International Experience
with Single Buyer Models for
Electricity
Report to Contact Energy
August
2013
Copyright Castalia Limited. All rights reserved. Castalia is not liable for any loss caused by reliance on this
document. Castalia is a part of the worldwide Castalia Advisory Group.
Acronyms and Abbreviations
ANEEL
The National Electric Energy Agency (Brazil)
CCA
Consumer Choice Aggregators (US)
CCEE
The Energy Commercialization Chamber (Brazil)
ECNZ
Electricity Corporation of New Zealand
EPE
Energy Research Council of Brazil
FIT
Feed In Tariffs
IESO
Independent Electricity System Operator
IPP
Independent Power Producer
kWh
Kilowatt hour
MW
Megawatt
MWh
Megawatt hour
NZ
New Zealand
OPA
Ontario Power Authority
OPG
Ontario Power Generation
PPA
Power Purchase Agreement
RFP
Request for Proposal
VOLL
Value of Lost Load
Table of Contents
1
2
3
4
5
6
7
Introduction: Key Decisions on Electricity Sector Structure
1
1.1
Four Key Functions for an Efficient Electricity Sector
1
1.2
Range of Industry Structures to Make these Decisions
3
1.3
Purpose of this Report
5
Which International Jurisdictions Use The NZ Power
Model?
7
Case Study of Brazil
13
3.1
Evolution of the Current Model
13
3.2
Planning
14
3.3
Procurement
15
3.4
Dispatch
20
3.5
Retail Sales
21
Case Study of Ontario
22
4.1
Evolution of the Current Model
22
4.2
Planning
23
4.3
Procurement
24
4.4
Dispatch
25
4.5
Retail Sales
27
Case Study of Vertically Integrated Electricity Sectors with
Independent Power Producers (IPPs)
29
5.1
Evolution of Current Market
29
5.2
Planning
30
5.3
Procurement
31
5.4
Dispatch
33
5.5
Retail Sales
34
Case Study of Jurisdictions with Capacity Markets
35
6.1
Evolution of the Current Market
35
6.2
Planning
36
6.3
Procurement
36
6.4
Dispatch
37
6.5
Retail Sales
38
Conclusion: What Will Reduce Retail Power Prices?
39
Appendices
Appendix A : Operation of Electricity Sector Affected by Physical
Features
42
Tables
Table 1.1: Risks in Each Function of an Electricity Sector
2
Table 2.1: Evaluation of nominated international comparators
8
Table 3.1: Characteristics of “Old” and “New” Energy Auctions
17
Table 3.2: Average volume and prices of regulated market
contracts (2004 to 2012)
18
Table 5.1: Four Main Types of Retail Markets in Jurisdictions
with Vertically Integrated Markets
34
Table 7.1: Lessons from International Experience with Sector
Reform
40
Table A.1: Comparison of the New Zealand Electricity Sector to
Electricity Sectors in Brazil and Ontario
42
Figures
Figure 1.1: Physical Supply Chain for Electricity
3
Figure 3.1: Methods of Procurement in the Brazilian Electricity
Sector
16
Figure 3.2: Convergence in “Old” and “New” Energy Prices
18
Figure 3.3: Link between Procurement and Dispatch in Brazilian
Power Sector
20
Figure 4.1: Methods for Procuring New Generation Capacity in
Ontario
24
Figure 4.2: Role of Long Term Financial Contracts in Ontario
26
Figure 4.3: Comparison of Retail Electricity Prices in Ontario and
New Zealand
28
Figure 5.1: Common Steps in Electricity Sector Reform Overseas
30
Figure 5.2: Key Features of Power Purchase Agreements
32
Figure A.1: Size of Electricity Supply and Demand (MW)
43
Figure A.2: Sources of Demand in Ontario, New Zealand and
Brazil
44
Figure A.3: Generation Mix in Ontario, New Zealand and Brazil
45
Boxes
Box 6.1: PJM Reliability Pricing Model
37
Executive Summary
The Labour Party and the Greens have proposed to replace New Zealand’s wholesale
electricity market with a single buyer of wholesale electricity known as NZ Power. The
key motivation behind the NZ Power proposal is to reduce retail electricity prices for
residential customers. The Labour Party and the Greens believe this can be achieved
through a single buyer model that carries out the functions of electricity supply more
efficiently than the current wholesale market. This report investigates what international
experience with various forms of single buyer models tells us about NZ Power.
There is no ready-made single buyer model to emulate
Our review of international experience shows that there is no single buyer scheme
anywhere in the world that New Zealand can draw on as a model to emulate. Regardless
of the arrangements that have been adopted, each jurisdiction continues to grapple with
risks that make electricity supply difficult in their particular context.
Our review also shows that single buyer models with a similar design to NZ Power are
relatively rare. Many of the examples provided by the Labour Party and Greens policy
documents are actually wholesale energy markets similar to New Zealand, while other
examples are variants of vertically integrated national utilities with different degrees of
contracting out (a kind of ECNZ model with generation and some aspects of the retail
function delivered by the private sector under long-term contracts). This leaves two
jurisdictions (Brazil and Ontario, Canada) that are sufficiently similar to the NZ Power
proposal to warrant in depth investigation in this report. Other international examples
also offer interesting insights into how various design and implementation issues can be
resolved, despite having quite different features from the NZ Power proposal.
The lack of international experience with single buyer models like NZ Power does not
mean that the scheme cannot be made to work. In principle, it may be possible to
assemble a reasonably efficient set of arrangements that draws on aspects of each of the
actual systems found around the world. However, it is important to understand that in
doing so, New Zealand would embark on a world-first. Since all elements of an electricity
system are inter-linked, there a clearly significant risks in simply plucking the best
features from each system and hoping that they integrate seamlessly.
Lower power prices come from managing risks effectively
The key to lower electricity prices is not adopting a particular structure for the electricity
sector, but getting the risk allocation right. A framework that allocates risk efficiently will
generally produce lower retail prices over the long term. Efficient risk allocation involves
allocating risks to the party best able to manage and mitigate them—the party that has
both the means and the incentives to manage each risk.
All electricity systems require a number of key functions to be carried out, requiring
trade-offs to be made about who bears risk:
How much generation capacity do we need and when do we need it?
What’s the most efficient way of procuring that capacity?
Which generators do we run at what times to minimise the total costs of
supply?
How do we retail electricity to ensure efficient utilisation?
Electricity industry structures differ primarily on who bears the risk that these decisions
will not be made in the least-cost way—for example, because too much or little
i
generation capacity is procured at a particular point in time. In market based systems,
generators and retailers bear most of these risks. If too much generation is procured,
prices fall and investors bear the consequences. In the NZ Power proposal, these risks
are transferred to the single buyer, but the costs are ultimately borne by customers if the
single buyer recovers its costs or taxpayers if NZ Power suffers financial losses.
When these risks are shifted to a single buyer, it is clear that private generators and
distributors bear lower risk, and will therefore expect lower returns. This should mean
that wholesale electricity costs will be lower. However, whether or not moving to a single
buyer model results in lower retail electricity prices for customers depends on whether the
single buyer can manage the risks better than the private generators and retailers. There is
no evidence from our review of international experience that suggests that a single buyer
in New Zealand would be able to manage key risks better than current market
participants. In fact, the experience from Ontario and Brazil suggests that single buyers
are unable to control prices if underlying industry costs are rising.
ii
1
Introduction: Key Decisions on Electricity Sector
Structure
The Labour Party and the Greens believe that retail electricity prices in New Zealand are
too high. To lower retail prices, they propose to replace New Zealand’s wholesale
electricity market with a single buyer of wholesale electricity (called NZ Power). This
report analyses international experience with a range of single buyer models to draw out
the relevant lessons for sector reforms in New Zealand. In particular, we ask what
international experience tells us about the effect of different sector structures on retail
electricity prices.
The electricity sector involves a complex series of trade-offs and risk allocation decisions.
Internationally there are a wide variety of models and structures ranging from
competitive markets through to regulated monopolies. All market structures aim to
achieve reasonable retail electricity prices, within the physical, environmental and legal
environment in which they operate. By reasonable, we mean prices that broadly reflect
the cost of supply including compensating parties for the risk they take. There is no
universally accepted “right” market structure for achieving those electricity prices.
1.1
Four Key Functions for an Efficient Electricity Sector
The generation and sale of electricity to end users requires the following four key
functions to be carried out, and the risks associated with each function to be allocated
and managed. The key functions are:
Planning. How much generation capacity is required, both now and in the
future, to efficiently meet demand?
Procurement. How are the decisions on the size, type, technology and
location of the required new capacity made to ensure that future demand is
met at the least cost?
Dispatch. How do you dispatch your portfolio of available generation to
ensure that the least cost sources of power are used within the physical and
environmental constraints of the system?
Retail sales. How is electricity priced and sold to end use customers to
ensure efficient utilisation?
Each of these functions involves taking risk. At the planning stage, who pays if demand
is lower or higher than expected? At the dispatch stage, who pays if fuel resources are not
efficiently used? Table 1.1 summarises the source of uncertainties in the electricity sector,
and the related risks that need to be allocated when dealing with these uncertainties.
1
Table 1.1: Risks in Each Function of an Electricity Sector
Source of Uncertainty Risk Event
Planning
Long term demand
Who pays if demand is lower or higher than expected?
Procurement The least cost supply
option
Who pays if we contract for supply that is the wrong
size, built at the wrong time, in the wrong location or
using the wrong technology?
Dispatch
Fuel availability
Who pays if you do not use fuel resources efficiently?
Retail
Real time demand
Who pays if demand is higher than expected in real
time?
In the current New Zealand electricity market, these functions are largely discharged
through market interactions. The market involves a high degree of regulation and
oversight by such bodies as the Electricity Authority and the Commerce Commission.
Market interactions also need to be co-ordinated by bodies such as the Market and
System Operators. The wholesale electricity market is therefore quite artificial, and
requires a complex set of rules to function well.
In the Labour and Greens proposal, these key functions will be carried out by an
independent statutory body called NZ Power. This industry structure is commonly
referred to as a “single buyer model”. In the broadest sense, “single buyer” means that a
centralised agency has some degree of role in coordinating supply (generation) and
demand (retail) of electricity. However, it is important to recognise that there are a wide
variety of “single buyer” models in use internationally, with a reasonable degree of
confusion about what the term actually means.1
The “single buyer” model does not reform transmission and distribution
There are of course other functions that need to be carried out within the electricity
supply chain—most notably transporting electricity from generation sources to the
customers. Figure 1.1 provides an overview of the physical supply chain for electricity,
and the contribution that each component of the supply chain to retail electricity prices.
The Labour and Greens single buyer proposal only has the potential to influence costs
arising in two components of the electricity supply chain shown in Figure 1.1: electricity
generation and retailing. Suppliers in the other “monopoly” parts of the electricity supply
chain (transmission and distribution) have their prices regulated by the Commerce
Commission under Part 4 of the Commerce Act 1986. This suggests that the single buyer
proposal relates to components of the physical supply that account for roughly half of
retail electricity prices, and similarly do not explain all of the recent increases in retail
electricity prices.
1
See Centralized Purchasing Arrangements: International Practices and Lessons Learned on Variations to the Single Buyer Model,
World Bank, March 2006
2
Figure 1.1: Physical Supply Chain for Electricity
Note:
* Other supply chain costs not shown above are 2% for metering and 11% for tax
Source: Electricity Authority, “Electricity in New Zealand”
1.2
Range of Industry Structures to Make these Decisions
Internationally, there are a range of industry structures for making the key planning
procurement, dispatch and retailing decisions.
