Gas to Coal Competition in the U.S. Power Sector
←
→
Page content transcription
If your browser does not render page correctly, please read the page content below
Gas to Coal Competition in
the U.S. Power Sector
Steven Macmillan, Alexander Antonyuk, Hannah Schwind
© OECD/IEA 2012
The views expressed in this paper do not necessarily reflect the views or policy of the International Energy Agency (IEA)
Secretariat or of its individual member countries. The paper does not constitute advice on any specific issue or situation.
The IEA makes no representation or warranty, express or implied, in respect of the paper’s content (including its
completeness or accuracy) and shall not be responsible for any use of, or reliance on, the paper. Comments are welcome,
directed to carlos.fernandez@iea.org.
© OECD/IEA, 2013
INTERNATIONAL ENERGY AGENCY
The International Energy Agency (IEA), an autonomous agency, was established in November 1974.
Its primary mandate was – and is – two-fold: to promote energy security amongst its member
countries through collective response to physical disruptions in oil supply, and provide authoritative
research and analysis on ways to ensure reliable, affordable and clean energy for its 28 member
countries and beyond. The IEA carries out a comprehensive programme of energy co-operation among
its member countries, each of which is obliged to hold oil stocks equivalent to 90 days of its net imports.
The Agency’s aims include the following objectives:
n Secure member countries’ access to reliable and ample supplies of all forms of energy; in particular,
through maintaining effective emergency response capabilities in case of oil supply disruptions.
n Promote sustainable energy policies that spur economic growth and environmental protection
in a global context – particularly in terms of reducing greenhouse-gas emissions that contribute
to climate change.
n Improve transparency of international markets through collection and analysis of
energy data.
n Support global collaboration on energy technology to secure future energy supplies
and mitigate their environmental impact, including through improved energy
efficiency and development and deployment of low-carbon technologies.
n Find solutions to global energy challenges through engagement and
dialogue with non-member countries, industry, international
organisations and other stakeholders.
IEA member countries:
Australia
Austria
Belgium
Canada
Czech Republic
Denmark
Finland
France
Germany
Greece
Hungary
Ireland
Italy
Japan
Korea (Republic of)
Luxembourg
Netherlands
New Zealand
Norway
Poland
Portugal
Slovak Republic
© OECD/IEA, 2013 Spain
International Energy Agency Sweden
9 rue de la Fédération
75739 Paris Cedex 15, France Switzerland
Turkey
www.iea.org
United Kingdom
Please note that this publication United States
is subject to specific restrictions
that limit its use and distribution. The European Commission
The terms and conditions are available online at also participates in
http://www.iea.org/termsandconditionsuseandcopyright/ the work of the IEA.© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector
Table of Contents
Executive Summary ................................................................................................................... 3
Introduction .............................................................................................................................. 4
Background and Recent Trends ................................................................................................. 6 Page | 1
A look back at 1990‐2011: The US dash for gas and its limits ................................................... 6
The evolution of gas‐coal competition during the past two decades ............................... 6
Assessing current potential switchable gas capacity ......................................................... 8
Characterising the portfolio of switchable capacity .......................................................... 8
Factors affecting utilisation of switchable capacity .................................................................. 9
Fuel prices ........................................................................................................................ 10
Coal contracts .................................................................................................................. 11
Variability in plant level efficiency ................................................................................... 11
Technology factors ........................................................................................................... 13
Role of regulation and policy ........................................................................................... 14
Environmental regulation ................................................................................................ 19
Estimates of switching: observed and projected ...................................................................... 20
Observed switching ................................................................................................................. 20
Projected switching ................................................................................................................. 21
Conclusions on projection for switching by 2017.................................................................... 23
Appendices ............................................................................................................................. 25
Appendix A............................................................................................................................... 25
Appendix B ....................................................................................................................... 27
References .............................................................................................................................. 30
List of Figures
Figure 1 • Evolution of the US wellhead gas price over 1980‐2012 ............................................... 6
Figure 2a • Coal and gas power generation, 1990‐2011 ................................................................. 7
Figure 2b • Coal and gas shares in power generation, 1990‐2011 .................................................. 8
Figure 3 • Switching potential in 2011 ........................................................................................... 9
Figure 4 • United States Henry Hub prices, 2009‐12 ................................................................... 10
Figure 5 • Average length of US non‐lignite coal contracts for power generation, by state ....... 12
Figure 6 • Range of thermal efficiency in US coal and CCGT plants, 2011................................... 12
Figure 7 • Gas switch price based on coal price, for different gas efficiencies and fixed coal
efficiency ...................................................................................................................... 13
Figure 8 • Deregulation in the US power sector and retail electricity prices, 2011 ..................... 15
Figure 9 • Share of coal and gas generated from the regulated and unregulated sector, 2011 .. 16
Figure 10 • CCGT capacity, GW, 2011 ............................................................................................. 25
Figure 11 • Coal capacity, GW, 2011............................................................................................... 25
Figure 12 • Gas costs for power, December 2011 .......................................................................... 26
Figure 13 • Coal costs for power, December 2011 ......................................................................... 26
List of Tables
Table 1 • Individual Case Studies .................................................................................................... 27Coal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
Acknowledgements
The authors would like to acknowledge the members of the Gas, Coal and Power Division (GCP)
of the IEA, in particular Carlos Fernández Alvarez, László Varró and Anne‐Sophie Corbeau, who all
provided considerable guidance and feedback to support the completion of this paper. Input was
Page | 2 also provided by Warner Ten Kate and Johannes Trüby, both secondees to the IEA during the
course of 2012.
