The UK Gas Industry in the Long-term:
and the Liberalisation of European Markets
An alternative analysis by Professor PR
1 This note seeks to clarify some of the issues
in this Report relating to the future of natural gas, in general,
and to paragraphs 91-96 on the liberalisation of European gas
markets, in particular. The Report argues that "there is
considerable uncertainty about gas imports in the long-term"
(para 91) and that the UK's security of energy supply would best
be achieved if left to market forces and that these "would
not operate effectively without greater liberalisation of continental
European markets". (para 92)
2 As gas reserves/ resources potentially available
for use in Europe (including the UK) constitute about 70% of the
global total, while Europe is responsible for only 18% of current
world use with this share more likely to decrease than
to increase over the next 20 years there can be no uncertainty
over supply per se. Potential suppliers are, indeed, gathered
around Europe like proverbial "wasps around the jam jar",
containing, in this case, high value gas markets and a set of
consumers ready, willing and able to pay for the commodity in
steadily increasing volumes.
3 Presumably, therefore, the "uncertainties"
to which the Report refers must be related specifically to the
questions of how soon and how much the UK will need to import
and from which specific sources of supply such requirements
can be most securely and cheaply obtained?
B The UK's future gas import needs will be limited
4 The Minister of State for Energy has suggested
that the UK is likely to be up to 50% dependent on gas imports
by 2010 and some 90% dependent by 2020. These forecasts emerge,
however, from inappropriate values attached, first, to gas demand
developments; and second, to UK gas production potential.
5 According to the PIU Scoping Note the rate
of expansion of UK energy demand will be of the order of 2% per
annum, viz from 226 million tons oil equivalent in 2000 to 275
million tons in 2010 and 335 million tons in 2020. In reality,
this has a very low probability of being achieved. Even with a
continuation of the very modest energy conservation and efficiency
efforts to date, it seems unlikely that incremental energy demand
over the next 20 years will be almost five times that of the last
20 years (viz 110 mtoe compares with 23 mtoe). Given energy use
objectives which are now orientated much more strongly to demand
constraints, the probability of such future levels of energy use
is close to zero.
6 It is much more realistic to predicate that
future demand growth will continue to expand at no more than the
0.5% rate of the past 20 years; to about 238 mtoe in 2010 and
just over 250 mtoe in 2020. Within this framework, certain or
planned supplies of oil, coal, nuclear and renewables will deliver
some 138 mtoe by 2010 and 145 by 2020, thus indicating a demand
for gas of about 110 Bcm in 2010; and about 115 Bcm by 2020. Gas
demand in 2000 was 96 Bcm (with indigenous production significantly
higher at 108 Bcm, indicating a net export from the UK of about
7 Even if indigenous gas production were to fall
dramatically from its present level to some 82 Bcm in
2010 and to 58 Bcm by 2020 (that is, by roughly the decline expected
by UKOOA from the depletion of presently discovered reserves),
then net import requirements for gas would be only 28Bcm in 2010
and 58 Bcm in 2020 (= 25% of gas demand in 2010 and 50% in 2020).
Additional recoverable reserves of UKCS gas are, in the meantime,
however, virtually certain to emerge from re-evaluated fields
and from new discoveries as a consequence of the industry's
intensified efforts to achieve such an objective based
on the DTI's current mid-range estimate of 2100 Bcm of remaining
discoverable gas. In the absence of adverse regulatory constraints
on the industry's propensity to invest, production will be some
25 Bcm per year greater than the 82 Bcm and 58 Bcm in 2010 and
2020, respectively (as indicated above). Thus, the UK's net gas
import needs could fall to near zero in 2010 and to no more than
33 Bcm in 2020.
C An Accord with Norway will solve the "problem".
8 The security of UK gas supply for the next
20 years is thus at worst an issue of relatively minor dimensions:
at best, it will be non-existent. In any case, net imports sufficient
to meet the reasoned estimated shortfall can be virtually guaranteed
from the exploitation of the massive additional gas reserves of
Norway. In 2000, Norway exported 49 Bcm (all to mainland European
countries). An additional 20 Bcm per year are already contracted,
largely to the same set of purchasers, for delivery by 2004/5.