Three broad industry structures, two with features of a single buyer
Possible industry structures can be conceptualised on a spectrum from a fully vertically
integrated, price regulated monopoly (where a single entity owns and controls all
generation, procurement, dispatch and retail); to fully competitive markets (where private
generators bid to supply electricity to private retailers). In between these points on the
spectrum, there are three main models used around the world:
A vertically integrated monopoly that owns most generation but with some
competition in generation, particularly for new capacity. Depending on how
roles are allocated, this structure can have features of a “single buyer” model.
This industry structure is explored in more detail in Section 5
Capacity markets where there are separate markets for generation capacity
(MW) and the production of energy (MWh). This industry structure could also
have features of a “single buyer” model, and is analysed in more detail in
Section 6; and
Energy only markets where generators are paid a single price for energy
production (MWh), and are not explicitly compensated for providing capacity
(MW). This model is currently used in New Zealand, and does not have any
elements of a “single buyer” model.
NZ Power is a hybrid model
It is worth being clear about where the Labour and Greens’ proposal sits on the
spectrum of possible industry structures. We see NZ Power as a hybrid approach that
combines some aspects of a vertically integrated utility that procures generation by
contract, with some aspects of a capacity market.
The following bullets characterise the NZ Power proposal according to the degree of the
level of central control of planning, procurement, dispatch and retail:
3
Planning for new investment is done centrally using demand forecasts
rather than through price signals. A single buyer—almost always a
statutory body and independent of generation companies—forecasts the
generation capacity required. This means that the level of required capacity is
administratively determined, and not the result of market forces. Under the
NZ Power proposal, the need for investment in new capacity would be
identified through a planning process that is centrally controlled.
New generation is centrally procured through a competitive tender for
long term power purchase contracts. The required generation capacity is
procured by the single buyer through an open tender process with private
sector parties. This is often described as competition for the market, without
competition in the market. There is no reservation or allocation of new
generation projects to government owned generation entities or incumbents.
Generators are paid under long term contracts by the single buyer. The
contracts are typically for the economic life of the generation plant and usually
incorporate both capacity and energy payments (or have equivalent effect
through mechanisms such as a predetermined load factor or take or pay
obligations). Using this approach, the NZ Power proposal combines some
elements of central control (requiring a central procurement process to be
run), with elements of market competition (allowing project sponsors to
compete for contracts).
Dispatch of generation is controlled centrally, without reliance on
market interactions. The single buyer dispatches all generation—usually in
merit order according to the contracted energy price—but can dispatch out of
merit order due to other considerations, such as optimising use of scarce fuel
resources or achieving environmental goals. The design of the dispatch
arrangements determines the extent to which generators’ offers determine
whether their plants operate at any time. The NZ Power proposal implies a
high level of central control over dispatch, with the single buyer having wide
discretion to call on plants to run.
4
Retail of electricity to end-use customers is marked based. The single
buyer sells all energy to one or more retailers and major customers—that is,
there is no generator to retailer or customer contracting. In many jurisdictions,
the single buyer sells wholesale power to regulated distribution and retail
companies (involving a high degree of central control). However, the NZ
Power proposal instead plans to maintain competition between retailers (a
more market based approach).
1.3
Purpose of this Report
The purpose of this report is to:
Identify which overseas jurisdictions currently have electricity sector
structures that are similar to the structure proposed by the Labour and
Greens. The international evidence shows that only a small number of
jurisdictions have a single buyer model that answers the four design questions
in a similar way to the NZ Power proposal; and
Draw lessons from each of these market structures for New Zealand.
We look at how each of the overseas jurisdictions answers the four questions
above on capacity, procurement, dispatch and retail. This enables us to
identify lessons from international experience on the trade-offs involved in
achieving reasonable retail electricity prices.
Structure of this report
Section 2 of this report identifies which overseas jurisdictions currently have electricity
sector structures that are similar to the proposal being made by Labour and the Greens.
We start by defining the essential characteristics of the model NZ Power model. We do
this by reference to the Labour and Greens policy documents. Those documents refer to
a number of jurisdictions that incorporate some or all of the characteristics of a single
buyer model. We compare those jurisdictions to the NZ Power model to focus our
research and analysis on the nominated jurisdictions that are similar to the proposal.
In the next four sections of this report, we then analyse four market structures that are
likely to hold lessons for the NZ Power proposal:
5
Section 3 provides a case study of Brazil, which has a unique structure that has
many of the features of a single buyer model in a hydro-dominated electricity
systems
Section 4 provides a case study of Ontario, Canada, which is the closest
international comparator to proposed NZ Power model
Section 5 provides a case study of jurisdictions with electricity sectors that are
vertically integrated, with competition for generation. These structures provide
particular insights into the procurement of generation using long term
contracts
Section 6 provides a case study of capacity markets, which provide a different
model for the central procurement of generation capacity and the dispatch of
that capacity in real time.
In each of these sections, we look at who is responsible for planning, procurement,
dispatch, and retail, how these parties manage risk and therefore what impact the sector
structure has on electricity prices.
Finally, in Section 7 we summarise our review of the international experience with single
buyer models. We summarise which characteristics of electricity sector structures have
the largest impact on retail power prices. This helps to clarify what lessons can be drawn
from other jurisdictions about how to achieve efficient and sustainable electricity prices
in New Zealand.
6
2
Which International Jurisdictions Use The NZ
Power Model?
This section looks at the key features of the NZ Power proposal and then evaluates the
international examples of the single buyer model as provided in Labour’s and the Greens’
policy documents against those key features.
The opposition parties also claim that the proposal is “mainstream” internationally. In
the NZ Power proposal, Labour and the Greens cite a number of jurisdictions that utilise
the single buyer model—or variants of it:
[From the Greens policy document] A non-exhaustive list of countries and regions that
operate single buyer models: Brazil, China, India, Indonesia, Italy, Japan, Malaysia,
Mexico, Pakistan, Philippines, Ontario (which returned to a single buyer model after
the failure of a regulated market), South Africa, South Korea, Vietnam, EU (one of
three market options EU members can choose from). Massachusetts, Ohio, California,
New Jersey and Rhode Island have partial single buyer models called Community
Choice Aggregation, which work on the same principle of aggregating consumer demand
into one purchaser that has market power to drive down prices.
[From the Labour Party policy document] Many states in the United States use
similar models, including pricing models based on historic cost, plus fuel. Examples
include California and Virginia… Other examples include South Africa and
Brazil… This approach is common-place overseas. The 2011 World Bank report
Electricity Auctions: an overview of efficient practices details many examples.
In Table 2.1 we evaluate each of the jurisdictions nominated by the Labour/Greens
against the four key features of the NZ Power proposal identified in Section 1. The key
finding from this screening exercise is that many of the examples cited in the policy
document do not have these features and several cannot be accurately described as
adopting a single buyer model. The Ontario electricity sector is the only example that has
three of the four key features that we identify (it does not have non-market dispatch by
the single buyer).
7
Table 2.1: Evaluation of nominated international comparators
Jurisdiction
Who is
responsible
for planning?
How is new
generation
procured?
How is
generation
dispatched?
Who retails
electricity to
customers?
Type of Model
NZ Power
Competitive
tenders run by
NZ Power
By NZ Power
NZ Power sells to
competing retailors
Single buyer (owns no
generation) with retail
competition
Brazil
Government
agency
coordinates
demand
forecasts
prepared by
regional
distributors
Central agency
coordinates
capacity
auctions held 3
to 5 years in
advance
Hybrid model,
with
market dispatch
on basis of
generator bids for
thermal and
optimisation
model for hydro
Large customers
can buy directly
from generators.
Small customers
buy from regional
monopoly
distributors
Combination of a
capacity market with a
single buyer model
China
Central
planning for
all
investments
Non transparent
Dispatch on
On a regional basis Government controlled Sector dominated by government owned or
process
average cost basis
vertically integrated
controlled companies—high degree of
monopoly, little private central planning and regulation
sector involvement
India
Forecast on a
state by state
base by each
distributor
Some capacity
allocated from
Government
owned
generators
Regional dispatch
based on
generator bids
Distributors have
state monopoly
Vertically integrated
monopoly with some
competition for
generation
Distributors can self-generate, be allocated
power from large government owned
generators or tender to IPPs
Central government also facilitates large IPP
projects and allocates power to distributors
Indonesia
Central
forecast by
utility (PLN)
Only selected
projects
tendered by
PLN
Utility dispatch
But as an
integrated utility
Vertically integrated
monopoly with some
competition for
generation
PLN is a vertically integrated utility that
enters into PPAs for selected projects to
reduce balance sheet pressures and ensure
efficient development and operations. IPPs
currently buy around 22% of generation
NZ Power
8
Comments
Capacity auction and single buyer operate
only for regulated market. Contracted
generators execute contracts with each
distributor in proportion to forecast load.
Large customers contract independently
with generators
Jurisdiction
Who is
responsible
for planning?
How is new
generation
procured?
How is
generation
dispatched?
Who retails
electricity to
customers?
Type of Model
NZ Power
NZ Power
Competitive
tenders run by
NZ Power
By NZ Power
NZ Power sells to
competing retailors
Single buyer (owns no
generation) with retail
competition
Italy
Fully
competitive
market
Fully
competitive
market
Bid based market
Single buyer only
for some captive
consumers
Fully competitive
generation and retail
markets
Not a single buyer model. The terminology
“Single Buyer” is used for a default retailer
for small customers that haven’t chosen a
retailer. The retailer buys both from the
wholesale market and through contracts
Japan
Forecast by 10
regional
utilities
Only selected
projects
tendered,
depends on
policy of utility
Market based
dispatch
Through 10
integrated utilities
Vertically integrated
monopoly with little
competition for
generation
10 vertically integrated regional utilities with
some independent generation and a market
for trading between utilities
Malaysia
By
government
ministry
Ministry
allocates
projects
Utility dispatch
on IPP price
basis
Single integrated
utility
Vertically integrated
monopoly with some
competition for
generation
TNB vertically integrated utility but
significant (51%) generation by IPPs
Mexico
Forecast by
utility
All new projects
appear to be
tendered out
Utility dispatch
on IPP price
basis
Single integrated
utility
Vertically integrated
monopoly with some
competition for
generation
CFE vertically integrated utility with 23%
generation by IPPs
Pakistan
Forecast by
two utilities
(NTDC and
KESC)
Only selected
projects
tendered
Utility dispatch
on IPP price
basis
Two integrated
utilities
Vertically integrated
monopoly with some
competition for
generation
IPPs around 45% of generation
Philippines
Comments
Has a wholesale energy only spot market—not a single buyer model
9
Jurisdiction
Who is
responsible
for planning?
How is new
generation
procured?
How is
generation
dispatched?
Who retails
electricity to
customers?
Type of Model
NZ Power
Competitive
tenders run by
NZ Power
By NZ Power
NZ Power sells to
competing retailors
Single buyer (owns no
generation) with retail
competition
Ontario
By
independent
agency
Procured by
single buyer
Market based on
generator bids
Single buyer sells
to discos and
major customers
Single buyer model
South Africa
Forecast by
utility Eskom
Tendered on a
70/30 ratio
Utility dispatch
Single integrated
utility
Vertically integrated
monopoly with some
competition for
generation
NZ Power
South Korea
Vietnam
Comments
Classic single buyer model where IPPs are
100% of generation
IPPs around 2% of generation
Vertically integrated utility with generation in six wholly owned subsidiaries—not a single buyer model
By utility
EVN
Only selected
projects
tendered
Utility dispatch
Single integrated
utility
Vertically integrated
monopoly with some
competition for
generation
IPPs around 29% of generation
Europe
One of three options to deregulated market in 1996—no jurisdiction has adopted this option and, as noted above, Italy’s “Single Buyer” is their
terminology for a default retailer that has no role in forecasting, capacity procurement or dispatch.