Steven Macmillan was a secondee to the International Energy Agency with the support of Origin
Energy (Australia). Hannah Schwind worked as an intern in GCP Division. Alexander Antonyuk left
the IEA in early 2013.
Thanks must also go to Associates of the IEA’s Coal Industry Advisory Board (CIAB), who provided
valuable input. The Energy Information Administration in the United States assisted in the
provision of data and clarification of data points.© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector Executive Summary This paper analyses the impact of the shale gas revolution in North America on the American power sector and contributes to analysis of the economic implications of environmental policies. Lower variable production costs triggered by the US shale gas revolution have enhanced the competitiveness of natural gas‐fired power plants during 2012, especially with respect to coal. Page | 3 However, in light of considerable regional diversity across the US power sector, low fuel prices are only one of many elements that determine the role of gas in the power system. This paper provides an overview of factors that influence this switch and identifies a sample of US states that have a meaningful fuel‐switching potential in terms of unused combined‐cycle gas capacity. From a sample of 18 states (accounting for around 75% of unused combined cycle gas output and around 46.5% of net generation in the United States in 2011), estimates are given for switching observed from late 2011, and a projection of switching to occur by 2017. It is assumed that natural gas prices will increase to USD 4.7/million British thermal units (MBtu) by 2017. Similarly, assumptions are made about other factors, such as the retirement of coal‐fired plants, construction of new combined cycle plants and changes in US environmental regulation affecting coal‐fired plants.
Coal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
Introduction
The United States is by far the largest consumer of natural gas in the world (690 billion cubic
meters (bcm) in 2011, or 21% of the world’s gas consumption (IEA, 2012a)) as well as the second
largest coal user (697 million tonnes of coal equivalent [Mtce] or 13% of global coal consumption)
Page | 4 (IEA, 2012b), albeit standing well behind China. The United States power sector could be
considered as a country on its own: its gas use, almost a third of total US gas consumption,
amounted to around 230 bcm in 2011, which is equivalent to the combined liquefied natural gas
(LNG) exports of the Middle East and Asia Oceania regions. The use of thermal coal by US power
generators was 95% of US coal demand, larger than the global seaborne thermal coal trade.
Hence the US power sector forms a significant part of both the global gas and coal markets, and
any change affecting it in a positive or negative way can have profound implications for the
world.
Such changes are already under way. The shale gas revolution that resulted in the dramatic and
unforeseen increase of US gas production by over 100 bcm over 2007‐11 resulted not only in a
quasi‐independence of the United States from LNG imports – and therefore on global gas
markets – but also in a significant increase of gas use in the power sector. Over the past three
years, as US natural gas prices remained low (on average at around USD 4/MBtuover 2009‐11,
and below USD 3/MBtu for the first nine months of 2012), gas‐fired plants have been slowly but
surely eroding the position of coal‐fired plants as the first energy source for power generation. In
2007, net coal‐fired electricity generation was 2.25 times that of net gas‐fired generation; in 2011
the ratio dropped to only 1.70. The year 2012, with its remarkably low gas prices, continued to
close the bridge between the two fuels, resulting in a 1.16 ratio for the first seven months
This shift from coal to gas for power generation, together with increased LNG production in the
United States has ramifications for energy markets worldwide. On global gas markets, LNG
supplies once earmarked for the United States were available to be redirected to Japan after the
Fukushima accident. Additionally, the United States now plans to become an LNG exporter by
2015, deterring investors previously targeting the North American market for LNG exports.