Thereafter, however, another 50 Bcm per year are predicated for
development, but with most of this gas not yet contracted for
sale: though note that BP has already negotiated modest purchases
for delivery to the UK from 2004 for a 25 year period under take-or-pay
9 Technical discussions between the UK and Norwegian
authorities on possible joint developments have already been scheduled
for the very near future (possibly by March this year). These
preliminary moves need to be expanded into a major Anglo- Norwegian
politico-economic agreement, whereby the best interests of both
countries can be achieved. This would seek to ensure a maximised
net-back value at the well-head from Norway's large potential
additional production, on the one hand; and, for the UK, guaranteed
volumes of required imports of new Norwegian gas, plus benefits
from a joint venture for the transit of the remaining gas via
the UK to the mainland of Europe. Ironically, the principal barrier
to such a mutually beneficial agreement for the two countries
could well be the incompatibility of OFGEM's stance on "competitive"
pricing for gas delivered to the UK, with Norway's preference
for long-term take-or-pay contracts whereby the high levels of
investments for the large-scale gas production in its Northern
waters can be justified.
D Other "guaranteed" sources.
10 In the context of such an Anglo-Norwegian
accord, the UK's needs for gas imports from other sources would
thus be minimised or even eliminated, except for seasonal
requirements for high winter demand. Such relatively minor import
volumes will be readily available albeit at higher prices,
given the seasonality of demand from alternative sources.
Either as pipelined imports from the Netherlands, where
significant seasonal flexibility of supply is built into its gas
production, transport and storage systems, and for which more
than adequate capacity for moving the gas to the UK through the
inter-connector from Zeebrugge (currently being expanded to handle
24 Bcm of gas per year) will be in place. Or as LNG imports
(to terminals with relatively short lead-times for development)
from an increasing number of possible suppliers within relatively
short sea distances from the UK, viz, Algeria, Egypt, Nigeria,
Trinidad, Venezuela and even Norway's Barents Sea Snøvit
field, currently under development as an LNG export facility.
E The UK and the non-liberalised mainland European
11 In the demand/ supply prospects as set out
above, the UK seems unlikely to be required to depend much, if
at all, prior to 2020 on any other external suppliers of gas to
Europe, viz Russia and Algeria as existing suppliers or Libya,
Turkmenistan and Iran as potential suppliers before 2020. Under
such conditions, the concerns expressed in this Report and elsewhere
(notably the PIU scoping note) for the slow process of gas liberalisation
in most other EU member countries is misplaced. The UK's demands
on the use of the transmission system already in place will be
minuscule in the context of the system's existing capacity to
move some 300 Bcm of gas per year from the exporting to the importing
countries. The UK's suppliers lack of guaranteed third-party access
rights to the system and the absence of price transparency would,
at worst, thus be a minor inconvenience.
12 Meanwhile, the mainland European gas transmission
system is not only being increasingly reticulated and geographically
extended, it is also being opened up to regulated or negotiated
third-party access with published tariffs in ways
which suit the needs of both exporting and importing countries.
13 The antecedents to the evolution of the mainland
gas transmission network and the trading mechanisms for the gas
itself have been very different from those that have emerged in
the UK (following the UK's decision in 1972 not to allow gas exports
to the rest of Europe and thus preventing integration). While
supply-side competition for gas in the UK did not effectively
emerge until the early 1990s, competition between the suppliers
of gas to mainland European markets started as early as 1971 (with
the entry of Russian gas to the market). By 1990 this competition
had become so intense that prices dipped well below crude oil
equivalents and enabled European consumers (in all sectors except
residential in which UK prices were held to an artificially low
level through government intervention) to enjoy much lower (pre-tax)
prices. This situation persisted until as recently as 1999, when
European pre-tax prices generally rose above those in the UK as
a consequence of the strong upward price movements of crude oil.
But UK consumers' new-found price advantages from that situation
have already proved very temporary, so that differentials have
14 Meanwhile, moreover, the generally high downstream
profits in gas distribution in most mainland European countries
arising from monopolistic conditions are now being
brought under severe downward pressure through governments'- induced
interventions requiring structural changes in the national systems
though not necessarily in the highly-regulated "laissez-faire"
manner chosen to ensure price reductions in the UK. This UK approach
is very widely non-acceptable in many other European countries
in the context of a continuing belief in the public service nature
of the gas (and electricity) supply industries, often under municipal
control; with gas and electricity revenues used to subsidise other
public sector services. This constraint on UK-style liberalisation
remains highly pertinent.
15 There is a yet more significant constraint
on the ability and willingness of other EU countries to switch
their gas purchasing arrangements from long-term take-or-pay contracts
to short-term trading. This reflects these countries' status already
as major gas importers -- and as even more import-dependent gas
users in the future. (Only Denmark and the Netherlands are self-sufficient).
Their 'dash-to-gas' has hardly begun, with gas still accounting
for only 19% of total energy used (compared with 38% in the UK):
by 2010 gas dependence is expected to increase to about 24% and
by 2020 to 30%, involving 315 Bcm of gas imports in 2010 and 390
Bcm in 2020. Given these expectations, guaranteed long-term arrangements
for imported supplies are of the essence and it may be assumed
that they will continue, irrespective of what are seen as the
irresponsible demands of the EU's Competition Directorate for
a switch to short-term competitive markets.
