1. Introduction

 1. Introduction

It is a great pleasure to be contributing to a special issue in honor of
David Newbery. David and I have worked closely together for all of my career at
Cambridge and my debt to him in terms of my interest in this particular subject
is immense. Characteristically, David has very kindly read and given me rapid
and detailed comments on the first draft of this paper (without seeing this first
paragraph). I can only hope that I have responded sufficiently to his insightful
comments.
Electricity markets in the developed world stand at something of a crossroads.
Many countries have made some, often substantial, progress with marketbased
reforms in production and retailing and the introduction of incentive regulation
of networks (see Joskow, 2008, for example). During the reform period
governments have sought to reduce their direct involvement in the electricity sector.
Now however rising environmental concern about global warming is beginning
to focus minds more clearly on the need for the reduction of carbon dioxide.
The need for substantial de-carbonization of the electricity sector is increasingly
recognized and being reflected in economic policy around the world, and particularly
within European Union (EU) countries.1 Indeed the EU as a whole has
adopted a trio of 20% targets by 2020 relating to climate change, renewable energy
and energy efficiency. These are a ‘hard’ target of a 20% reduction in CO2,
an ‘indicative’ target of 20% of final energy consumption from renewable sources
and an ‘aspirational’ target of a 20% improvement in energy efficiency (see Egenhofer,
2007, p.2). However between EU countries wide differences remain in
national level targets and in the degree of emphasis to be put on the ‘indicative’
and ‘aspirational’ targets with some countries (such as Spain and Germany) putting
great emphasis on renewables in contrast to other countries (such as the UK
and France).
There has been significant agreement on what constitutes the elements
of an energy market reform package (see Jamasb and Pollitt, 2005). At the level
of the EU this has been driven by the electricity and gas market reform directives
(in particular 1996/ 92/EC and 2003/ 54/EC). Addressing climate change
seriously, however, has the potential for introducing significant divergence in
policy choices between countries. This paper will argue that electricity (and, by
association, natural gas) regulation in an era of significant climate change concern2
needs to strengthen the role of competition and market forces as well as to
respond to the political pressure for action on de-carbonization of the electricity
and heat sectors.
The paper proceeds as follows. First we will briefly discuss the nature
of the traditional model of electricity reform and the place of economic regulation
within it. Next we will outline the drivers for changing the current model of
electricity regulation. Third, we will discuss the premises on which a new model
should be based. Fourth, we will outline the key elements of a new model. Lastly
we will conclude with lessons for independent regulatory agencies, governments
and companies. The paper draws heavily on the experience of the UK, but has direct
implications for most other European Union countries, which operate within
the context of EU energy and environment directives aimed at achieving common
goals and spreading best practice forms of action and regulation.