US
Consumer
Choice
Aggregators
Not a single buyer model. The CCAs are retail aggregators that customers can voluntarily select on a community basis. They acquire energy by
contract from existing generators. They have no role in forecasting, capacity procurement or dispatch.
California
Virginia
Not a single buyer model. There is a wholesale market with regulated retail supply
Not a single buyer model. Virginia is part of the PJM wholesale market—a capacity market—and has retail competition
10
Nine jurisdictions lack any elements of single buyer
Of the eighteen jurisdictions nominated in the policy documents, nine do not appear to
have any aspects of the NZ Power model:
China’s electricity sector is dominated by Government ownership and control
with few (if any) genuine private sector generation businesses
Italy has a deregulated and competitive wholesale market. The term “Single
Buyer” is used to describe a default retailer for small customers that have not
chosen a retailer. The default retailer buys both from the wholesale market
and through contracts
Japan’s electricity sector has ten vertically integrated utilities with little
independent generation and some wholesale market trading between utilities
The Philippines has a competitive wholesale market that was modelled on
New Zealand’s current wholesale market
South Korea has a single vertically integrated utility with generation in six
wholly owned subsidiaries. This was done as a step towards divestment which
has stalled. The generators “trade” in an internal wholesale market
European Union. The single buyer model was one option of a 1996
European Union directive on the reform of member country electricity
sectors. It was effectively superseded by a 2003 directive where the single
buyer model was only to be used in special circumstances such as impending
supply shortages. It was never adopted by any member country
United States. The Consumer Choice Aggregators (CCA) referred to in the
policy proposals are retail aggregators that customers can voluntarily select on
a community basis through a majority vote. They acquire energy by contract
from existing generators. They have no role in forecasting, capacity
procurement or dispatch. In effect they are a retail co-operative. The two
states cited in the Greens document (California and Massachusetts) both have
wholesale electricity markets where generators compete (CAISO and
NEPOOL).
California. California has a wholesale spot market with a number of franchise
distributors that buy energy from the market, through bilateral contracts with
independent generators, and from their own generation
Virginia. This is not a single buyer model, it’s part of the PJM wholesale
market—a textbook competitive capacity market—and has full retail
competition
Seven jurisdictions are vertically integrated
Seven of the jurisdictions (India, Indonesia, Mexico, Malaysia, Pakistan, South Africa and
Vietnam) are classic Independent Power Producer (IPP) models where a vertically
integrated utility (owning generation, transmission, distribution and retail assets)
competitively tenders out some of the required new generation capacity to the private
sector. The utility then enters into long term contracts with successful bidders. These
contracts are commonly known as Power Purchase Agreements (PPA).
The reasons for tendering out new capacity may be some combination of:
Financial—involving the private sector may unlock additional sources of
finance that aren’t available to the utility
11
Efficiency—on the basis that the IPP may have lowers costs particularly in
development, construction and operation of the power station than the
incumbent utility; or
Sector reform—as part of a transition to a more competitive market—that is
introducing competition for the market as a first step to competition in the
market.
In most of the jurisdictions mentioned and elsewhere, the utility still continues to
develop additional generation capacity in-house. The basis for selecting which capacity is
tendered out and which is developed by the utility is often arbitrary and non-transparent.
For example, in many countries the national electricity utility will not tender out
generation opportunities that are considered “strategic”. The IPP model therefore fails to
provide useful insights into how to make good decisions on how much generation
capacity is needed and of what type and location.
While the planning decisions made by vertically integrated utilities are not directly
relevant, the process of procuring IPPs is relevant and can provide useful insights for the
NZ Power proposal. This is because the IPP procurement and contracting model has
evolved over many years and is an efficient and well understood process in most parts of
the world. We discuss the lessons from the generic IPP model further in Section 5.
The two most similar jurisdictions are Ontario and Brazil
Two of the jurisdictions—Ontario and Brazil—are single buyer models that have much
in common with the NZ Power proposal. Section 3 presents a case study of the Brazilian
power sector, while Section 4 looks at the Ontario power sector in more depth.
While there are similarities in the proposed market structure, it is important to be aware
that the physical features of these three markets differ. For example, while Brazil and
New Zealand both generate the majority of our electricity from hydro, Ontario relies a
lot on nuclear power. These physical features can affect the choice on the most efficient
power sector structure, for example because nuclear power is typically more reliable than
hydro power (which is affected by hydrological conditions). Appendix A summarises the
differences in the physical features of the New Zealand, Brazilian and Ontario power
sectors.
12
3
Case Study of Brazil
This section describes the single buyer model implemented in Brazil. We begin by noting
that Brazil is not a pure single buyer model in the form proposed by Labour and the
Greens. There are three facets of the Brazilian model that differ from the proposed NZ
Power model:
The single buyer does not actually buy and sell electricity—it simply coordinates a central auction process on behalf of the franchise distributor
retailers. In this process, all contracted energy is pooled and each distributor
executes contracts with each generator in proportion to their share of the
pool. The single buyer acts as a broker.
The single buyer only covers 75 percent of the total demand. Customers with
a demand of greater than 3 Megawatts (MW) are free to negotiate bilateral
contracts with generators or retailers. These free customers represent about
25 percent of total electricity consumption; and
The single buyer plays no role in dispatch: there is a spot market for dispatch
with all generators participating.
Despite these differences, there are useful lessons that can be drawn from the way that
electricity is centrally procured in a hydro-dominated system like Brazil.
3.1
Evolution of the Current Model
Until the late 1990s, Brazil’s electricity sector consisted of a series of vertically integrated
and mostly Government owned utilities. In the late 1990s, sector reform saw distribution
companies able to freely negotiate energy supply contracts with generators, and a spot
market was established to coordinate this trading. The distributors were required to
purchase at least 85 percent of their energy through wholesale contracts of at least two
years’ duration. This requirement appears to have been aimed at establishing a
contracting market so that sufficient capacity was available to ensure reliability.
In 2001-2002 large scale shortages of electricity resulted in rationing, with energy
consumption reduced by about 20 percent. This crisis was caused by a number of factors
including2:
Below average rainfall that severely reduced the output from dominant hydro
generation capacity
The market structure, with two large government owned generators, was felt
to inhibit investment in sufficient new generation capacity; and
The short term contracting arrangements were thought to create insufficient
incentives to invest in new generation.
The current industry model in Brazil developed out of this crisis. Initially, a pure single
buyer model was proposed—one of the objectives of this proposed reform was to
capture the “economic rents” of depreciated hydro plants (similar to the stated objective
of the NZ Power proposal). However, analysis of the hydro plants revealed that:
There is no universal agreement as to the contribution of each of these factors to the supply
shortages.
2
13
Studies developed in 1998 proved that there were indeed depreciated power plants in
perfect operating conditions – therefore with economic rent. However, there were also
plants heavily stranded, whose “accounting cost” was as high as US$ 270/MWh. On
the average, the accounting cost, on a full costing basis, for the entire portfolio of
generation plants was about US$ 36/MWh, or very close to the long run marginal
cost of expansion. Therefore, on the average, there was not too much economic rent to be
captured.3
After an analysis of international experience with single buyer models, the current
structure was introduced in 2004 where the single buyer acts as a broker between the
distribution companies and the generators. The model also included separate
procurement and contracting arrangements between existing and new generation. We
describe this in detail in Section 3.3.
Lessons for NZ Power
With the benefit of hindsight, the decision to introduce the current single buyer model
arose largely because the market design introduced in the 2002 reforms was flawed. The
reliance on short-term contracting combined with dominant Government owned
generators created little incentive for the private sector to invest in new generation
capacity. The rationale for the proposed NZ Power model is quite different—focusing
on the perception that retail electricity prices are too high.
Brazil’s experience underlines that establishing the right model for the electricity sector is
not easy, and there are many potential unforseen and unintended consequences.
3.2
Planning
In the Brazilian model, planning for new generation capacity has three steps:
Firstly, each distribution company is required to forecast its captive customer
(primarily residential) load for a 5 year period. These are “net” forecasts in
that distributors can purchase power bilaterally from embedded generators
and small generators for up to 25 percent of their load
Secondly, these forecasts are co-ordinated by an independent body—the
Energy Research Council (EPE). The EPE is responsible for long term
planning in the electricity sector
Thirdly, distribution companies are required to contract with generators for
sufficient capacity and energy to meet their forecasts.
Distribution companies are heavily incentivised to make their demand forecasts as
accurate as possible because they have to contract for generation capacity based on their
forecasts. In other words, there are penalties for over- or under- forecasting the required
electricity generation.
Lessons for NZ Power
Forecasting future electricity demand accurately is a difficult task. No matter who is
responsible for preparing or approving the forecast, there is always a degree of
subjectivity and error. The Brazilian approach to forecasting ensures that the party
responsible for the forecast bears the cost if the forecast is inaccurate.
3
Centralized Purchasing Arrangements: International Practices and Lessons Learned on Variations to the Single Buyer Model, World
Bank, March 2006
14
This approach clearly incentivizes distributors to forecast as accurately as possible
because distributors directly suffer the consequences of forecast error. In this way, the
Brazilian approach overcomes the usual problem of centrally planned forecasts where the
planner bears no real consequences for the forecast. In contrast, if NZ Power contracts
for more power than is actually needed due to inaccurate forecasts, then additional costs
will be passed on to customers (or taxpayers through NZ Power). Alternatively, if NZ
Power under-forecasts—leading to a shortfall in generation capacity—then reliability
standards will fall and customers will be exposed to blackouts. This is likely to be more
damaging to NZ Power than the additional cost of contracting for more capacity than
needed. As a result, the incentive for NZ Power—and any central planner—is to be
conservative and over-forecast demand.
The Brazilian approach to managing the risks of under- or over- forecasting demand
would be difficult to apply in jurisdictions like New Zealand that have a competitive
retail market. The approach works in Brazil because distributors are franchise monopoly
retailers, which means that the task of forecasting relates to the entire consumption
within a particular geographic area. In a competitive retail market, retailers would not
only have to forecast the average demand of existing customers, they would also need to
forecast their market share and customer composition up to 5 years in advance.
This type of long term forecasting in a competitive retail market is carried out
successfully in capacity markets—see Section 6. However, in these markets the capacity
commitments made by retailers are freely tradeable. This is not a feature of the
arrangements in Brazil, where retailers are committed to contract for their forecasts and
have only limited opportunities to adjust those positions.
3.3
Procurement
The process for electricity procurement in Brazil differs depending on:
The size of the customer: customers consuming more than 3 MW are
allowed to procure their electricity supply on what is termed the “free”
market—that is outside the single buyer arrangements. Customers consuming
less than 3 MW are known as “captive customers” because they do not have a
choice of supplier (they must be served by their local distribution company).
Local distribution companies are required to procure electricity supply
through regulated auction markets; and
Whether the generation comes from an existing or from a new plant.
When new generation capacity is required the national regulator, the National
Electric Energy Agency (ANEEL), runs auctions for a set number of MW in a
certain location. Potential generators bid into this auction, competing on price.
Figure 3.1 distinguishes between the main methods for procuring electricity supply in the
Brazilian system. The functioning of regulated and free markets is explained in more
detail below the figure.
15
Figure 3.1: Methods of Procurement in the Brazilian Electricity Sector
“Free” Market
In the free market, the purchase and sale of electricity through bilateral contracts is
undertaken with conditions, prices and quantities freely negotiated between generators,
traders and customers.
