and
retailers to stock high-efficiency equipment.
• See Appendix 1, Pages 31-40.
New Building Design Program
• It is a commercial DSM program.
• Program rebates are based on the
average incremental cost between
standard-efficiency and high-efficiency
equipment.
• The program also encourages thermal
energy storage applications in new
buildings.
Other Conservation Program
Concept
• A. Shared Savings Approach
– Win-win for both Energy Service Companies
and Customers
• B. Pay As You Save
– Customers pay additional surcharge on their bill
to cover the cost of energy efficiency programs.
Energy Use Management
Programs (EUM)
• Residential Time of Use Rates
• Kilowatchers Club
– A cycling program for central air conditioners, heat
pumps, and electric water heaters.
– PEPCO limits the cycling of air conditioners to no
more than 15 non-holiday weekdays over the fivemonth period and to no longer than six hours
between noon and 8 p.m. For air conditioning, the
air conditioner compressors may be cycled off for 13
minutes and then on again for the next 17 minutes of
each half-hour of program operation.
EUM Programs (Cont.)
• Commercial Time of Use Rates
• Curtailable Load Program
– PEPCO offers summer billing period credits of $8.6
per kW reduced to commercial customers who agree
to provide at least 100 kW of load curtailment.
Upon receipt of a signal from PEPCO, participating
customers reduce their electricity demands to a
“firm service level” for the duration of a curtailment
request. Participants who fail to reduce their
demand to the firm service level pay a penalty of
$17.20 for each kW used above the firm service
level.
• See the Appendix 1, Pages 13-30.
Demand Response Programs
• Mitigate the Supply-Side market power and
enhance reliability.
• Regional ISO programs supplement states’
programs.
Supply-Side Evaluations
• Considering PEPCO’s generating
facilities, power purchase
agreements, renewable resource
options, fuel supply arrangement,
and Clean Air Act compliance.
Transmission and Distribution
Improvement Plans
• Commission had established a Productivity
Improvement Working Group (PIWG)
which consists of PEPCO, Office of
People’s Counsel, and Commission Staff.
• PIWG meets monthly to discuss G, T, D
related projects and all the productivity and
fuel related issues.
T&D Improvement Plans (Cont.)
• PEPCO is required to file a
Productivity Improvement Plan (PIP)
each year with the Commission.
Commission will issue an order once
the plan and OPC & Staff’s comments
are reviewed.
Key Components of PIP
• (1) Productivity Improvement Projects
• (2) Industry Comparison includes:
– Annual unit
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Operating availability factors comparison
Equivalent availability factors comparison
Capacity Factor comparison
Equivalent forced outage factors comparison
– System heat rate comparison
Key Components of PIP (Cont.)
• System Energy Losses Comparison
• (3) Fuel prices, consumption and
expenditures forecast (the % difference
between forecasted values vs. actual values
were presented too.)
• (4) Technical Terms and Engineering
Process
Regional Transmission
Expansion Plan
• On Transmission side, PEPCO is a member of
Pennsylvania, New Jersey and Maryland
Independent System Operator.
• Stakeholders and PUC representatives
collaboratively decide the transmission
expansion plan for the region.
• PEPCO participated in regional studies and
conducted internal transmission studies.
Planning Framework
• Step 1: Resource Screening
• Step 2: Baseline Load Forecasts
– 15 Years
• Step 3: Full- Loop Integration
– The plans minimize total revenue
requirements for their respective scenarios.
• Step 4:Sensitivity Analysis and Base Plan
Selection
Planning Framework (Cont.)
• Step 5: Development of Alternative Plans
– With the Base plan as a starting point,
PEPCO develops alternative resource plans
that address a broader set of planning
criteria.
• Step 6: Analysis of Candidate Plans
– Each alternative plan is analyzed to
determine how well it meets each planning
objective.
Planning Framework (Cont.)
• Step 7: Preferred Plan Selected
– PEPCO selects a preferred plan that balances
effects on prices, utility revenue requirements and
customer bills, reliability, and customer service
objectives.