Moreover, record low natural gas prices in the United States give a competitive edge to the US
industry – notably petrochemicals and fertilisers – while other regions, such as Japan and Korea,
face record gas prices almost six times higher. On global coal markets, the lack of US domestic
demand for coal in the power sector forced US thermal coal producers to look for other markets,
resulting in a marked increase in US coal exports, most of which found their way into Europe. As
a result, coal is winning market share against gas in the European power sector, where gas is
simply no longer competitive. The irony is that the United States, which did not sign the Kyoto
protocol, sees greenhouse gas (GHG) emissions reduced through cheap gas, while Europe, which
was the first to put in place an Emission Trading Scheme, may actually see its GHG emissions
increase in the power sector through gas to coal switching.
These changes, as significant as they have been already, raise two questions that this report
investigates:
whether the penetration of natural gas in the US power sector might have been more
significant except for limitations on switching in particular US regions; and
whether this trend is likely to continue over coming years.
The first part of this report analyses the historical developments of gas and coal in the power
generation sector. In particular, it examines in depth the historic background to coal to gas fuel
switching in the United States, with a special focus on the range of factors that have influenced
or limited the rate of switching. These factors include relative fuel prices, the location of excess
gas‐fired capacity in comparison to existing coal‐fired plants, technological factors, the duration© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector of coal contracts between producers and power generators, the role of regulation (including new regulations covering emissions for coal‐fired plants) and transmission constraints in both power and gas markets. This analysis shows that, despite a large over‐capacity of gas‐fired plants at the country level, the limitations mentioned above currently restrict switching to a theoretical ceiling of 613 terawatt hours (TWh) in a year (which is equivalent to 13% of total US power generation in 2011). Page | 5 The second part provides an estimate of switching that occurred in the 12 month period beginning in October 2011 (when Henry Hub prices fell below USD 4/MBtu for a sustained period), and a projection for switching to occur by 2017. These estimates are based on an analysis of the situation in 18 American states that account for approximately 75% of the unused combined‐cycle gas turbine (CCGT) capacity in the United States.1 The conditions for switching vary between states. The key factors examined are relative fuel prices, the length of coal contracts, the existing unused CCGT potential, an estimate of coal plant retirements due to the legislative requirements on air quality, and an estimate of the expansion in the CCGT fleet occurring by 2017. The meaning of the term “fuel switching” varies depending on the time horizon chosen. In the short term, where no changes in the power plant fleet are possible, fuel‐switching designates instantaneous adjustments of the merit‐order as a response to temporary changes in variable production costs. For example, coal‐to‐gas fuel‐switching within the existing generation capacity signifies that some gas‐fired power plants have cheaper variable production costs than coal, thus triggering changes in the merit order. This “short‐run” switching can occur either within days or over periods of many months, and is of interest in terms of the resilience of the electricity systems, as well as for its impact on commodity markets. In the long run, the power plant fleet itself can change due to additions of capacity, retirements, fuel conversions and retrofits. Those factors then have long‐term effects on the power mix. Both “short‐run” and “long‐run” switching are examined in this paper, the former over months (rather than days) and the latter by analysing the impact of projected price changes, additions and retirements out to 2017. 1 The total is comprised of 14 states, in addition to four states (California, Maine, Oregon and Washington) where there is spare CCGT capacity but no coal output to switch. The 14 states are Alabama, Arkansas, Arizona, Florida, Georgia, Louisiana, Michigan, New Jersey, Nevada, New York, Oklahoma, Pennsylvania, Texas and Virginia.
Coal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
Background and Recent Trends
A look back at 1990‐2011: The US dash for gas and its limits
Page | 6 Natural gas‐fired plants have provided around 60% of additional US power generation over the
past two decades (1990‐2011). While coal‐fired plants also met additional power demand in the
1990s, their contribution to incremental US power output remained flat over most of the last
decade and has been dropping significantly since 2009. The current situation as of late 2012 was
therefore the result of a slow evolution which took place over 20 years and resulted in a
significant overbuild of gas‐fired capacity. The geography of the US power, coal and gas sectors
means that only part of this surplus gas‐fired capacity can replace coal‐fired plants, even when
pricing signals would dictate switching. The following analyses in depth factors which need to be
taken into account while looking at future switching from coal to natural gas
The evolution of gas‐coal competition during the past two decades
Liberalisation of the US power sector accelerated in the 1990s. By this time, the United States
had already developed a well‐functioning gas market and Combined Cycle Gas Turbine (CCGT)
technology was technologically mature. It is also worth mentioning that in the 1970s and 1980s,
US energy policy restricted the use of gas in power generation due to limitations in the supply of
gas (IEA, 2012c). As gas was then considered a scarce resource, its share in the power generation
sector was kept artificially low during that time.
Figure 1 • Evolution of the US wellhead gas price over 1980‐2012
USD/mbtu
9.00
8.00
7.00
6.00
5.00
4.00
3.00
2.00
1.00
0.00
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
2011
Source: EIA.