Free market customers need to be contracted for 100 percent of their energy
consumption and are subject to penalties for failing to maintain sufficient cover. The
costs of being under- or over- contracted arise because any differences are settled in the
weekly balancing market—see Section 3.4.
Regulated Market
Three quarters of all electricity is procured through the regulated market. There are five
main players in the regulated market:
The Energy Research Council (EPE)4 determines where and when new generation
is needed. This is done on the basis of the demand forecasts from the
distribution companies (as explained in Section 3.2). In other words, EPE
decides when to run an auction for new generation capacity. It determines the
type, size, location and technology of this new generation.
The Energy Commercialization Chamber (CCEE) runs the auctions. The objective
of these auctions is to provide the lowest possible price of electricity for
captive customers.
ANEEL regulates and supervises all electricity supply services in the country
including oversight of the procurement process.
Regional distribution companies are required to contract supply for their regulated
customers through regulated auctions—they are the counterparties to
generation contracts co-ordinated by the single buyer.
Generation companies bid into these auctions to sell their available generation
capacity under long term contracts.
Procurement is conducted through “regulated auctions”. There are two main types of
auctions—for energy generated from existing (or “old”) capacity and for energy
generated from new capacity. “Old” capacity is procured for shorter contract terms with
a shorter lead time than new capacity (see
4
EPE is coordinated by the Ministry of Mines and Energy (MME)
16
Table 3.1).
There are also “adjustment” auctions for 1 to 2 year contracts with delivery 4 months
ahead. These auctions allow distributors to revise their contracted positions. This
adjustment process only allows distributors to adjust their positions if their forecasts are
wrong. The other mechanism for rebalancing distributor supply and demand is the
weekly balancing market, which is more costly and risky because prices are more volatile.
Table 3.1: Characteristics of “Old” and “New” Energy Auctions
Old Capacity
New Capacity
Adjustment Auctions
Desired basis for price
from regulator’s point of
view
Short run
marginal cost (as
assets should be
fully depreciated)
Long run marginal
cost (as prices
cover fixed and
variable costs)
Opportunity cost (what else
you could do with the
energy if not sold through
an adjustment contract)
Contract Term
5-8 years
15 years
1-2 years
Delivery date
One year ahead
3-5 years ahead
4 months ahead
Number of Auctions
held since December
2004
10
12
9
Old capacity is never eligible to participate in new energy auctions. However, if owners
of old capacity do not sell their capacity in the old energy auctions, they are allowed to
sell to large customers on the free market. New capacity can participate in the old
capacity auctions after the expiry of their initial 15 year contracts (or can choose to sell
their energy to large customers on the free market).
The procurement process for both old and new energy starts with a reverse price auction.
The EPE sets a starting price that is designed to create excess supply. Generators bid in
the quantities (MWh) that they are willing to supply at the stated price. EPE then reduces
the price, and generators bid in quantity they are willing to supply at the lower price. The
EPE continues to drop the price until there is no more excess supply. The outcome of
this auction effectively sets the price cap for long term contracts.
In auctions for new energy, generators are allowed to negotiate prices with distributors
following the reverse auction. The negotiated price may not exceed the final price in the
reverse auction.
In contrast, the reverse auction for old energy is followed by a second round of bidding.
Instead of using a reverse auction (where the regulator sets price and the generators bid
quantities), the second round involves a single pay-as-bid auction (where the regulator
sets a quantity, and the generators bid prices). The regulator sets a quantity that is
deliberately below the capacity that was successful in the reverse auction to create
competition for the remaining generators to bid low prices. Generators make a single bid
to supply quintiles of their generation at different prices. The regulator then selects the
cheapest combination of bids to meet the capacity required.
Difference between “old” and “new” energy prices
The auctions have resulted in some differentiation between the prices paid for existing
and new capacity, as shown in Table 3.2. New generation is roughly a third more
expensive than old generation. This was clearly intended as a way to ensure that old
capacity (such as hydro plants that were built many years ago) did not receive the price
paid to the developers of new capacity (such as thermal plants with higher running costs).
17
Table 3.2: Average volume and prices of regulated market contracts (2004 to 2012)
Auction Type
Average volume
(MWh)
Average Price
$US/MWh
No of contracts
Existing (“old”) generation
19,987
$45.46
1,612
New generation
22,478
$61.90
6,728
900
$74.05
1,146
Reserve generation
2,189
$72.83
176
Total
45,554
$59.17
9,662
Renewable generation
Source: Castalia from “Evolution of Global Electricity Markets”, Fereidoon P. Sioshansi (ed), pp350
While there is still a significant difference between “old” and “new” energy prices, there
has been considerable convergence between prices since the market was first introduced
(see Figure 3.2). New energy prices have stayed reasonably constant at around US$54 per
MWh. This aligns with the expectation that competition to supply new energy will keep
auction prices at the system long run marginal cost, which is likely to be relatively
constant. However, prices for “old” capacity have been steadily rising.
Figure 3.2: Convergence in “Old” and “New” Energy Prices
Source: “A Perspective of the Brazilian Electricity Sector Restructuring: From Privatization to the New
Model Framework”, Melo, de Almeida Neves, Da Costa, Correia
The convergence between old and new energy prices has given rise to the claim that the
owners of “old” assets are making excess profits. In economic terms, these firms are
alleged to capture the “infra-marginal rents” between the short run costs of operating
(hydro) plants, and the long run marginal cost of new forms of electricity generation.
18
In response to these concerns, in 2012 the Brazilian government pledged to reduce
residential electricity prices by around 20 percent. To reach this target, the Government
has intervened in the market for “old” energy to push prices back to the short run cost
of operating existing plants. The Government has decided to set old energy prices at a
reference point that allows for operations and maintenance costs, plus a 10 percent
margin, and has made the renewal of operating licenses contingent on existing hydro
generators signing new contracts at these lower prices. Existing generators that do not
want to accept this lower price must hand their assets over to the Federal government.
This somewhat radical intervention is less controversial than it would be in New Zealand
because hydro plants in Brazil are almost exclusively owned by the State and Federal
Governments.
Lessons for NZ Power
Brazil’s attempt to achieve different prices for “old” and “new” energy holds some
important lessons for New Zealand.
Brazil’s experience suggests that regular government intervention is needed to keep “old”
energy prices lower than “new” energy prices. Initially, the Government tried to lower
the price of generation from existing plants by creating an artificial surplus of capacity in
the auction. However, this illusory surplus capacity was eroded over time as more and
more generators sought out the higher prices for their output on the free market (serving
industrial customers). In a country like Brazil with significant electricity demand growth,
imposing an artificial sense of surplus capacity is highly unlikely to work.
Owners of existing capacity in repeated auctions will respond to the rules of the game to
maximise their returns. In Brazil, existing generators that did not sell through the
regulated auction were able to contract with customers on the free market. These
customers were willing to pay generators higher prices than were achieved through the
auction. As a result, existing generators had less interest in participating in the next
auction for “old” energy and resulting prices were higher. Subsequent auctions for old
energy have accentuated this trend—with more energy sold on the free market, and less
competitive tension in the regulated auction.
Despite the attempt to separate prices for “old” and “new” generation, Brazil’s
procurement process is also unlikely to consistently lead to the lowest cost generation
capacity for two reasons:
For new capacity, the contract term is significantly less than the economic life
of the asset. This creates a revenue risk for the owners of generation: at the
end of their first contract, the private firm has to re-auction the asset in the
regulated market for existing capacity (where the ceiling price is set by the
Government). This would likely see investors seeking to recover the full
capital costs of the investment over the shorter new contract period, with any
cost recovery after that period representing an economic gain.
As shown in Table 3.1, generation assets that were already operating when this
auction based procurement model was introduced in 2004 do not receive new
entrant prices as a result of the price ceiling on short term contracts. This may
mean that investors are not receiving a commercial return on their investment.
Because most of the existing generation is owned by either the Federal or
State Governments, this may not be seen as a serious issue in Brazil. However,
the impact on existing investors and any resulting chilling effects for new
investment would be an issue for the NZ Power proposal.
19
One positive feature of the Brazilian auction market that might help to reduce prices is
using a reverse price auction for a total number of MW (procuring a “portfolio” of
generation capacity, rather than requiring all the capacity from a single plant). The
auction process ranks projects by cost and selects a portfolio needed to meet the capacity
need.
3.4
Dispatch
Brazil uses a hybrid system to dispatch generation consisting of elements of both central
control and market pricing. The central control element is used to dispatch electricity
from hydro generation assets through an optimisation model. Market pricing is used to
dispatch thermal generators.
The hydro dispatch optimisation model takes into account forecast demand, reservoir
levels, expected inflows and the Value of Lost Load (VOLL). The model aims to
minimise the use of thermal generation, and therefore the cost of fuel. Hydro generation
accounts for almost 80 percent of generation, and the difficulty in valuing water is seen
as a major reason for using an optimisation model for water, rather than a market based
approach that relies on generator bids.
Brazil uses a spot price market to balance any power that is not dispatched under long
term contracts. Figure 3.3 shows the interaction between long term contracts for
capacity, and the spot market:
First, all long term contracts for power supply are fulfilled
Then, any excess is cleared through the spot market. For example, in Figure
3.3, generator A has generated 110 MW, but is only contracted for 100 MW.
This generator provides the 100 contracted MW at the price specified in the
long-term contract. The generator is then able to sell the extra 10 MW on the
spot market to Distributor Y, who presumably has a consumption of 10 MW
more than provided under its long-term contracts.
Figure 3.3: Link between Procurement and Dispatch in Brazilian Power Sector
20
The spot market in Brazil is run on a weekly basis: any additional power traded within a
given week is settled at the same price. Having a weekly average price clearly blunts price
signals. If a generator has extra capacity at peak times, then they receive the same price as
a generator who has extra capacity at off-peak times, even though extra generation at
peak times is more valuable.
The spot market is regulated, with a floor price set as the operations and maintenance
costs of hydro generators and a ceiling of the highest cost thermal generator.5 While the
spot price is therefore quite artificial, it does not have major financial impacts because all
loads and generation is fully contracted. The role of the spot market is, therefore, only to
balance out any differences between the fixed contract levels and actual consumption.
Lessons for NZ Power
The Brazilian dispatch process is a mix of cost based market dispatch for thermal
generators with an optimisation model for the hydro plants. The model aims to set an
appropriate value for water—given limited storage—and to optimise situations where
chains of hydro stations exist on one water source with multiple owners.
Both of these are problems are faced in New Zealand. In many ways, the Brazilian
dispatch process is the same process employed by ECNZ and its predecessors before the
wholesale market was established in 1996. This illustrates that the centralised dispatch of
hydro assets is not a guarantee against dry year shortages.
The key issue in dispatch is to achieve an appropriate risk allocation—dispatch by a
centralised body may be able to optimise many variables, but may or may not be superior
to more limited optimisation carried out by multiple parties that actually face the financial
consequences of their decisions.
3.5
Retail Sales
Electricity retailing in Brazil is carried out by around 50 distribution companies, each of
which have a regional monopoly over customers consuming less than 3 MW. In addition,
retailers are able to compete for large customers: a quarter of the market (by
consumption) that has no interaction with the regulated “single buyer”.
Lessons for NZ Power
A key component of the Brazilian single buyer model is the non-competitive retail
market. This makes the forecasting process somewhat incentive-based for distributors,
but also limits its applicability to New Zealand.