F The views and requirements of the countries
exporting gas to Europe
16 The gas importing countries' motivations for
the continuation of long-term contracts for gas imports are already
powerful enough to ensure the sustenance of the 30 year old system,
except for minor changes relating to joint sales (as by the Norwegian
GSU), destination clauses and resale procedures. The importers'
concerns are, however, greatly strengthened by the views and requirements
of the external suppliers -- most notably Russia and Algeria,
but also involving both Norway and also potential new suppliers,
all of which have participated in recent gas suppliers' summits.
At these meetings exporters expressed their 'indignation' at the
EU's attempts to undermine the supply system on grounds of 'restraints
on trade' -- even to the extent of declaring existing contracts
as unacceptable under EU competition law.
17 The exporters argue that ending long-term
take-or-pay contracts will mean that both volumetric and
pricing risks will be moved to the producer, compared with the
current sharing of those risks between exporters and importers
(with the latter guaranteeing volumes). Liberalisation, the exporters
say, does not take account of their needs and, moreover, they
have not been consulted on the changes. Gazprom summarised the
evolving situation as one in which it would be unable to conclude
new contracts. Both Gaz de France (given France's 90% dependence
on imports now and over 95% by 2010) and Ruhrgas (given Germany's
80% import dependence) are giving strong support to the exporters'
18 The French, German and other countries' concern
for the adverse impact of liberalisation on prospects for gas
supply and price is taken even further by their fears that the
alienation and provocation of the external suppliers of gas to
Europe will lead to the creation of a formal oligopoly of suppliers
(viz. An Organisation of Gas Exporters to Europe -- OGEE) through
which supply constraints and consequential higher prices will
be the end result -- to the disadvantage of all gas users in Europe
(note that neither Russia nor Algeria -- nor Libya, Egypt and
Iran -- have signed and/or ratified the European Energy Charter
which requires a free-trading regime).
19 In light of such formidable opposition to
gas trade liberalisation it is not very surprising that a mid-2001
ruling by the EU that a 'prioritised' infrastructure-connector
for electricity between Germany and Poland involves such a large
investment that those investing need 25 years of exclusive
rights to use the line (in order fully to cover their costs)
and that this requirement should 'supercede competition issues'.
This appears to establish a precedent for treating infrastructural
connectors for gas movements between states in a like manner.
Coincidentally, an EU Report on Energy Infrastructure has
recently been published and has designated a set of five prioritised
requirements for the gas industry. These include the connection
of networks between the UK, Netherlands, Germany and Russia; likewise,
between Algeria, Spain and France; underground gas storage construction
in Spain, Portugal and Germany; and the development of pipeline
systems between the EU and both the Middle East and the Caspian
basin (plus LNG facilities in France, Spain, Portugal and Italy)
with the collective object of guaranteeing at least 20% of peak
daily demand for all parts of the EU. Should such EU-prioritised
gas infrastructure developments be given exemption from competition
rules -- through the protection of investments made in the facilities
against 'required' TPA for 25 years, then gas market liberalisation
objectives would be well and truly thwarted for the whole of the
period to 2020.
G Optimal Policy for the UK
20 Given the prospect outlined above, then the
development of the UK's gas industry would seem likely to be best
effected by a combination of maximum efforts to maintain the volumes
of indigenous production (as suggested above in para 7); by an
accord with Norway to make-up most of any shortfall in the context
of a broad, mutually beneficial agreement (paras 8 and 9 above);
and by the development of LNG peak sharing facilities (para 10).
The use of the interconnector with the European mainland would
remain as an optional (emergency) extra.
21 None of these proposals should create any
great concern as to their practicality: and neither in respect
of the level of costs involved. In the context, that is, of realistic
forecasts of future levels of energy demand, in general, and of
gas demand, in particular (as argued in paras 6 and 7).
22 The UK's security of gas supply for the next
two decades is certainly not a problem of accessing large
volumes of gas from distant sources, separated from the UK by
many intervening complexities. On the contrary, supply security
is, in essence, a matter of good and mutually beneficial relations
with Norway as a complement to the establishment of a number of
nationally achievable aims, viz much higher efficiencies in gas
use, especially in the domestic sector (responsible for one-third
of total consumption) through measures including fiscal ones;
favourable policies for maximising indigenous gas exploration
and exploitation; and the abolition of regulatory practices which
undermine investments in gas production, new terminals and extended
transmission systems -- with particular, but not exclusive, reference
to the UK as a transit country for large volumes of Norwegian
gas en route to mainland Europe.