2. The Traditional Model of Electricity Reform and Regulation

 2. The Traditional Model of Electricity Reform and Regulation


The model of electricity reform as it first emerged in Chile (1982), UK
(1990) and Norway (1991), and subsequently in many other jurisdictions including
Australia and Texas, had four key elements.
1. The introduction of a competitive wholesale power market.
2. The gradual extension of competition in the retail market.
3. The regulation of network services via CPI-X regulation
4. The introduction of additional incentives for quality of
service and loss reduction.
The reform model was supported by rules on the separation of generation,
transmission, distribution and retail businesses in order to improve third
party access to the monopoly networks.
In many jurisdictions reform involved the privatization and restructuring
of state owned monopolies (Pollitt, 1997). In some other jurisdictions with
initially private monopolies, legislation and voluntary agreements resulted in divestitures
of generation assets in order to facilitate competition in the wholesale
power market (see Joskow, 2008, for a detailed description of both the ‘standard
liberalization model’ and a comprehensive review of the lessons learned from the
implementation of its many variants internationally).
Reform was often accompanied by the introduction of an independent
regulatory agency, with an arms’ length relationship to government departments
and with statutory duties to promote competition and to set regulated tariffs.3 This
new regulatory agency was usually a specialist in energy regulation and often
combined electricity and gas regulation, where gas was available.
To understand the role of such economic regulators it is worth examining
the mandate of the Gas and Electricity Markets Authority in the UK. This is the
governing board of Ofgem, the energy regulatory agency in Great Britain (GB)
(see Box 1).4
The legislation governing Ofgem has arisen principally from the Gas Act
1986 and the Electricity Act 1989 which privatized the state owned industries.
The duties of Ofgem were modified in the Utilities Act 2000 which introduced,
inter alia, the protection of vulnerable customers and the Energy Act 2004 which
included provisions about such things as energy security and having regard to best
regulatory practice. In addition Ofgem’s duties also arise from general competition
legislation, namely the Competition Act 1998 and the Enterprise Act 2002, as
well as arising from national implementation of European Community directives.
Reading the summary in Box 1 suggests that while Ofgem has a principal
objective – captured in its current strap-line: ‘promoting choice and value for
all gas and electricity customers’5, several other elements of economic regulation
seem largely tacked on to Ofgem’s duties. In particular climate change objectives
for the sector are things that Ofgem should have regard to rather than objectives.
There is also a loose requirement to have regard to energy security issues.
I would want to suggest, that at the very least, Ofgem’s mandate with regard to
implementing government policy towards climate change in the energy sector is
rather vague and that Ofgem’s regulatory role in the politically sensitive areas of
vulnerable customers, energy security and de-carbonization of the electricity sector
is ill-defined and reflects the incremental addition of matters to which it should
have regard to. This lack of clarity is reflected in a lack of associated powers in
these areas.
Taking Ofgem as an example of a leading independent energy regulator,
we take the traditional model of electricity and gas market regulation in the reform
period to centrally be aiming at promoting competition and effective monopoly
regulation (a perfect complement to competition in generation and retail) with
additional concerns secondary. This is not to say that many other jurisdictions,
especially in Europe and many of the states of the United States, only ever aspired
to fully implement the ‘traditional’ reform model (see Pollitt, 2008a, for more
expansion of this in a global context).
Looking to the wider context it is important to point out that few jurisdictions
have gone as far as the UK in implementing the ‘traditional reform model’.
The proposed EU Third Energy Package envisages further requirements in the
EU towards independent regulation and greater market structure reform. However
wide differences remain between EU countries, particularly with respect to the
strength and functions of energy regulatory agencies (see Green et al., 2006).

3. Drivers of change

3. Drivers of change
I identify three drivers of change for energy regulation in the UK (and
hence other deregulated energy markets): the maturity of the existing (traditional)
model; the reality of changing circumstances; and finally the coming of age of
climate change concern.

3.1 The Maturity of the Existing Model

3.1 The Maturity of the Existing Model

Ofgem’s mandate is to achieve its principal objective by promoting effective
competition. It is legitimate to ask how we would know if we had established
‘effective competition?’ And if we have achieved it, what are the implications
for the existing model of regulation?
Independent sectoral regulatory agencies exist for a purpose. Usually that
purpose is related to the idea that the markets they are regulating need special attention
that cannot be provided by the general competition authorities, such as the
Office of Fair Trading or the Competition Commission in the UK. This special attention
can be due to the immaturity of the markets being regulated and hence their
need for considerable ongoing monitoring and/or the complexity of the assessment
of whether the market is competitive and hence the need for specialist staff best
organized into a separate regulatory agency (or indeed the specialist market monitoring
function of the Independent System Operator, as in the United States).
Independent sectoral regulatory agencies in some countries may substitute
for a weak competition authority, however it is interesting to note the very
active role of the EU competition authorities in highlighting the nature of problems
with the operation of central European electricity and gas markets (European
Commission, 2007). The European Commission has been able to have a powerful
forcing effect in bringing about structural change where national regulators and
competition authorities failed to do so (e.g. in Germany where electricity and gas
companies have announced their intention to voluntarily unbundle their transmission
assets).
In terms of its principal objective Ofgem (and its predecessor Offer) has
witnessed notable success. The wholesale market was substantially competitive by
2001 when the market shares of the leading companies had been reduced by divestiture
(Newbery, 2006). Incentive regulation and tough reallocation of costs between
distribution and retail had ensured that there was a level playing field in retail
competition between incumbent retailers and new entrants, such that the residential
switching rates in GB are among the highest in the world (see Littlechild, 2006).
In terms of promoting the efficiency of network companies, real prices
fell in all the price review periods up to 2005. There was also significant conver-
gence in costs observed between electricity distribution companies (Jamasb and
Pollitt, 2007).
We suggest that scope for Ofgem’s efforts to impact prices by promoting
competition and incentivizing efficiency in electricity (and gas) supply further is
now limited by the achievement of de-concentration in generation asset ownership
and significant price convergence between suppliers and by the elimination of
initially high levels of inefficiency in network companies. This is not to say that incumbents
have not got considerable scope to lose more market share in the household
sector but that this trend is now well established (3% per year since 2002).
There may also be specific issues associated with gas distribution in the
UK, where the recent breakup and sale of National Grid’s former monopoly seems
to be resulting in significant efficiency improvements.7 This suggests that gas distribution’s
former structure was inefficient and that introducing comparative competition
between regional monopolies, as was already the case in electricity, will
yield significant improvements. It remains to be seen how long these efficiency
gains will take to be realized, especially within National Grid’s remaining four
gas distribution areas, now that the scope for efficiency savings has been revealed
by the new operators of the divested regions.