The single buyer model is not used for large customers, who are free to negotiate supply
with generators on individual terms and conditions. This accounts for 25 percent of the
market, and since participation is voluntary this suggests that many large customers
believe they can purchase energy on better prices, terms and conditions than those
available through the single buyer. We note that the business community in New Zealand
has expressed concern about the single buyer model.
5
There is some regulatory oversight of the thermal generators costs
21
4
Case Study of Ontario
This section describes the single buyer model implemented in Ontario. This case study is
particularly relevant to the NZ Power proposal because it shares many of the features of
the model proposed by Labour and the Greens. Ontario is also the only jurisdiction that
has reverted back to a more centrally controlled electricity supply after having
implemented a wholesale market (albeit for a much shorter period of time than in New
Zealand).
4.1
Evolution of the Current Model
Until 2002, Ontario’s electricity sector was structured as a single provincial government
owned utility (generation, transmission and rural distribution) and 300+ municipally
owned distribution utilities in urban areas. There were some independent generators
supplying the distribution utilities. In 2002, the vertically integrated utility was split into
three separate companies—generation, transmission and rural distribution and a system
operator. The monopoly elements were regulated and a competitive wholesale market
was established. The resulting generation company, Ontario Power Generation (OPG)
owned around 90 percent of the total generation capacity.
Prices in the wholesale market rose sharply after these reforms, doubling in the first few
months of the market’s operation. There were a number of possible reasons for this price
rise, including an especially hot summer, a reduction in domestic generating capacity, and
an increasing reliance on limited capacity to import power from neighbouring states in
Canada. Most residential customers were exposed to this volatile and rising spot price.
Residential consumers (who are also voters) voiced concerns to politicians about the
impacts of these price rises, and the wholesale market in Ontario was closed after only
six months. A retail price freeze was imposed—and the current single buyer model was
developed and implemented in 2004.
There were two major flaws with the way that the wholesale electricity market in Ontario
was introduced:
Small retail customers were exposed to spot prices without any transitional
arrangements or protection from price volatility. This was clearly
unsustainable and destined to cause political problems
Creating a wholesale market when 90 percent of the generation was in the
hands of one party was always going to create difficult market dynamics.
Furthermore, because the dominant party was the previous government
owned monopoly generator (OPG), this would likely have inhibited private
sector entry into the generation market. We note that OPG still controls
around 70 percent of Ontario’s generation capacity.
Lessons for NZ Power
In a similar manner to Brazil, the single buyer market in Ontario resulted from a failed
market reform process. Again, like Brazil, the market had serious design flaws including
exposing residential customers to spot prices and having a dominant Government owned
generator. Both Ontario and Brazil’s experiences with sector reform underline that
establishing the right model for the electricity sector is not easy, and there are many
potential unforseen and unintended consequences.
The relationship between electricity reform and electoral politics in Ontario is also
relevant. The wholesale market in Ontario began life shortly before a State government
election. Wholesale market prices could then be used by the political opposition party to
22
point to failures in the existing arrangements, and propose an alternative to “solve” the
issues. In much the same way, the NZ Power proposal in New Zealand comes from a
political desire for change, rather than from government officials or industry.
4.2
Planning
Planning for new generation capacity is centrally controlled in Ontario. The single
buyer—the Ontario Power Authority (OPA)—is responsible for all forecasting and
planning. To quote from its website:
The Ontario Power Authority develops integrated electricity plans that look forward
several years, with the purpose of providing sustainable electricity solutions to
Ontarians well into the future.
The plans take a long-term, province-wide perspective, examining possibilities for future
electricity demand and how it can be met through conservation, generation and
transmission options. The aim is to enable the electricity system to meet technical
standards and public policy objectives in ways that are acceptable to the community.
These plans form the technical basis of the advice the OPA provides to government to
inform policy priorities, including:
• making Ontario efficient in its use of electricity;
• phasing out the use of coal;
• increasing renewable energy sources; and,
• deploying information and technology to improve customer service.
The OPA therefore acts as a central planner with responsibility for electricity demand
forecasting. OPA then prepares a 20 year plan for generation and transmission to meet
those forecasts, and ensures that adequate generation is contracted through the
procurement process. The OPA also provides broader advice to the Government on
energy policy.
Lessons for NZ Power
The OPA is accountable to the Government to ensure adequate, reliable and secure
electricity supply. Its legislation sets out the following objectives:
1) To forecast electricity demand and the adequacy and reliability of electricity resources
for Ontario for the medium and long-term.
2) To conduct independent planning for electricity generation, demand management,
conservation and transmission and develop integrated power system plans for Ontario.
3) To engage in activities in support of the goal of ensuring adequate, reliable and
secure electricity supply and resources in Ontario.
4) To engage in activities to facilitate the diversification of sources of electricity supply by
promoting the use of cleaner energy sources and technologies, including alternative energy
sources and renewable energy sources.
5) To establish system-wide goals for the amount of electricity to be produced from
alternative energy sources and renewable energy sources.
6) To engage in activities that facilitate load management.
7) To engage in activities that promote electricity conservation and the efficient use of
electricity.
23
8) To assist the Ontario Energy Board by facilitating stability in rates for certain types
of customers.
9) To collect and provide to the public and the Ontario Energy Board information
relating to medium and long term electricity needs of Ontario and the adequacy and
reliability of the integrated power system to meet those needs.6
It is also subject to direction by the Minister for Energy. Directions have been issued to
OPA to procure power through standard offer and feed in tariff arrangements.
OPA’s clear responsibility to ensure adequate, reliable and secure electricity supply and
there is no mention of least cost. These obligations are likely to create incentives for over
capacity, rather than under capacity of generation. Given that the responsibilities of NZ
Power are very similar to the OPA, we would expect the same dynamic to play out in
New Zealand if the proposed reforms are implemented.
4.3
Procurement
The OPA procures capacity differently depending on whether it was in use at the time of
the 2004 reforms, or whether it has been procured since. The OPA also uses different
procurement methods depending on the type of generation that is being procured (see
Figure 4.1).
Figure 4.1: Methods for Procuring New Generation Capacity in Ontario
Existing generation owned by OPG (the stated owned generator) is contracted at
regulated prices. Existing generation owned by private parties is contracted through long
term PPAs.
The OPA procures new capacity through three basic mechanisms, depending on the type
of capacity being procured:
For small scale renewable and cogeneration projects, OPA has standing offers
of standardised contracts with Feed In Tariffs (FIT). These are technology
6
From “The Electricity Restructuring Act”, 2004
24
specific and are based on the cost of the technology—for example wind
$115/Megawatt hours (MWh) and roof top solar $549/MWh7
For unique situations (particularly for renegotiating contracts for OPG’s large
nuclear power stations), OPA conducts sole source negotiations; and
For large-scale new capacity, OPA runs a competitive tender process starting
with a Request for Proposal (RFP).
The competitive tenders are generally technology specific, but are not limited to a certain
size. For example, in 2004 the OPA issued a RFP to tender for 2,500 MW of new
capacity that could not be oil or coal fired. The tender accepted offers of all sizes; ranked
them in cost order and selected a number of projects that accumulated to 2,500 MW.
That tender utilised a location adjustment to try to encourage generation in appropriately
unconstrained areas of the transmission system. That approach was not seen as a success,
and later tenders have tended to specify location (at least broadly). For example, in 2008
the OPA issued a RFP for “up to approximately 850 MW of generation in the South
West Greater Toronto area”. That need was met by a single gas fired plant.
No RFPs appear to have been issued since 2009. This is partly due to falling demand for
electricity in Ontario in the past few years following the global financial crisis, and partly
because of the additional renewable generation capacity added through the various
standing offer programs. There have also been capacity increases at OPG nuclear
stations that were directly negotiated.
Lessons for NZ Power
There are aspects of the OPA procurement process that could be incorporated in a
successful single buyer model and would lead to lower costs such as procurement
through a competitive tender process that uses long term contracts that match the
economic life of the assets to acquire a portfolio of projects.
However, the key lessons from the procurement are:
It is very difficult to manage location factors and the costs imposed through
transmission augmentations in an open tender process—that is to co-optimise
location, transmission and generation. While mechanisms such as locational
incentives may help the process, the OPA experience shows that this will
always involve a degree of central planning and prescription.
While technology neutral procurements are likely to result in lower costs,
central procurement can lead to carve outs that lower overall competitiveness
and efficiency. Through these mechanisms the OPA has implemented
Government objectives such as the phase out of coal and increased use of
renewable energy more easily than would be possible in a market but with less
transparency about the cost.
4.4
Dispatch
Dispatch in Ontario is determined through a spot market. The spot market is run by the
Independent Electricity System Operator (IESO), with generators offering capacity and
price every 5 minutes.
The spot market in Ontario is similar to the one currently operating in New Zealand. In
New Zealand, retailers and generators use long term financial contracts to hedge against
spot market price fluctuations. These contracts agree a strike price per Kilowatt hour
7
Rates are higher for projects with aboriginal or community participation
25
(kWh). If the spot price is above the contracted strike price, then the generator pays the
retailer the difference. If the spot price is below the contracted strike price, then the
retailer pays the generator the difference. This is similar to the interaction between long
term contracted prices and spot market prices in Ontario (see Figure 4.2).
Figure 4.2: Role of Long Term Financial Contracts in Ontario
Price
(cents per kwh)
Spot price on
day 2
Day 2:
Generator pays
retailer the
difference
Contracted long
term price
Day 1:
Retailer pays
generator the
difference
Spot price on
day 1
Day 1:
spot price below
contracted price
Day 2:
spot price above
contracted price
In Ontario, the OPA has long term contracts with generators based on net monthly
revenue requirements. Generators also state a monthly energy cost. At the end of each
month, the amount that the OPA pays to each generator is calculated in two steps:
Firstly, OPA calculates the spot market price for all periods where the spot
price exceeds the generator’s stated energy cost. This incentivises the
generators to be accurate in stating their energy cost, and to bid into the spot
market at their energy cost
Secondly, this spot market revenue is deducted from the monthly net revenue
requirement and the balance is paid to the generator. If the generator earns
more on the spot market than their stated monthly revenue requirement, they
are only allowed to keep 5 percent of this excess (the remaining 95 percent
surplus is kept by the OPA).
The main goal of this payment structure is to incentivise the generators to be available
for dispatch. It assumes that a generator will run when the spot market price exceeds
their stated energy cost.
Lessons for NZ Power
The dispatch process used in Ontario is aimed more at providing incentives for
generators to be available than necessarily ensuring least cost dispatch. The process
ensures that all contracted generators will bid at the contracted short run marginal cost so
that they will be dispatched and earn their deemed market revenue. This is efficient only
to the extent that the contracted short run marginal cost represents the generator’s actual
short run marginal cost in each and every dispatch interval.
26
The approach to dispatch in Ontario is the main area that is quite different from the NZ
Power proposal. NZ Power will be given the power to dispatch plants based on a
centrally determined order of priority, and has the ability to call on plants for dispatch.
The approach in Ontario is thus more market based and is similar to the current New
Zealand wholesale market with the exception that dispatch occurs on the basis of a
generator’s contracted short run marginal costs rather than generator offers. The Ontario
approach of cost based dispatch would not be appropriate in a system like New Zealand
where the dominant generation is hydro with almost zero marginal cost but with water
availability constraints. In such a system, water needs to be valued explicitly—in a
market—or implicitly—in a central optimisation process—to ensure efficient dispatch.
4.5
Retail Sales
Ontario’s retail market is divided into two sections:
Small customers (including all residential customers and small business
customers) who are served by retailers
Large customers (including all commercial and industrial consumers and large
business customers) who can buy directly from the OPA.