During the 1990s and into the 2000s, CCGT was considered an investment of choice by new
entrants in the power market. A true boom in gas capacity construction occurred then, with
184 GW of gas‐fired plants built between 1990 and 2010. Indeed, a record of 36 GW of CCGTs
added at the peak of the boom in 2002 (or 57 GW if one includes open‐cycle gas‐fired plants).
Some observers argue that too much capacity was built, which led to its underutilisation later in
the 2000s. Although low gas prices below USD 2/MBtu in the 1990s are often referred to as one© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector
of the main reasons for the surge in gas generation investments, coal prices also dropped during
this period (from USD 33.93 per tonne in 1988 to USD 26.37 in 1999).2 As a consequence, there is
no direct correlation between low gas prices and high gas‐fired capacity additions.
Levelised cost studies sometimes show coal as more competitive than gas‐fired plants (Hogue,
2012). However, CCGT plants offer many advantages, including high efficiency, lower CO2
emissions, relatively quick and cheap construction, modularity and less local resistance to the Page | 7
siting of new plants than for coal and nuclear plants. Moreover, when the distinctive economic
and financial characteristics of CCGTs are taken into account, they reveal their critical advantages
for new entrants in liberalised markets. Indeed, a high degree of correlation between gas and
electricity prices makes CCGTs “self‐hedged” (Roques, 2007). Finally, CCGT investments take
place with a lower capital expenditure than coal or nuclear plants (IEA, 2010).
Despite the significant gas price fluctuations and the dramatic but short‐lived surge in gas
capacity investments that have occurred over the past 20 years, the share of gas in thermal
generation as well as gas‐fired generation increased in a very gradual and steady manner over
the same period. Figures 2a and 2b illustrate this gradual progression of coal and gas output and
their respective shares in thermal generation. In absolute volumes, gross generation from gas‐
fired plants reached about 1 046 TWh in 2011, which is three times higher than in 1990, and
twice more than in the late‐1990s, illustrating the dash for gas that occurred over this period.
Meanwhile, coal‐fired generation increased during the 1990s, then hovered at around the same
level of 2 000 TWh over the last decade until 2008. Since 2009, it has been globally declining to
reach 1 773 TWh in 2011. It appears that during most of these past 20 years, additional gas‐fired
generated electricity (+660 TWh) has actually partly filled the gap created by incremental power
demand (+1 100 TWh), rather than displacing coal.3 Real competition between coal‐ and gas‐fired
plants started in the past four years, prompted by low gas prices. This took place in a context of
stagnating power demand. This competition, however, did not occur everywhere in the United
States, but was mostly concentrated in the eastern part of the country.
Figure 2a • Coal and gas power generation, 1990‐2011
TWh
2500
2000
1500
1000
500
0
1981 1984 1987 1990 1993 1996 1999 2002 2005 2008 2011
Coal Gas
Source: EIA.
2
Bituminous coal, EIA data
3
Additional electricity from all renewable sources added 190 TWh and from nuclear power plants 210 TWh.Coal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
Figure 2b • Coal and gas shares in power generation, 1990‐2011
70%
60%
Page | 8 50%
40%
30%
20%
10%
0%
1981 1984 1987 1990 1993 1996 1999 2002 2005 2008 2011
Coal Gas
Source: EIA.
Assessing current potential switchable gas capacity
As of 2011, capacity utilisation of CCGT plants in the United States at an aggregate national level
was approximately 46.4%, compared with 62% for non‐lignite coal. There is considerable
variation among states, however, with utilisation rates for gas‐fired plants ranging from below
10% in Nebraska and Iowa to over 80% in Connecticut and Alaska.4
Given the large raw switching potential suggested by the low utilisation of US gas‐fired plants,
one could wonder why more switching has not already occurred. The following in‐depth look at
the US energy market elucidates which factors have hampered − and could continue to deter − a
more significant switch from coal to gas.
Characterising the portfolio of switchable capacity
When considering the scope for fuel switching in electricity generation, only a sub‐set of coal‐
and gas‐fired plants is most likely to be substitutable, also taking into consideration the fuel type
and combustion method.
The United States had 415 GW of generating capacity from gas in 2011, compared with around
315 GW of coal‐fired capacity. Running 415 GW of capacity at 100% theoretically equates to
3 637 TWh of output, shown as a maximum output in Figure 3.
Of the 415 GW of gas capacity, as much as 198 GW are open‐cycle plants, which, due to their
lower efficiency, are not as competitive as CCGTs and are therefore unlikely to be substituted
for coal even at prices in the range of USD 2.50‐4/MBtu. Excluding open‐cycle plants results in
a reduction of 1 734 TWh in output.