3.2 The Reality of Changing Circumstances

 3.2 The Reality of Changing Circumstances
If the traditional model has had significant success in achieving its mandate,
it is also the case that the environment in which it is being practiced is
changing.
The most visible sign of this is seen in the outcomes of the most recent
price control reviews that Ofgem has carried out. Three of the four most recent reviews
have resulted in significant projected rises in capital expenditure compared
with the previous price control review period. While rising capital investment is
not new, its impact in driving prices up overall is new.
The P0 adjustments indicate a rise in price in the first year of all of the
above price control periods. The RPI-X formulae give the price adjustments in
each of the subsequent four years of the five-year price control period. In electricity
distribution and transmission higher real prices have occurred because operating
efficiency savings (which continue but at a slower rate than previously) are
not sufficient to offset the effects of the extra capital expenditure on overall revenue
requirements.8 This situation reflects the fact that the ability for ‘asset sweating’
is much reduced relative to the early post-reform years. There are significant
methodological issues with the ability of efficiency analysis to detect significant
operating cost and capital cost inefficiencies when the underlying differences in
inefficiencies between the firms are small. Doubtless improvements in the size
of the datasets used for efficiency analysis, via the inclusion of international and
panel data would help, but would not necessarily address the issue of the declining
economic significance of measured efficiency differences and the unreliability of
the methods applied to them (see Pollitt, 2005).
In terms of electricity distribution and transmission a significant part of
the increase in capital expenditure is driven by low carbon investment in generation,
much of which is incentivized under the renewables support scheme (Renewables
Obligations Certificates or ROCs) and the European Emissions Trading
Scheme (EU ETS). For electricity distribution the increase in capital expenditure
to support distributed generation amounts to £500m over the price control period
(or around 25% of the increase) and for electricity transmission there has been a
separate allowance for £500m for renewable generation support in Scotland (under
the Transmission Investment for Renewable Generation (TIRG) scheme) and
scope for more if more renewable generation is connected.
If we assume that extra climate change inspired investment in GB is
£200m per annum, by 2012 the price of distribution and transmission services
might be 5% higher as a result of this extra expenditure.
More important in volume terms is the amount of investment required to
renew and upgrade the existing network. Electricity transmission and distribution
investment peaked in real terms in the late 1960s, this means rising and expensive
replacement investment in the current price control period and this trend seems set
to continue. Ensuring efficient re-investment in electricity networks is therefore
much more of a priority than it was in the early years following the initial reforms
because capital expenditure is a more significant share of total expenditure on
networks than it was in the past (see Pollitt, 2005).
Rising commodity prices for gas and coal have contributed to substantial
price rises for wholesale power since 2003 in GB. While our analysis of the
trend in network services costs suggests these are going to rise in real terms, we
have already seen substantial rises in wholesale power costs and in customer bills.
 
Between March 2003 and September 2006, when prices temporarily peaked, the
average household electricity and gas bill rose by £370 to £881. This contrasts
with consistent falls in electricity and gas bills from 1995 to 2003. Such a large
rise in the annual fuel bill has raised political questions and led to a significant
increase in fuel poverty, defined as households which spend more than 10% of
their income on fuel (primarily gas, but also electricity) to maintain a satisfactory
heating level (vulnerable households are those containing children, elderly,
sick or disabled). From a low of 1.2 million the number of households defined as
fuel poor rose to 1.5 million in 2005 (7% of all households) as energy prices rose
(BERR, 2007a, p.9-10).
While recent rises in electricity and gas bills are driven by supply and
demand in fossil fuel commodity markets, the impact of environmental factors on
the final price of electricity is increasing (primarily via the ROC scheme and the
EU ETS).