Both of these groups pay regulated tariffs. Tariffs are set at the OPA’s average wholesale
price. The average wholesale price reflects:
Average spot market prices
The regulated rates paid to OPG’s nuclear and hydroelectric base load
generating stations
Payments made to suppliers that have been awarded contracts through the
OPA such as new gas-fired facilities, renewable facilities (like wind farms) and
demand response programs; and
Contracted rates administered by the Ontario Electricity Financial
Corporation paid to existing generators.
Figure 4.3 shows a comparison of retail electricity prices in Ontario and New Zealand
over the last 10 years.
27
Figure 4.3: Comparison of Retail Electricity Prices in Ontario and New Zealand
Note: Prices indexed to 2003 prices
These are real prices—that is, the impact of the different inflation rates in each country
has been removed. Ontario’s demand for electricity has fallen by about 10 percent since
2005. The price rises from 2008 represent the costs of phasing out coal fired generation
and the continued uptake of renewable energy. The combination of falling demand and
increased capacity has seen Ontario’s reserve margin reach 48 percent in 2012.
Lessons for NZ Power
Ontario’s retail prices have risen and continued to rise under the single buyer model
largely because, while demand has been falling, additional generation has been procured.
While it is clear that much of this additional generation has been driven by environmental
objectives, some rise may also be due to the primary objective of the OPA to ensure
adequate, reliable and secure electricity supplies.
The key lesson for NZ Power is to ensure that the central buyer is simultaneously
accountable for both reliable supply and at the least cost. Since reliability is easy to
measure and least cost is not easy to measure (due to the absence of an obvious
counterfactual), it’s much more difficult to ensure that the single buyer is held
accountable for a least cost outcome.
A further lesson from Ontario is that in a single buyer model, the scope for large
customers to benefit from competition between retailers is limited by the fact they all pay
the same wholesale price. A similar issue will arise under the NZ Power proposal, where
competing retailers all face the same wholesale price. The only area to compete on is
customer service: the good they are selling (electricity) does not vary in quality or price.
28
5
Case Study of Vertically Integrated Electricity
Sectors with Independent Power Producers
(IPPs)
Many jurisdictions have some form of vertical integration combined with IPPs. From the
list put forward by Labour and the Greens, this includes India, Indonesia, Mexico,
Malaysia, Pakistan, South Africa and Vietnam. Many other countries could be added to
this list. Obviously there are a number of country specific nuances in the specific design;
however most of these jurisdictions have the following features in common:
Planning is run by a central agency—usually the utility—who forecasts
demand, rather than relying on market signals
Procurement of new generation is normally run by the vertically integrated
utility. Often the vertically integrated utility builds and owns certain generation
projects, and tenders out other generation projects to private parties. The
tender process is normally competitive, with private firms competing to
supply a certain amount of electricity over a certain time period. Electricity
supply is governed by long term Power Purchase Agreements (PPA) whose
term matches the economic life of the generation asset
Dispatch of generation is normally controlled by the vertically integrated
utility. IPPs are indifferent about whether they are dispatched or not, due to
capacity payments that cover all fixed costs under the PPA
Retail is normally controlled by a vertically integrated utility, either with a
single national retailor, or with regional monopoly retailers. In certain
countries, retail competition is allowed for large industrial and commercial
consumers, who are allowed to buy electricity directly from IPPs.
5.1
Evolution of Current Market
Most countries in the world developed their electricity sectors through a vertically
integrated state owned utility with responsibility for planning, procurement, dispatch and
retail. Many countries in the world have retained that sector structure. Introducing
private participation in electricity generation is typically the first step in the process of
electricity sector reform: the vertically integrated state owned utility retains control over
transmission and retail. We examine this sector structure in more detail to understand the
role of the “single buyer” in this market structure.
Figure 5.1 shows four common steps in electricity sector reform internationally.
Introducing competition for generation is generally the first step away from full vertical
integration. After this, a common next step is to break up the vertically integrated
company into separate divisions (focusing on generation, transmission and distribution).
Often these separate divisions are partially or fully privatised at the same time. These
sector reform steps often (but not always) lead to the establishment of a competitive
wholesale electricity market. This is sometimes accompanied by the introduction of retail
competition. New Zealand is one of a number of countries, including Australia, Great
Britain, most European Union counties, and some states in the United States that have
achieved a competitive wholesale electricity market with full retail competition—that is,
where even the smallest customer has a choice of retailer.
29
Figure 5.1: Common Steps in Electricity Sector Reform Overseas
Fully vertically
integrated state
owned utility with
no private
participation
Vertically
integrated state
owned utility with
private
participation in
generation
State owned
enterprise broken
up and/ or partially
privatised
Introduction of
retail competition +
some form of
wholesale market
(New Zealand
currently)
Lessons for NZ Power
Although not unheard of (as shown by the case of Ontario), it is unusual to move back
from a competitive wholesale electricity market to a single buyer model. Many countries
are currently trying to reform their electricity sectors the other way—from a model with a
single buyer to one with a competitive market. For example, even in Africa where the
push for sector reform has been relatively gradual, countries such as Nigeria and Kenya
have recently split up their state owned utilities into generation, transmission and
distribution companies and partially or fully privatised their sectors. It is important to
understand the reasons that most countries choose to move towards a more market
based system, lessening the role of a single buyer.
As the experience in Ontario (and to a lesser extent Brazil) shows, some jurisdictions do
“wind the clock back”. However, it is important to recognise the trade-offs that exist
between a market based system, and a centrally controlled system.
5.2
Planning
In vertically integrated markets with competition for generation, planning for new
capacity investments is done centrally (as proposed in the NZ Power model).
Responsibility for planning can be given to the utility (for example in Indonesia), a
government ministry (for example in Tanzania), or the regulator (for example in Kenya).
The planning organisation will develop demand forecasts to determine when and where
new generation investments are needed.
Lessons for NZ Power
Accurately forecasting demand is a difficult task. Demand for electricity is affected by a
wide range of factors, with the main determinants being economic growth (which fuels
commercial and industrial growth as well as growth in demand per customer) and
population growth (which fuels growth in the number of residential customers). It is
difficult to project these variables accurately enough to determine the most cost effective
time and location to invest in new electricity generation.
30
One of the main strengths of wholesale electricity markets like New Zealand’s is that
they replace the centralised planning function that is found in markets with vertical
integration and IPPs: prices signal where new generation is needed. When demand peaks
in certain parts of the grid, supply is constrained so the spot price increases. New
Zealand’s nodal pricing system also sends important signals as to where new generation
investment is needed most (and where it will likely earn the highest return).
5.3
Procurement
In vertically integrated markets with competition for new generation, procurement is
generally controlled by the vertically integrated utility. This is because the vertically
integrated utility will be the counterparty to the PPA. Other organisations (such as a
government Ministry or independent regulator) will often provide some oversight of the
procurement process to ensure that consumers end up paying no more for power than is
necessary.
Broadly, there are three options for procuring new generation capacity:
Self-build: in most countries with a vertically integrated utility and
competition for generation, the vertically integrated utility will build and own
generation assets. So when new build opportunities are identified, the utility
(or sometimes the Ministry or regulator) needs to decide whether the utility
will build the new capacity, or whether a private party will build the capacity.
South Africa has established a guide that at least 30 percent of new generation
must be built by private parties, with the remaining 70 percent left to the
vertically integrated utility, ESKOM
Unsolicited bids: in some situations, vertically integrated utilities will be
approached by private parties with a proposal to build a new generation
facility. These approaches are known as unsolicited bids, because the utility
did not solicit bids through a competitive tender process. In most countries,
unsolicited bids are closely scrutinised by the sector regulator to ensure they
offer value for money. Some countries forbid unsolicited bids altogether
Competitive tenders: in most countries, generation that is not built by the
vertically integrated utility is competitively tendered out to private bidders.
The utility will normally identify the location and capacity required, and
private firms will bid on a price for building such a plant.
Both unsolicited bids and competitive tenders will require the utility to negotiate a PPA
to purchase electricity over a defined timeframe for a defined price.
Structure of Power Purchase Agreements
PPAs have a well-defined structure, as shown in Figure 5.2 below.
PPAs are long term contracts, normally for the useful life of the asset. This varies by
technology: thermal plants normally have a useful life of around 25 to 40 years, whereas
hydro assets can function for much longer time periods with appropriate maintenance.
PPAs have a typical allocation of risk:
Demand risk is borne by the buyer (as would be the case under the NZ
Power model). In other words, the buyer contracts to purchase a certain
amount of electricity, independent of whether demand actually exists for this
electricity. This allocation of risk makes sense because the private party has no
control over whether or not their generation asset is dispatched
31
Fuel price risk is almost always borne by the buyer. This means that changes
in fuel costs—such as coal or gas—are passed through to the buyer under the
PPA. In some cases, the buyer is directly responsible for procuring the fuel—
meaning that the PPA effectively provides a tolling arrangement for use of the
generation asset
Inflation and foreign exchange risk. Again, this risk is almost always borne
by the buyer through escalation provisions in the PPA
Technical generation risks are always borne by seller (the private party),
who is best able to control whether the plant is appropriately designed and
functioning properly. The private party bears technical risks up until the point
where electricity is injected into the grid: beyond that point, the vertically
integrated utility is normally responsible for risks such as overloaded
transformers or damaged lines.
PPAs have a typical payment structure that is based on two types of payments:
Capacity charges: cover the fixed costs of the plant, including all capital
costs and fixed operations and maintained costs. This payment is made so
long as the plant is available to be dispatched.
Energy charges: cover the variable costs of the plant including fuel costs and
all variable operations and maintenance costs. This payment is made only if
the plant is actually dispatched.
Figure 5.2: Key Features of Power Purchase Agreements
Contract length: matches the useful life
of the asset (such as 25-40 years for
thermal assets)
Risk allocation: utility takes demand risk,
fuel price risk and foreign exchange risk;
private party takes design, construction
and operation risks
Payment structure: private party paid
“capacity payment” to cover fixed costs
and “energy payment” to cover variable
costs
The combination of the risk allocation and the payment structure means that IPP
projects are relatively low risk. In most cases, this means that IPPs are able to be project
financed—which typically involves a high level of debt leverage and means that lenders
do not have recourse to forms of security other than the asset that is built. Ultimately,
these arrangements aim to make the cost of generation very low by ensuring that returns
to the power station’s investors only need to compensate them for taking a moderate
level of risk.
32
However, this low price comes at a cost because many of the normal risks taken by
investors in new generation in other sector structures (such as the need for capacity, fuel
costs and inflation) have been allocated to the buyer. This means that the price of
purchasing power from IPPs can be deceptively alluring: to have an apples for apples
comparison with other ways of procuring new generation the price needs to be adjusted
for the risks that are being taken by the buyer.
Lessons for NZ Power
Procuring new capacity by running competitive tenders should achieve efficient costs as
long as:
The capacity being procured is needed (the planning process correctly
identifies the size and location of new generation need)
There is sufficient competition (two or more technically capable firms place
bids that reflect efficient costs); and
The PPA contract is well designed (resulting in a contract for the economic
life of the assets that appropriately allocates risk, and contains a payment
mechanism that reflects competitive energy and capacity charges over the life
of the contract).
5.4
Dispatch
In vertically integrated markets with competition for generation, dispatch is controlled
centrally. Due to the structure of PPA payments, private generators are indifferent to
whether they are dispatched or not. If they are not dispatched, their costs are covered by
capacity charges. If they are dispatched, the additional costs of running the plant are
covered by energy charges.
The central agency needs to determine the merit order in which to dispatch available
generation plants. Its goal is to minimise the cost of electricity to customers, given the
long term PPAs they have signed up to. Merit order is normally determined by the energy
payments under each PPA, with the plants with the lowest energy charges dispatched
first.