In practice, 85% capacity is a more accurate maximum running level, since plants require
maintenance. This results in a reduction in potential output of 285 TWh.
4
The United States Energy Information Administration (EIA) is in the process of refining its measures of capacity utilisation,
with a view to reporting consistent monthly figures on capacity utilisation by fuel and state.© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector
From this, it is then necessary to subtract existing CCGT output of 833 TWh, since the
corresponding capacity was already in use and is therefore unavailable for further switching.
Lastly, two states in particular represent limited switching potential. Arizona has relatively
more expensive gas, longer average term coal contracts and less efficient CCGTs, making
switching less economical in that state. Meanwhile, California stands out as a state with a
largely underutilised gas‐fired capacity; however, there is no coal capacity to displace. Page | 9
Subtracting California and Arizona nets a further 171 TWh from the remaining total (assuming
an 85% potential output).
This leaves therefore a maximum switching potential of 613 TWh (or around 17%) of gas‐fired
generation to compete with coal as of 2011. This figure represents a ceiling of possible switching
rather than an actual switchable amount.
Additionally, it is important to look at coal‐fired capacity. The existing 315 GW of coal‐fired
capacity is fuelled by lignite, bituminous and sub‐bituminous coal. Out of 16 GW of lignite‐fired
capacity in the United States, the majority is concentrated in the states of Texas and North
Dakota, with some capacity in Louisiana, Mississippi and Montana. As lignite is a very low‐cost
fuel source, it is generally consumed close to the mine; consequently, it is unlikely that CCGT
capacity could compete with lignite, even at gas prices in the range of USD 2.50‐4/MBtu. In North
Dakota there is little CCGT to switch, whereas in Texas there is sufficient non‐lignite coal capacity
to switch that the state can be included in the 613 TWh.
Finally, growth in overall demand for electricity is falling in the United States, which may reduce
the scope for switching. In this context it is also worth noting the year 2012 was exceptional in
many respects: a mild winter, a hot summer, and frequent outages of nuclear power plants. The
demand of gas‐fired generation in 2012 was therefore driven, inter alia, by abnormal conditions.
Figure 3 • Switching potential in 2011
Twh 4000
3500
3000
1734.117647
2500
2000
3637 285.4323529
1500
833
1000
171
500
613.45
0
Total gas Remove OCGT 15% limitation CCGT output 2011 CA,AZ (at 85%) Potential extra gas
Source: EIA data (EIA‐860) and IEA calculations
Factors affecting utilisation of switchable capacity
Many factors can further affect potential coal‐to‐gas switching and actually explain why switching
has not occurred in a more significant manner. These include:Coal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
the relative fuel prices at state level,
the variability in plant efficiency,
the length of contracts between coal producers and power producers,
technical factors, and
Page | 10 other specificities of the US power market.
These factors are examined in detail in the following sections. They will provide the background
for the analysis of observed switching at state level in the year beginning October 2011, as well as
an estimate of switching occurring by 2017.
Fuel prices
Fuel prices are the primary determinant of dispatch and switching activity between coal‐ and gas‐
fired plants. First, gas prices at the main US hubs have fluctuated considerably since January
2009, making it hard for power generators to predict how they would evolve. Figure 4 shows that
that gas prices remained consistently below USD 4/MBtu for more than three months since the
economic downturn in 2009 in the latter half of 2011.
While looking at the US gas market, one tends to consider only the Henry Hub (HH) price.
Actually, there are many different regional hub prices, the HH usually acting as a reference for
international comparisons or long‐term forecasts. While regional gas prices would tend to follow
HH price movements, there is also great variability between these prices, resulting in widely
different gas prices at the state level, and even among plants. The spread between the different
hub prices is seasonal. The greatest spread, more than USD 1/MBtu, occurs in winter months,
with New England and New York experiencing significantly higher gas prices than the rest of the
country due to lack of gas storage and transportation congestion. Florida also has more
expensive gas prices (see Figure 13 in Appendix A).
At the level of regional prices (and based on available data), substitution seems most likely to
occur on the Eastern seaboard, where relative prices were most favourable.
Figure 4 • United States Henry Hub prices, 2009‐12
Source: EIA.© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector
Coal contracts
The terms and conditions of coal contracts influence the choice of fuel for electricity generation
in the United States, as a larger proportion of coal than gas is bought on a contracted long‐term
basis. For example, 93% of the coal consumed for electricity generation in the United States in
2011 was purchased via long‐term contracts of more than one year, (rather than via spot
Page | 11
purchases), against only 44% of gas (EIA, 2012).