Notes on Combined Heat and Power
(CHP) by Professor Bert Whittington
All fossil-fuelled electrical generating equipment
is less than 100% efficient. The proportion of the energy in the
input fuel which is not converted to electricity is discharged
as waste heat - more than half the energy is lost in this way.
In a CHP installation, both this heat and electricity are used:
the heat (usually as process steam or hot water) generated is
used in industrial processes, community heating and space heating.
The ratio of heat-to-electricity can be tailored for each installation
by the designer.
Because the waste heat from electricity generation
is used and transmission losses are avoided, CHP typically achieves
a 35 % reduction in primary energy usage compared with power stations
and heat-only boilers. Used prudently, CHP can deliver significant
improvements in efficiency and in cost reduction compared with
The current CHP installations are estimated to achieve
a reduction of over 30 % in CO2 emissions in comparison
with generation from coal-fired power stations, and over 10 %
in comparison with gas-fired combined-cycle gas turbines. The
newest installations achieve a reduction of over 50 % compared
with generation from coal-fired power stations
The matching process: selecting the electricity-heat
ratio of plant
(often termed "sizing" plant)
The design of a CHP system is straightforward, providing
that the electricity-heat ratio is constant or varies only over
a limited range: otherwise the choice of appropriate CHP is a
compromise and theoretical efficiency gains are not obtained.
One of the most important issues is seasonal variation
in the electricity-heat ratio. To illustrate this, consider an
installation for providing heat and electricity to a commercial
premises. Nowadays electricity demand for air conditioning is
high in summer and is accompanied by a low heat demand for space
heating: in winter, the heat demand rises considerably, but not
the demand for electricity. Thus, an installation designed for
optimised summer operation could be ill-equipped for winter operation
and vice versa.
Note from Professor Bert Whittington
on Quality of Supply
Except for exceptional circumstances, the Electricity
Supply Regulations permit variations of voltage not exceeding
10% above and below the nominal at 400kV, 275kV and 132kV and
not exceeding 6% at lower voltages. Customers may expect voltage
to remain within these limits, except under abnormal conditions
e.g. a system fault outside of planning and operating standards.
Voltage sag describes reduction in voltage of 10s
of percent which can persist for up to a minute and is usually
caused by a fault on the network. Voltage swell describes a short-term
rise in voltage, usually caused by a switching operation on the
network, and is much less common than sag. Voltage flicker describes
rapid variations in system voltage, caused by such activities
as arc furnaces striking and taking rapidly-varying quantities
Normal operational limits are agreed and monitored
individually at connection points with customers to ensure that
voltage limits are not exceeded, following the specified fault
events described in the Licence Security Standard Operation Memorandum
No. 3. The criteria for reporting variations in excess of those
permitted by the Electricity Supply Regulations are: Voltage excursions
for more than 15 minutes.
The Electricity Supply Regulations permit variations
in frequency not exceeding 1% above and below 50Hz, a range of
49.5 to 50.5 Hz.
The system is normally managed such that frequency
is maintained within operational limits of 49.8 and 50.2Hz. Frequency
may, however, move outside of these limits under fault conditions,
or when abnormal changes to operating conditions occur. Losses
of generation between 1000 and 1320MW are abnormal and a maximum
frequency change of 0.8Hz may occur, although operation is managed
so that the frequency should return within the lower statutory
limit of 49.5Hz within 60 seconds. The criteria for reporting
variations in excess of those permitted by the Electricity Supply
Regulations are: Frequency excursions for more than 60 seconds.
Harmonics are electrical frequencies which are 'harmonically'
linked to the main or fundamental frequency. Thus, the third harmonic,
for example, is three times the fundamental, i.e. 3 x 50 = 150Hz.
They are caused by specific types of equipment, such as electronic
power supplies for computers or television sets. All of the above
are found in the present electricity supply network. Harmonic
distortion is a measure of how 'unsmooth' the voltage and current
waveforms have become by the presence of waveforms of different
A standard has been developed for recommended harmonic
voltage and current limits by the electricity industry. This standard
is Engineering Recommendation G5/3, (Limits for Harmonics in the
United Kingdom Electricity Supply System), published by the Electricity
Association. ER G5/3 sets limits for both voltage and current
distortion produced by a customer. This will soon be superseded
by G5/4 which will extend the range of harmonics that require
monitoring. Customers must then be concerned with harmonics up
to 2500Hz, both voltage and current, and total harmonic distortion.
The European Technical Standard is EN 50160.