The central agency must dispatch plants within the system constraints. This may include
constraints on the transmission and distribution systems, as well as constraints on hydro
storage. Dispatching hydro plants effectively can be hard to model, as the central agency
needs to factor in not just current dam levels, but likely rainfall in the catchment over the
coming months. In some countries, dispatch of hydro plants also needs to consider the
impact on other water users such as agriculture, industry and consumers.
Lessons for NZ Power
Dispatch according to energy charges is only efficient if the PPA payment structure
accurately reflects the fixed and variable costs of generation. Because PPAs last for many
years, it is important that capacity and energy charges are appropriately reviewed over
time. This is achieved through fuel cost pass through, indexation for inflation and
sometimes for foreign exchange changes. It is also important that the PPA payment
structure creates incentives for the generator to reduce costs where possible. For
example, a gas fired plant owner should have an incentive to renegotiate fuel contracts
over time. These incentives are hard to create with fuel price pass through provisions, so
the contract needs to share of benefits of renegotiation between the buyer and the seller.
33
Due to New Zealand’s reliance on hydro power generation, NZ Power has the somewhat
unusual challenge of ensuring that the approach to dispatch optimises the use of water
storage to avoid black outs in dry years.
5.5
Retail Sales
In vertically integrated markets with competition for generation, the bulk of the retail
market is not normally competitive. Rather there is normally either a single national
retailor (as in South Africa or Indonesia) or a series of regional monopoly retailers (as in
India and Japan).
Some jurisdictions do have competition for some larger commercial and industrial
consumers. Consumers who meet certain conditions are allowed to negotiate directly
with generators for their supply. These conditions normally relate to the size of their
consumption: the rationale being that, if customers are large enough, they have enough
negotiating power to achieve reasonable power prices.
Table 5.1: Four Main Types of Retail Markets in Jurisdictions with Vertically
Integrated Markets
Number
Single national
of retailers retailer
Regional monopoly
retailers
All customers
Small residential customers
Indonesia, South Africa
Rwanda
India, Japan
Ontario, Brazil
Lessons for NZ Power
Vertically integrated markets provide few direct lessons on retail sales for NZ Power,
which will have a single buyer with retail competition. We are not aware of any other
jurisdiction that has successfully used this combination of central control with retail
competition. This is because the presence of a fixed wholesale price leaves little room for
retailers to effectively compete. Without the ability to compete on wholesale electricity
purchasing costs, retailers can only differentiate themselves through billing technologies
and customer services. While this is still retail competition, it is clearly more limited than
current market arrangements.
34
6
Case Study of Jurisdictions with Capacity
Markets
Many jurisdictions have capacity markets which combine some features of the single
buyer model with market and market-like arrangements. While the exact form of capacity
markets varies considerably across jurisdictions, the key feature is some kind of
administrative oversight over the provision of capacity. Similar to the payment structure
under PPAs, generators in capacity markets receive separate payments for capacity and
energy. However, in contrast to vertically integrated markets, capacity and energy
payments are not set by long term contracts, but rather by markets:
Capacity payments compensate generators for their fixed costs—that is
payments for being available. These payments can be made by retailers and
large customers contracting for capacity, or by the single capacity buyer—
usually the market operator; and
Energy payments compensate generators for their short run marginal
costs—essentially fuel—when they are dispatched. These payments are
received by generators from some type of spot market for dispatch.
Generators and retailers can also enter into contracts for differences between
spot market prices and some contracted long term strike price.
Capacity markets are thus a hybrid between the single buyer model and the fully market
based energy only wholesale pool model.
While capacity markets have many different forms, they all have the following features in
common:
Planning is usually decentralised in that all retailers and loads submit
forecasts to the market
Procurement of capacity is primarily the responsibility of retailors, however
shortfalls are procured by the market operator as a last resort
Dispatch of generation normally occurs through a spot market with
generators submitting bids; and
Retail can be competitive or regulated.
6.1
Evolution of the Current Market
Capacity markets are common internationally, with possibly the largest and best known
being the PJM market, which covers wholesale electricity supply to 14 states in the North
Eastern United States8. In Australia, the Wholesale Electricity Market (WEM) in Western
Australia is a capacity market. In this section we use PJM as a reference case for a
capacity market but recognise that considerable variations exist.
Capacity markets evolved as part of the general electricity market reform process to
unbundle vertically integrated monopoly power systems and introduce competition and
contestability. One policy junction was whether to have an energy only market (as in
New Zealand), and whether to have a capacity market. Those jurisdictions that choose
capacity markets did so on the basis that energy only markets produce volatile spot prices
that may not provide incentives for appropriate investments in long term capacity to
ensure reliability.
8
PJM market serves all or part of the following states: Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New
Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
35
6.2
Planning
In capacity markets, planning is usually decentralised in that all retailers and any directly
supplied large customers submit forecasts to the market operator along with evidence of
any capacity contracts they have to match that load.
This means the risk of forecast errors lies with the retailers that bear the consequences of
those errors. The financial consequences arise through either:
Retailers being over contracted in capacity—that is paying for more capacity
than is required; or
Penalties imposed by the market operator when the retailers consume more
capacity than they forecast. Those penalties are usually based on the assumed
cost of new entry plus a margin to incentivise retailers not to game their
capacity forecasts.
A feature of capacity markets is that capacity is tradeable—that is retailers can continually
adjust their forward capacity position.
In essence this incentivises (or perhaps forces) retailers and loads to maintain the
reliability standard set by policy makers by requiring them to contract for capacity and
providing penalties and costs if they do not contract.
Lessons for NZ Power
The option of shifting forecasting risk to retailers and loads is attractive if they are
incentivised appropriately through exposure to the financial consequences of that risk.
This type of approach promises greater efficiency than a central forecasting body that
may have different or lesser incentives—for example a responsibility to maintain supply
security may lead to a bias towards over forecasting future capacity requirements.
6.3
Procurement
In a capacity market, all retailers and loads are generally required to have firm capacity
contracts with generators for their expected loads plus—importantly—an
administratively determined reserve capacity margin. The capacity margin can also be
implemented as a firm capacity requirement—that is generators are assigned a firm
capacity rating, for example, on an N-1 basis, that they can contract. Typically the
forward cover mandated in capacity markets is three to five years and thus provides a
basis for long term investment in new capacity.
To the extent that retailers and loads cannot contract for all of their required capacity, it
is procured by a single buyer. The single buyer is almost always the market operator, who
administers competitive tenders. The tendering process differs by jurisdiction, with
varying degrees of neutrality with regards to the size, location and technology of the new
capacity. In many jurisdictions there is a ceiling price set above which the single buyer
will not procure capacity. That ceiling is usually set at the deemed fixed costs of an open
cycle gas generator. The costs of the procurement process are paid by the retailors and
generators who did not fully contract bilaterally for their needs.
Box 6.1 describes the PJM procurement process—a typical capacity market approach.
PJM calls its approach “reliability pricing” because capacity markets focus on having the
capacity in place ahead of time to meet forecast demand peaks on very hot or cold days.
The market therefore enables the system to deliver the planned level of reliability.
36
Box 6.1: PJM Reliability Pricing Model
The Reliability Pricing Model (RPM) is PJM’s capacity-market model. Implemented in
2007, the RPM, based on making capacity commitments three years ahead, is designed to
create long-term price signals to attract needed investments in reliability in the PJM region.
The long-term RPM approach, in contrast to PJM’s previous short-term capacity market,
includes incentives that are designed to stimulate investment both in maintaining existing
generation and in encouraging the development of new sources of capacity – resources
that include not just generating plants, but demand response and transmission facilities.
The RPM model works in conjunction with PJM’s Regional Transmission Expansion
Planning (RTEP) process to ensure the reliability of the PJM region for future years.
The RPM includes the continued use of self-supply and bilateral contracts by load-serving
entities (LSEs) to meet their capacity obligations. The capacity auctions under the RPM
obtain the remaining capacity that is needed after market participants have committed the
resources they will supply themselves or provide through contracts.
The RPM provides:
Procurement of capacity three years before it is needed through a competitive auction;
Locational pricing for capacity that reflects limitations on the transmission system’s
ability to deliver electricity into an area and to account for the differing need for
capacity in various areas of PJM;
A variable resource requirement to help set the price for capacity;
A backstop mechanism to ensure that sufficient resources will be available to preserve
system reliability.
Source: http://www.pjm.com/about-pjm/learning-center/markets-and-operations/rpm-capacitymarket.aspx
Lessons for NZ Power
We see two benefits of the capacity market approach to procuring new generation
capacity.
Firstly, the hybrid approach gets the best out of the market, while having a backstop of a
centrally run process. It creates powerful incentives for both generators and retailers to
negotiate rather than rely on the system operator tendering process for new capacity. For
generators, failure to contract all of their capacity will ensure that either new entry occurs
or they will be forced to participate in a competitive tender process. For retailers, it caps
the price they are prepared to pay for capacity at the new entrant price determined by a
competitive tender process.
Secondly, capacity markets provide incentives for both retailers and generators to
contract long term—that is for a term longer than the market’s mandatory capacity term.
For example, the mandatory capacity term in PJM is three years. However freely
negotiated contracts often have a much longer terms, as this lowers the costs and risks
for both generators and retailers.
6.4
Dispatch
Typically capacity markets use a spot market with competitive bidding on energy cost to
ensure efficient least cost dispatch. Capacity payments cover all fixed costs of generation.
Generators recover the variable costs of their generation through their bids into the spot
market.
The spot market for dispatch in capacity markets is far less volatile than in energy only
markets, as generators are only seeking to recover their variable costs. In energy only
markets, generators are seeking to recover their variable costs as well as their fixed costs.
37
They often recover their fixed costs through a small number of very highly priced spot
market periods.
Spot markets for dispatch in capacity markets typically have their prices capped. Prices
are normally capped at the fuel costs of the most expensive generation. Prices caps of
around $1,000 are typical. Having such low price caps substantially mitigates any market
power concerns.
Lessons for NZ Power
The separation of the markets for capacity and energy make the energy dispatch market
for capacity markets less volatile and in some ways more transparent. There is far less
angst about whether price spikes represent genuine scarcity and thus recovery of fixed
costs or evidence of market power.
However, the energy dispatch market in a capacity market model does not provide any
insights for New Zealand on the appropriate valuation of limited water resources for a
predominantly hydro generation based system.
6.5
Retail Sales
Capacity markets are well suited to either a competitive or regulated retail environment,
provided that there are enough buyers and sellers of capacity to make a liquid and
competitive market for capacity. This means that if the retail sector is regulated there
should be multiple franchise retailers and or major customers that can contract with
generators for capacity.
As retail deregulation is carried out on a State by State basis in the United States, PJM
operates across states that have both regulated and competitive retail markets.
Lessons for NZ Power
Of all the single buyer models, the capacity market model is most suited to a deregulated
retail market. This is because the single buyer component is limited to two functions:
Mandating that retailers and large customers have contracted adequate
capacity to meet their loads; and
As a last resort, procuring capacity to cover any shortfalls through a
competitive tender process.
38
7
Conclusion: What Will Reduce Retail Power
Prices?
The key motivation behind the NZ Power proposal is to reduce retail prices for
customers. Labour and the Greens have a view that the current wholesale market
structure is not sufficiently supporting such an outcome. The opposition parties believe
that a single buyer model would lower retail electricity prices. However, international
experience shows that the key to lower electricity prices is not adopting a particular
structure for the electricity sector, but getting the risk allocation right. If sector reform
does not change the underlying costs incurred in the industry through better risk
management, then all reform can hope to achieve is to transfer value between parties.
