power grids and cdm methodologies workshop for cdm stakeholders the world bank buenos aires december...

Ingenieros Consultores

POWER GRIDS ANDCDM METHODOLOGIES

Workshop for CDM stakeholders

The World BankBuenos Aires

December 8, 2004

Ingenieros ConsultoresPower Grids and CDM Methodologies

Characteristics of deregulated power markets in LAC Dispatch and spot market Contract market Criteria used for deciding new power plants

Planning and dispatch: case of Chile What does a CDM project substitutes? Case of Chile Comments on the CDM baseline methodologies

CONTENT


Most LAC have developed deregulated Wholesale Electricity Markets -WWM-

Dominican Republic, Guatemala, Nicaragua, Salvador, Panama, Colombia, Ecuador, Peru, Bolivia, Chile, Argentina

Main features: Competition in generation and supply. Deregulated prices No central planning

Indicative Planning intended to provide information, only Open access to the transmission system Centralized dispatch based on merit order of variable operating

costs (most countries) Spot prices based on the system´s short run marginal costs (most

countries)

Characteristics of deregulated power markets in LAC


Usual practices


Dispatch and spot prices based on offered prices

Colombia, Salvador

Dispatch based on merit order and spot prices based on variable costs

All others

Capacity price separated from energy price

All, except Salvador

Capacity price based on the annuity of capital of a Gas Turbine (least cost for peaking-reserve)

All, except Salvador

Supplies mostly based on bilateral contracts and agreed prices

Chile, Peru, Colombia, Dominican R., Nicaragua, Guatemala, Panama

Supplies mostly based on levelized (6 months) spot prices

Argentina, Bolivia, Ecuador


Usual practices for contract supplies

Contracts established for 2 to 15 years Contract prices based on:

First years of the reform: average of expected spot prices Due to risk of fluctuations, the current practice is to set

prices close to a proxy of the system development costs (capital + operation costs of new units)

Equivalent to concept of opportunity costs (costs of competitors)

Indexed with US CPI and fuel prices In accordance to cost structure



Usual practices for spot supplies

Gencos sell to “the system” Discos purchase from the system Price = average of expected spot prices for following 6 months Adjustment “ex-post” in accordance with actual spot prices

Links between spot prices (including capacity component) and long term contract prices:

A permanent discrepancy in one direction cannot be sustained Under equilibrium conditions, both converge In theory, revenues from the contract market should be closed to

those from the spot market Contracts provide stability in revenues



A Genco decides to invest:

When the revenues through contracts and/or the spot market covers its capital + operating costs

Spot revenues assessed for a likely expansion sequence Investments decided under competitive pressure

Likely expansion sequence = such as spot revenues (capacity + energy) provide a given a return on assets

Return depends on the country risk and power sector risk LAC: 10-14% on assets (real term, after taxes)

The possibility to sign LT contracts sometimes “accelerates” the decision to invest

Criteria used for deciding new power plants


Practical approach: 1- Determine a likely expansion sequence

Includes power plants already decided New power plants added when spot prices get a level such that they

provide a given return on assets The expansion sequence includes the project (several sizes, start-up

dates) In hydro-thermal system, a least cost thermal “base-load”

technology is usually selected

2- Compute spot prices for that expansion sequence

3- Computes revenues for the project selling P and E into the spot market

4- Determine if and when revenues pay the project´s capital + operating costs

Criteria used for deciding new power plants


Spot and contract prices in the central Interconnected System

SIC - MONOMIC SPOT AND NODE PRICES (Quillota 220 kV, Load Factor=0.75)

0

20

40

60

80

100

120

140

160

Ene

-94

Ene

-95

Ene

-96

Ene

-97

Ene

-98

Ene

-99

Ene

-00

Ene

-01

Ene

-02

Ene

-03

Ene

-04

abr0

4 U

S$

/ MW

h

Node

Spot

WEM prices in Chile


Since the gas interconnection with Argentina: price driver are 370 MW combined cycle units burning NG (base load)

Before: coal unitsCosts

Planning and dispatch: case of Chile

Investment 192 MM US$ (520 US$/kW)Fixed O&M 4 MMUS$/yearFixed gas transport cost 17 MMUS$/yearVariable non fuel + NG price 14 US$/MWhTotal average cost (11% return on assets, 85% plant factor)

36 US$/MWh

Return from capacity payments

11 US$/MWh

Required return from energy payments

25 US$/MWh


Since new CC units (most economic development units) require 25 US$/MWh, the MW planned must be “below” the existing coal units for dispatch

In order to avoid being the marginal unit

Planning and dispatch: case of Chile

Hydro reservoir

Coal = 28 US$/MWh

Gas = 14 US$/MWh

Run of River =0 US$/MWh

Coal is marginal

SRMC= 28

Gas is marginal

SRMC= 14


Same would happen with new hydro power plants (instead of NG cc units): if too much capacity is added, the SRMC would drop

What does a CDM (base load) project substitute? Coal or NG? apparently coal (and some NG)

What does a CDM project substitutes? Case of Chile

Hydro reservoir

Coal = 28 US$/MWh

Gas = 14 US$/MWh


Coal substitution?

SRMC= 28Gas substitution?

SRMC= 14


In fact substitutes 100% NG since it will displace (or reduce the size) of a new cc unit

The same amount of coal is burned


Hydro reservoir

Coal = 28 US$/MWh

Gas = 14 US$/MWh


Coal substitution

SRMC= 28Gas substitution

SRMC= 14

The CDM project substitutes MW in the cc unit


Apparently a small CDM project is marginal and might not affect investment decisions

Certainly, a large project close to start construction or under construction will not be postponed.

But “marginal” does not mean “nil” The impact of even a small project is relevant in the spot market Example.

A 50 MW CDM base load project (less than 1% of the 7000 MW installed capacity in the Chilean SIC) has an impact of -1.5 US$/MWh in the spot prices if nothing is postponed (4% on prices)

The incumbents perceive an impact of 1.5 x 35 TWh = 52 MMUS$/year if they do nothing

=> Very shortly they will postpone projects in order to avoid prices below development costs



The “Combined Margin methodology” averages the Operating Margin (OM) and the Build Margin (BM)

We believe that only for very small projects the OM is applicable Under the condition that the total capacity of all projects remains small

In principle, the appropriate methodology would be to recalculate the expansion sequence with and without the project.

Given the complexity, lack of transparency, gaming, etc., we believe that the BM methodology should have more weight

For base load CDM projects, a good approach seems to estimate the BM through the reduction in the capacity that is likely to be installed as base load (hydro and cc units in the case of Chile)

This is the “proxy plant method”

Comments on the CDM baseline methodologies

power grids and cdm methodologies workshop for cdm stakeholders the world bank buenos aires december...

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