# Presentation: 661899

## Electricity Prices in a Competitive Environment

- presented to the
- Philippines Department of Energy
- by
- Robert T. Eynon
- Energy Information Administration
- U.S. Department of Energy
- September 17, 1997

## 1995 Retail Electricity Prices (Cents per kilowatthour) 

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- 1995 Retail Electricity Prices (Cents per kilowatthour)

**Notes:**
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## Restructuring Activities by State (December 1996)

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- Restructuring Activities by State (December 1996)

**Notes:**
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## Assumptions

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- Competition begins January 1, 1998
- No market power
- Reserve margins are set to minimize capacity and outage costs
- Consumers may shift demand from peak to off-peak periods
- Transmission and distribution is priced under cost-of-service regulation

## Electricity Price Components

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- Marginal generating costs include the operating and maintenance costs of the last plant dispatched in each time period, the recovery of general and administrative costs, and taxes.
- Reliability price adjustment applies to periods when demand approaches the limits of available generating capacity based on
- the value that consumers place on reliability and
- the contribution that each kilowatt of generating capacity contributes to reliability.
- Regulated prices for transmission and distribution services

## Coal Plant Employment

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- Source: Federal Energy Regulatory Commission, FERC Form 1, “Annual Report of Major Electric Utilities, Licensees and Others.”

**Notes:**
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This graph illustrates the same improving cost trend in terms of employees.
Employeement began to fall in 1986 and fell 22 percent between 1986 and 1995.
Some of this may be due to outsourcing, but employment levels at utilities are clearly declining.

## Operation and Maintenance Costs for Coal Plants

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- Source: Federal Energy Regulatory Commission, FERC Form 1, “Annual Report of Major Electric Utilities, Licensees and Others.”

**Notes:**
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Between 1981 and 1995 coal plant operations and maintenance costs fell 44 percent in real dollars per kilowatthour.
A good part of this was due to declining fuel cosls, but nonfuel costs also fell 22 percent over the same time period.
Non fuel costs were actually rising in the early 1980s, but began falling in 1987.  From 1986 until 1995 then fell 26 percent.
Its hard to say how  much of this is due to competition.  Falling gas and oil prices in 1986 also put pressure on coal plants to improve.
Its also hard to say how far they can continue to improve.
The difference in nonfuel operating costs from the first and third quartile of plants Is 27 percent.
For our upcoming AEO we expect these costs to fall by this order of magnitude.

## Slide 8

## National Price Results

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## National Price Results

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## Regional Price Results

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## Net Stranded Asset Estimates

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## Regional Net Stranded Asset Estimates

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## Regional Price Distributions

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## Distribution of Revenue Changes

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## Uncertainties

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- Market power
- Competitive prices for customer classes
- Efficiency improvements
- Prices for transmission and distribution services
- Market value of service reliability and inclusion in prices
- Cost of capital
- Costs of price volatility
- Technological innovation
- Timing of restructuring

## Summary

- Growing competition is likely to lead to lower electricity prices without stranded cost recovery
- The level of price decline will be driven by utilities ability to make efficiency improvements and consumer response to price changes
- The impacts vary among regions and  utilities within regions

## ELECTRICITY MARKET MODULE (EMM)

**ELECTRICITY MARKET MODULE (EMM)**
**of the**
**NATIONAL ENERGY MODELING SYSTEM (NEMS)**
**presented by**
**Robert T. Eynon**
**Energy Information Administration**
**to the **
**Philippines Department of Energy**
**September 16, 1997  **

**Notes:**
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## Information Flow Within the  Electricity

**Information Flow Within the  Electricity**
**Market Module**

## INFORMATION FLOWS WITH OTHER NEMS MODULES

**INFORMATION FLOWS WITH OTHER NEMS MODULES**

- End-Use Demand Modules
- Inputs:	Electricity demand by sector and end-use (e.g., residential heating, commercial lighting)
- Outputs:	Sectoral electricity prices
- Fuel Supply Modules
- Inputs:	Fuel prices, SO2, emissions penalty cost (coal)
- Outputs:	Fuel consumption, SO2, emissions limit (coal)
- Renewables Fuel Module
- Inputs:	Cost and performance characteristics
- Outputs:	Capacity additions

## ELECTRICITY SUPPLY REGIONS

**ELECTRICITY SUPPLY REGIONS**

- Uses 13 regions corresponding to North American Electric Reliability (NERC) regions and subregions.
- Represents service territories of integrated utility systems.
- Allows representation of demand using actual load data.
- Allows meaningful representation of interregional transfers.