While the exact conditions attached to these contracts are not made public, anecdotal evidence
suggests that many have firm take‐or‐pay clauses, with the result that power producers have
frequently committed to consuming a given level of coal output for several years into the future.
Of the 15 states with the longest average remaining contract terms, four have CCGT capacity
above 5 GW: Arizona, Pennsylvania, Mississippi and Oklahoma. The average contract terms by
state are shown in Figure 5, with these four states highlighted.5
Variability in plant level efficiency
The relative value of natural gas and coal to electric generators cannot be compared solely on a
thermal unit (Btu) basis, since the thermal conversion into electricity (kilowatt‐hours generated
per Btu) varies by facility. US non‐lignite coal plants range in age from one to 88 years, with an
average age of 38 years.6 Due to depreciation and changes in technology, the efficiency of these
plants varies considerably, with most falling in the range of 22 to 35%.7 Likewise, while the CCGT
fleet is much younger (with an average age of 12.5 years), there is still considerable variance in
efficiency, with the bulk of the fleet falling in a range between 40% and 50%, since the first
generation of CCGT plants had considerably lower efficiencies.8 Because efficiency of any one
given plant depends on a combination of factors, such as fuel quality, load factor, cooling
temperature, etc., efficiencies of different plants are difficult to be reported on standard,
comparable bases.
There is no single, definitive source on the distribution of efficiencies in the two sets of
generators, and available data can deliver differing results. A study completed by the California
Energy Commission in August 2011 (Nyberg, 2011) examined the growing efficiency of CCGT
plants in California in the period 2000‐10. Analysing data of state regulatory agencies, the study
found the average efficiency of new CCGT plants in California to be around 48% in 2010.
Aggregate calculations from EIA data (EIA, 2012; EIA, 2013) support this finding; however, EIA
data show considerably less efficiency for CCGT plants in Texas, with an average below 44%.
Texas and California have respectively the largest and third‐largest CCGT fleets in the United
States. At a high level, the range of efficiencies can be estimated, based on a calculation of the
net output compared with thermal input. This calculation has been done at plant level in Figure
6, on a high heating value basis and using net generation. While Figure 6 represents a high level
estimate of the distribution of efficiencies of coal and gas‐fired plants, it is nonetheless broadly
indicative of the variation that exists.
5
In the case of Alabama, one coal contract recorded as expiring in 2099 skews the average by just over two years. The basis
for enforcing a contractual term extending in excess of 80 years is questionable, and so this contract has been omitted from
the data in Figure 5.
6
Age weighted for MW capacity, EIA data.
7
All efficiencies are on a gross calorific basis, based on net generation.
8
Age weighted for MW capacity, EIA data.Coal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
Figure 5 • Average length of US non‐lignite coal contracts for power generation, by state
years
10
9
Page | 12
8
7
6
5
4
3
2
1
0
WI
KY
WV
AR
OH
HI
MN
IN
ME
KS
MT
SC
NV
MS
PA
MD
NM
CA
AZ
WY
NC
OR
DE
IA
IL
TX
MI
NY
LA
VA
OK
TN
UT
SD
WA
AL
NE
NJ
NH
FL
CO
GA
MO
Note: Volume‐weighted average, based on remaining terms on coal contracts from deliveries in 2011.
Source: EIA (EIA‐923); IEA calculations.
Figure 6 • Range of thermal efficiency in US coal and CCGT plants, 2011
Capacity: MW
70000
60000
CCGT COAL
50000
40000
30000
20000
10000
0
20 30 40 50
Efficiency: percent
Source: EIA (EIA‐923); IEA calculations.© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector
Some uncertainty regarding the absolute level of efficiency notwithstanding, it appears that CCGT
efficiencies vary significantly in the US power sector. As a purely theoretical but indicative
exercise, Figure 7 shows the “switching gas price”, depending on the price of coal and the
thermal efficiency of the CCGT plant. As can be seen from the graph, a change of efficiency from
52% to 44% can require a gas price up to USD 0.60/MBtu lower (for a given coal price of
USD 65/t). Interestingly, the differential increases in absolute terms as the coal price increases, Page | 13
which is explained by the fact that a switching price is proportionate to a gas plants’ efficiency,
and thus at higher coal (and electricity) prices, gains (and switching) from higher efficiency are
larger in absolute terms, while fixed in percentage terms.
Figure 7 • Gas switch price based on coal price, for different gas efficiencies and fixed coal efficiency
gas 44% eff gas 48% eff gas 52% eff
5
Gas price, USD/MBtu
4
3
2
50 55 60 65 70 75 80
Coal price, USD/t6000
Note: Coal thermal efficiency fixed at 39% , $/t6000 represents $ per tonne of coal with a 6000 kilocalorie /kilogramme of net calorific
value . Source: IEA calculations.