• Step 8: Action Plan
– A four-year action plan details PEPCO’s projected
capital costs, budgets, and schedules for carrying
out the Preferred strategy.
• See Appendix 1, page 41.
Integration Procedure
• Baseline Load Forecasts
– See Appendix 1, Pages 48-51.
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Marginal Cost Determination
DSM Cost-Effectiveness Analysis
Net Load Forecasts
Resource Integration
– See Appendix 1, pages 42-45, 67.
Key Planning Assumptions
• For alternative cases, the planning
assumptions vary.
• Key assumptions include:
– General Inflation
– GDP growth rates
– Price of Electricity
Built or Buy Decisions
• Evaluated outside of the filing of Least
Cost Plan
• Previously, two projects were considered
– PEPCO would like to sign two power
purchase agreements
– One with Patowmack Power Partners, Inc.,
(PPP) and the other with Panda-Brandywine
L.P. (Panda)
Panda and PPP Projects
• PEPCO requested that the Commission
approve these non-company power
projects in the context of a
modification to its least-cost plan
(LCP) and find the contract payments
to be below the Company’s avoided
costs.
Panda and PPP Projects
• The Commission investigated two issues:
• (1) Is the need for and the timing of the
Panda and PPP projects prudent and
consistent with PEPCO’s least cost planning
activities?
– If so, should PEPCO’s LCP be amended as
proposed by PEPCO to include these two
contracts?
Panda and PPP Projects
• (2) Whether the proposed
payments for energy and capacity
pursuant to the terms of the Panda
and PPP contracts are below
PEPCO’s applicable avoided costs?
Panda and PPP Projects
• PEPCO suggested accepting both
projects.
• OPC suggested accepting one
project Panda.
• Staff suggested rejecting both
projects.
Panda and PPP Projects
• Staff’s main reasons:
– PEPCO would not need any capacity to satisfy the
reserve margin requirement until 1995
– PPP was supposed to be on-line starting with 1994
– Panda and PPP created excess capacity for six years,
during a time when PEPCO’s reserve margin
exceeds 20 percent
– See Appendix 2, PSC (B)-7 to PSC (B)-10.
Panda and PPP Projects
• Based on both need, timing and
avoided costs analysis, Staff
rejected both projects.
• Commission decided to accept
Panda rather than PPP.
Retail Electric Competition and
Consumer Protection Act of 1999
Additional Highlights:
• The Commission is actively establishing customer
education programs including a Commission
hosted website to facilitate price comparisons
• See www. dcpsc.org, click on customer
information, electric.
• Establishing Reliable Energy Trust Fund
Programs
• Establishing code of conduct between PEPCO
and its affiliates
• Determining fuel mix information disclosure for
the consumers
The 1999 Act (Continued)
• Establishing procedural rules for
complaints, investigations and
dispositional hearings
• Governing market power proceedings
in both retail and wholesale markets
• Implementing competitive bidding
process to select default service
provider prior to July 1, 2004
• New SOS provider should start on
January 1, 2005.
The 1999 Act (Continued)
• In addition:
 a) The Act states that the Mayor, in
conjunction with the
Commission, shall issue
regulations governing a municipal
aggregation program.
 b) Net Metering provisions include:
Facilitating the development of
distributed generation.
 c) Competitive billing shall begin on
January 1, 2002.
Act Implementation &
the “Retail Choice Program” Jan. 1, 2001
• The Commission completed the
“Three-Phase” Rate Reductions
• The total rate reduction for threephases amounts to 7% for Residential
customers and 6.5% for Commercial
customers.
• 11 Suppliers/Aggregators were
approved by the Commission.
Current Statistics
• 8.3% of residential and 19.1% of nonresidential customers have switched to the
third-party suppliers.
• In terms of total MWs, 48.9% of the load has
switched.
• See page 68 for a copy of recent D.C.’s market
monitoring report.
• For a copy of Electric Policies in the Public
Interest, see Appendix 1, Pages 52-66.
THANK YOU!