NZ Power proposal has an unusual combination of common market elements
Labour claims that the market structure proposed is commonplace around the world.
This is misleading. No other jurisdiction combines the elements of NZ Power across the
key functions of planning, procurement, dispatch and retail electricity sales. It is
particularly unusual to have retail competition in a single buyer market.
There is no perfect structure, so it is important to be explicit about the trade-offs
when adopting a new sector structure
All electricity system frameworks—whether vertically integrated monopolies, single
buyers or wholesale markets—have the core objective of providing reliable supply at the
lowest long term cost. International experience shows that there is no single model that
universally performs better than others in achieving this objective—wholesale markets
have worked well in some jurisdictions, and have failed completely in others, as have
single buyers.
Economic theory suggests that markets will generally work towards an efficient allocation
of resources. However, since electricity markets are all highly artificial and imperfect
regulated markets, it is less obvious that markets are always the best solution.
Lower power prices come from managing risks effectively
The key to getting the structure of the electricity sector right lies in risk allocation—a
framework that allocates risk efficiently will generally produce lower retail prices.
Efficient risk allocation involves allocating risks to the party best able to manage and
mitigate them—the party has both the means and the incentives to manage each risk.
There are many risks in electricity sectors, including who pays if there is over-investment
in new generation, who pays if world gas prices increase, and who pays to manage
environmental impacts. Market structures differ primarily on who bears each of these
risks. Different market structures cannot remove the risks inherent in electricity
generation, transmission and distribution. They can only allocate these risks to different
parties.
In market based systems, generators and retailers bear most of the risk in planning and
procurement. They are responsible for having sufficient electricity supply to meet
demand. If these parties fail to forecast demand accurately or fail to price their offers to
market competitively, then they bear the cost. In the NZ Power proposal, these risks are
transferred to the single buyer. If NZ Power forecasts demand incorrectly, it will either
be left with idle assets, or customers will face blackouts. If NZ Power dispatches
available hydro generation too heavily, it will be left with high fuel costs to dispatch
thermal plants when lake levels get too low (or worse will require electricity conservation
campaigns to manage combined water and thermal fuel resources).
39
When risk is shifted to a single buyer, generators and retailers will bear less risk, so
should expect lower returns. However, the underlying risk still exists—it has simply been
transferred to NZ Power. Whether or not moving to a single buyer model results in
lower electricity prices for customers will therefore depend on whether NZ Power can
manage these risks better than the private generators and retailers.
To illustrate this point, we can look at the risks associated with procuring new
generation. Procuring new generation centrally via a properly structured long term
contract may well lead to lower generation costs and lower returns for investors. This is
because many of the normal risks of developing capacity have been passed to the buyer.
The single buyer decides the size, technology and timing of the capacity expansion, and
takes risks such as future fuel price increases.
This means that the apparently low cost of generation through a long term contract is
balanced by the transfer of risk to the single buyer. If the capacity is not needed or is the
wrong technology or location, then the single buyer—and ultimately customers—pays
the financial penalty. It is therefore not surprising to see retail prices in single buyer and
wholesale markets following a similar trajectory. Risks are either priced into the returns
expected by investors in a competitive market, or are passed through to consumers when
risk events occur under the single buyer model.
What can we learn from international experience on trade-offs between different
sector structures?
Our case studies of Brazil and Ontario and IPPs and capacity markets provide some
useful lessons to understand the trade-offs inherent in developing an efficient model for
the electricity sector. Table 7.1 summarises the key lessons on managing risks in
planning, procurement, dispatch, and retail sales.
Table 7.1: Lessons from International Experience with Sector Reform
Procurement
Planning
Brazil
Ontario
Capacity
markets
Lessons on
managing
risks
effectively
Positive: Retailers Negative: Creating political
have incentives to incentives to maintain reliability is
likely to result in over-investment
forecast
accurately
Positive:
Requiring
retailers to
contract for
capacity gives
incentives to
forecast demand
accurately
Commercial
incentives
provide a
valuable
discipline to
plan
accurately
Positive: Reverse
auctions tend
drive price down
Negative: Contract
length shorter
than useful life
increases price
Positive: provides
incentives to
compete out
long term
contracts to
lower prices,
while having a
market provides
dynamic
responses over
time
Competition
for long term
contracts can
lower price
Negatives: Cooptimising
location of
transmission
and generation
is hard.
Decisions to
favour
renewable
renewables
drives price up
Vertically
integrated
markets
Positive:
competitive
tenders drive
price down
Negative: single
buyer does not
have strong
financial
incentives to
identify the best
location and
timing
40
Brazil
Ontario
Vertically
integrated
markets
Capacity
markets
Lessons on
managing
risks
effectively
Positives: Using
Dispatch
optimisation
model for hydro
dispatch tries to
account for
storage issue
Using a spot
market for
balancing is a
useful way to
signal scarcity
Positive:
generators have
incentive to be
available for
dispatch
Negative:
incentives for
contractors to
bid at
contracted price
dampens signals
of fuel scarcity
Negative: Long
term contracts
for energy and
capacity mean
that the price
paid to
generators may
not reflect the
actual costs of
generation re
either priced into
the returns e
Positive: energy
only spot
market allows
energy scarcity
to be reflected
and responded
to in real time
Market
mechanisms
provide
important
signals of fuel
availability.
Dispatching
hydro
resources
requires good
modelling
Retail
Positive: allowing
large customers
to purchase
directly from
generators is
efficient
Negative: retail
competition is
hard with a
single buyer
who sets
wholesale prices
Negative: single
buyer has no
customer
relationships
through which to
control real time
demand
NA: capacity
markets can be
used with single
buyers or with
competing
retailors
Wholesale
prices need to
incentivise
retailors to
contract for
sufficient
supply
Stability in market structure is valuable: change should only be made to realise
clear gains
Stability in market structure has value in itself—there is benefit in evolution rather than
revolution. Reforming a sector structure is risky and disruptive, as seen in Ontario and
Brazil’s failed market reforms that lead them back towards single buyer models. Reform
can create disruption for consumers. Reform can also discourage investment because
private parties will not invest money if they think the market structure is vulnerable to
future change that makes their investments unprofitable. In other words, there are costs
associated with the reform process, even if the end result is marginally better than the
status quo.
This suggests that reform should only be considered in New Zealand if the current sector
structure is clearly broken. Labour and the Greens are convinced that current electricity
prices are too high. However, reform should only be considered if an obviously better
sector structure is proposed. From our case studies of international experience, the single
buyer proposal does not appear clearly superior for New Zealand.
41
Appendix A: Operation of Electricity Sector Affected
by Physical Features
The two jurisdictions that have the most similar structure to that proposed by the
opposition parties are Brazil and Ontario (Canada). However, the physical characteristics
of each market are quite different. Table A.1 provides an overview of the key features.
Table A.1: Comparison of the New Zealand Electricity Sector to Electricity Sectors
in Brazil and Ontario
Brazil
Ontario
New Zealand
Peak demand (MW)
71,000 (year 2011)
27,005 (year 2006)
6,654 (year 2011)
Installed capacity (MW)
120,000 (year 2011) 34,276 (year 2009)
9,751 (year 2011)
Load Factor (%)
59%
60%
67%
Reserve Margin (%)
41%
21%
32%
Total consumption (GWh in 2011)
369,000
141,500
39,005
Average annual consumption per
capita 2008-2012 (kWh)9
2,381
15,137 (average for 9,566
Canada)
Proportion of consumption from
residential users
30% (year 2011)
36% (year 2006)
35% (Year 2010)
Proportion of consumption from
commercial10 users
20% (year 2011)
32% (year 2006)
29% (Year 2010)
Proportion of consumption from
industrial users
50% (year 2011)
32% (year 2006)
36% (Year 2010)
Hydro
72%
22%
55%
Gas
9%
Oil / diesel
6%
Coal
2%
Nuclear
2%
55%
0%
Geothermal
0%
0%
7%
Wind
1%
1%
6%
Biomass
8%
0%
0%
Cogeneration
0%
0%
4%
Imported
0%
5%
0%
Overview
Consumption
Generation mix
9
16%
17%
10%
http://data.worldbank.org/indicator/EG.USE.ELEC.KH.PC/countries
10
2%
For New Zealand, “commercial users” include agriculture and forestry
42
Generation market players
Number of generators
488
20
5
Share of generation produced by
largest generator
9%
70%
32%
Sources of data for Brazil: "Evolution of Global Electricity Markets" by Sioshansi (page 438-449)
Sources of data for Ontario: "Evolution of Global Electricity Markets" by Sioshansi (page 366-373).
http://www.ieso.ca/
Sources of data for New Zealand: "Evolution of Global Electricity Markets" by Sioshansi (page 649).
“Electricity in New Zealand” by the Electricity Authority. Page 22: “Generating capacity as at June
2011”. http://www.med.govt.nz/sectors-industries/energy/electricity/industry/electricity-generation
The New Zealand electricity market is much smaller than either of the other markets,
with a peak demand less than one tenth of Brazil’s peak demand, and less than one third
of Ontario’s peak demand (see Figure A.1).
Figure A.1: Size of Electricity Supply and Demand (MW)
Sources:
Ontario: "Evolution of Global Electricity Markets" by Sioshansi (page 366) and
http://www.ieso.ca/imoweb/media/md_peaks.asp
New Zealand: "Evolution of Global Electricity Markets" by Sioshansi (page 649)
Brazil: "Evolution of Global Electricity Markets" by Sioshansi (page 438)
The New Zealand electricity market has a similar consumption mix to Ontario, with
consumers, industry and commercial users each consuming roughly a third of generated
electricity (see Figure A.2). In Brazil, industrial users consume roughly 50 percent of all
electricity, with residential consuming around 30 percent.
43
Figure A.2: Sources of Demand in Ontario, New Zealand and Brazil
Sources:
Ontario: “Single Buyer and Ontario’s Electrics Supply Structure” presentation by the Ontario Power
Authority presented by Jan Carr. November 2006.
New Zealand: “Electricity in New Zealand” by the Electricity Authority. Page 8: Estimated electricity
consumption by section for year ended March 2010
Brazil: "Evolution of Global Electricity Markets" by Sioshansi (page 438)
New Zealand’s generation mix is more similar to Brazil’s than to Ontario’s (see Figure
A.3). Both New Zealand and Brazil rely on hydroelectricity for over half of generation.
Whereas in Ontario, nuclear is the main source of generation, accounting for 55 percent.
Fossil fuels are the second biggest energy source for all three markets. The secondary
renewable energy in each country after hydro differs: in New Zealand, it is geothermal
(making up 7 percent of total generation), in Brazil it is biomass (making up 8 percent of
total generation), and in Ontario, it is wind (making up 1 percent of total generation).
In terms of competition in the generation market, New Zealand has fewer market players
than either Brazil or Ontario. However the New Zealand market is split more evenly
between generators than in Ontario, where Ontario Power Generation accounts for 70
percent of all generation. In comparison, the largest generator in New Zealand, Meridian,
accounts for around 30 percent of the market. In Brazil, the generation market is much
more fractured, with nearly 500 generators, the biggest of which accounts for 9 percent
of the market.
44
Figure A.3: Generation Mix in Ontario, New Zealand and Brazil
Sources:
Ontario: "Evolution of Global Electricity Markets" by Sioshansi (page 366)
New Zealand: “Electricity in New Zealand” by the Electricity Authority. Page 22: “Generating capacity as
at June 2011”
Brazil: "Evolution of Global Electricity Markets" by Sioshansi (page 439)
45
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