Technology factors
Limitations of coal and CCGT technologies are also likely to play a role in the choice between the
two fuels. The increasing peakiness of US power load in recent years places certain restrictions on
the dispatch between coal‐ and gas‐fired plants. Where a power producer might otherwise
switch from coal to gas for baseload power and utilise coal to follow variable demand, technology
may limit this, for the following reasons:
Operating range and minimum output,
Start‐up rates, and
Ramp rates.
The geographical location of coal plants may also be a factor in some instances, as discussed later
under the section on transmission constraints.
Operating range and minimum output
The existing coal and CCGT fleets have different optimal capacity factors and the relationship
between utilisation and efficiency differs. The existing US coal fleet may be less well‐suited toCoal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
meeting variable demand because its optimal utilisation falls in a smaller range. The level of
optimal utilisation for a given plant depends on a range of factors, notably its age and its design.
New coal and CCGT plants have relatively similar ranges and can generally operate optimally at
between 70% and 90%, and sub‐optimally at between 40% to 70%, with moderate losses in
efficiency. For older plants, the loss of efficiency at lower levels of utilisation will tend to be
Page | 14 higher (IEA, 2010; NERC, 2010; Platts, 2003). As coal plants are on average 25 years older than
CCGT plants (IEA calculations based on EIA data [EIA‐860]), the efficiency losses associated with
sub‐optimal load factors are greater on average.
Start‐up rates
The start‐up rates for coal‐fired boilers and the steam component of CCGT plants are in the range
8‐48 hours, whereas the gas turbine components of CCGT plants have start‐up rates below one
hour (AEMO, 2010). This allows CCGTs to respond to rapid changes in power demand, albeit at
the efficiency level of an open cycle plant in the early stages (efficiency decreases by around 10‐
20%).
Ramp rates
The ramp rates of US coal‐fired generators depend largely on their vintage. The range for plants
of the 1960 vintage (the average age for a US coal plant being 38 years (IEA calculations based on
EIA data) is around three megawatts per minute (MW/min) for a 500 MW unit. This compares
with average CCGT ramp rates of around 15‐25 MW/min, which is roughly similar to the ramp
rates for coal plants built since 2000. As is the case with operating range, above, while ramp rates
are similar for coal and CCGT plants of similar vintage, the average age of coal plants is much
higher than that of CCGT plants, making coal plants more costly for meeting variable load.
For these reasons, CCGT plants are better placed to respond to variable demand, making coal
plants more expensive to run intermittently. This increases the likelihood that coal plants will be
run at higher capacity factors than CCGT, other factors being equal.
Role of regulation and policy
Besides the considerations regarding switchable gas‐fired capacity and technical, pricing and
contractual limitations on this, there are some specificities of the US power sector to be
considered.
In some regulated states (in the Southeast), due to already relatively lower electricity prices,
there might be less pressure to reduce prices further by switching to cheaper fuels. Although
there might be some discontent about higher end‐user prices in the liberalised northeastern
states, economic and market design factors play a key role. These states sometimes also have
higher fuel prices.
Price regulation
Unlike the gas sector, liberalisation of the US power sector reform is at different stages, which
affects directly the way power prices are formed. Electricity prices are a key factor when
considering electricity market reform. Figure 8 highlights the extent of power sector reform in
each state, alongside average electricity prices. Many states, notably in the centre and southeast
of the United States, have not deregulated power prices, while deregulation has been suspended
in some additional states in the Southwest. States with active deregulation are mostly
concentrated in the North east but also include Texas. However, conclusions cannot be extracted© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector
from the map, as differences in fuel prices between states often play a bigger role to determine
electricity prices than the matter of being regulated/deregulated.
In the context of analysing fuel switching, the regulatory process in regulated states where the
price is lower is expected to put less pressure on power producers to reduce prices further by
minimising fuel costs. In the liberalised north eastern states, economic and market design factors
play a key role, despite some potential discontent about higher end‐user prices. Page | 15
In competitive markets, such as PJM, market design and structure are potentially significant
factors in coal‐to‐gas competition. Capacity payment mechanisms exist in most liberalised US
markets and they constitute a significant share of gas plants’ revenues. For example, in 2010,
CCGT plants in the PJM market received around 30% of their net revenues from capacity
payments (Potomac Economics, 2011). Based purely on the microeconomic theory of profit
maximisation, this fixed stream of revenue should not affect decisions to run gas installations.
However, the reduced risk of making a loss on gas installations thanks to capacity payments
might affect the way market actors make decisions, as utility functions depend on attitudes to
risk, especially when the same owner also has coal‐fired plants.