**Notes:**
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## ELECTRICITY MARKET MODULE REGIONS

**ELECTRICITY MARKET MODULE REGIONS**

## ENVIRONMENTAL REGULATIONS

**ENVIRONMENTAL REGULATIONS**

- Operating decisions (e.g. fuel switching, allowance trading) for compliance with Clean Air Act Amendments of 1990
- Investment decisions (e.g. scrubbing) for compliance with Clean Air Act Amendments of 1990
- Intertemporal decisions (e.g. banking) for compliance with Clean Air Amendments of 1990
- Impacts of environmental regulations on capacity expansion decisions (e.g. technology choice)
- Impacts of alternative environmental regulations/policies (e.g. cap on carbon emissions, externality costs)

**Notes:**
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## OWNERSHIP TYPE

**OWNERSHIP TYPE**

- Represent generation and capacity additions for electric utilities and exempt wholesale generators (EWGs)/independent power producers (IPPS)
- Obtain cogeneration supplies from appropriate end-use demand module
- Adjust total capability and energy requirements to account for contributions from cogenerators

**Notes:**
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## TECHNOLOGY CHOICE

**TECHNOLOGY**** CHOICE**

- Choose among fossil-fuel, nuclear, and renewable technologies
- Represent dispatachable technologies
- Available for electricity generation in each load segment
- Full capacity credit towards total capacity requirement
- Represent intermittent technologies
- Production capability varies by season or time of day
- Contribution to total capacity requirement based on availability of energy source at time of peak demand
- If no capacity credit, evaluated on the basis of fuel savings
- Compete both conventional and advanced technologies

**Notes:**
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## LOAD

**LOAD**

- Uses annual electricity demands by sector and end-use
- Captures variations in demand over time using regional load duration curves (by sector and end-use) based on hourly load data from the NERC
- Defines loads chronologically to capture seasonal and time-of-day periods (daytime, morning/evening, and night) for dispatching
- Provides load duration curves for dispatching and planning decisions
- Uses six two-month seasonal periods and three time-of -day periods (daytime, morning/evening, and night) for dispatching
- Uses three four-month seasonal periods (Summer, Spring/Fall, and Winter) and three time-of-day periods (daytime, morning/evening, and night) for planning

**Notes:**
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## FUEL DISPATCHING

**FUEL DISPATCHING**

- Adjusts load duration curves for firm power purchases (domestic and international)
- Determine variable (fuel, O&M, emissions) cost for each capacity type
- Determine merit order (rank capacity types in ascending order of cost)
- Allocate capacity to meet demand based on merit order (most economical type used most, least economical type used least)
- Determine economy trades by comparing marginal production costs of regions with interregional transmission capability
- Determine generation and fuel consumption corresponding by capacity type
- Compute emissions

## CAPACITY PLANNING

**CAPACITY PLANNING**

- Use linear programming structure with multiyear planning horizon
- Satisfy capacity and energy requirements in each load segment
- Utilize dispatchable technologies in any load segment
- Limit intermittent technologies to specific load segments
- Meet minimum reliability requirements
- Allow fuel, partial, or no capacity credit
- Impose explicit limit on emissions such as SO2

## TECHNOLOGY PENERATION

**TECHNOLOGY PENERATION**

- Obtain capital cost estimates for “nth-of-a-kind” units
- Represent cost curves as technologies penetrate
- Technological optimism
- Learning-by-doing
- Risk premiums
- Use market-sharing algorithm to adjust capacity expansion decisions to include “competitive” but not “least-cost” technologies

## PRICING

**PRICING**

- Accumulate fixed and variable costs of building and operating electric powerplants
- Determine price of electricity under cost-of-service regulation
- Compute components of price (capital, fuel, operations and maintenance, purchased power)
- Compute sectoral electricity prices
- Determine competitive price of electricity
- Includes marginal energy cost (fuel, variable O&M)
- Includes reliability component (value of capacity)
- Assumes transmission/distribution price is the same as in cost-of-service regulation