As shown in the second chapter of this paper, some 12 TWh of fuel switching was estimated to
have occurred in Florida (from a base of coal generation of 56.4 TWh)9 and Florida is a regulated
state, suggesting that public utility regulation does not necessarily dampen economic incentives.
In reality, the impact of regulation is likely to be ambiguous and specific to local conditions.
Figure 8 • Deregulation in the US power sector and retail electricity prices, 2011
Source: IEA research
Some power producers, whose revenues are regulated, face weaker incentives to depart from
existing practice in response to changes in relative gas and coal prices. In 2011, 75% of US coal‐
fired generation was in the regulated sector, against 36.5% of CCGT (Figure 9). In many cases, the
power‐producing entity has the flexibility to increase charges automatically in response to
changes in fuel costs, but should not profit from the fuel component. A regulated entity, which
passes through the cost of fuel directly, is likely to have more discretion about the timing for
9
In the year beginning October 2011, compared with the prior 12 months, see the second chapter.Coal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
switching from coal to gas than a competitive energy producer, since it cannot theoretically
benefit from fuel cost changes nor does it face any negative exposure to these, as they are simply
passed through in higher charges. Even though fuel pass through clauses should theoretically
mean that the fuel choice is neutral in terms of profits, in practice, there are likely to be more or
less significant temporary or permanent cash flow impacts, depending on the precise pass‐
Page | 16 through arrangement in place.
A number of studies have discussed the implications of fuel pass through clauses for the
efficiency of regulated energy providers in the United States (Joskow, 1974; Brown et al., 1991;
Graves et al., 2006). Theoretically, the need to protect a firm from risks associated with rapid
change in fuel costs could be considered to involve some efficiency losses in the use of fuel by
that firm (Graves et al., 2006).10 Knittel (2002) examined the operation of firms in regulated
American states in the period 1981 to 1996, focusing on a handful of states where regulators
modified fuel clauses. Modified fuel clauses require the regulated firm to absorb a portion of the
risk associated with positive or negative changes in fuel costs, whereas under a standard fuel
pass through clause, the end customer bears all risk associated with fuel costs. Knittel found
evidence that providing incentives to regulated firms to keep fuel costs low had increased
efficiency in the use of fuel, suggesting that standard fuel pass through clauses do introduce a
level of inefficiency in the use of fuel among regulated firms.11
Figure 9 • Share of coal and gas generated from the regulated and unregulated sector, 2011
Terawatt hours
2000
1500
1000
500
0
Coal Gas
Regulated Unregulated Unknown
Source: EIA (EIA‐923); IEA calculations
While fuel pass‐through charges may delay a response to a change in relative fuel prices, most
regulated utilities will eventually be required to prove to the regulator that their fuel and
resource decisions have been prudent, as part of a rate case. Therefore, they will seek to move to
the lower cost fuel in the medium term. In the interim, the impact of regulation is ambiguous,
since the clauses essentially appear to provide a utility with extra discretion, either to defer or
bring forward its decision to switch fuels, without having a negative impact on earnings. Such a
decision could then be influenced by additional factors, such as:
whether the entity has long‐term coal contracts;
10
Graves et al. (2006) note that there may also be inefficiency in a regulatory process that requires a rate case each time an
entity needs to adjust its fuel costs.
11
Knittel examined efficiency in the use of a given fuel, rather than the choice between two types of fuel; however, the
implications appear pertinent to a situation where a firm must choose between power generated from fuels of different costs.© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector whether the entity has sufficient coal‐ and gas‐fired capacity to switch from one to the other or must contract for gas‐fired electricity. Some utilities may prefer generating from their own power assets rather than purchasing electricity on the wholesale market, since relying on internal generation may be seen as lower risk. Where they do not have sufficient gas‐fired capacity, they may seek to put off fuel switching until they have their own gas‐fired plant; whether the decision to move away from coal is supported in the relevant jurisdiction. Moving Page | 17 to gas in states where this is supported by policy at state level may facilitate regulatory approvals of future investment; conversely, in states where the coal industry plays a central role in economic activity, utilities may seek to delay fuel switching to support policy objectives of state governments; and some level of generalised inertia or path dependence that leads firms to defer change. Consequently, the impact of fuel pass‐through clauses on switching from coal to gas is ambiguous results, since these clauses may lead to faster or slower switching than would otherwise be the case under purely competitive forces. A general conclusion is that the fuel decisions of regulated utilities will be less closely correlated with changes in relative fuel prices than in states where competitive price pressures more strongly influence fuel choice, but that this could lead to faster or slower switching than would otherwise be the case in a state where the power sector was liberalised. Electricity transmission The United States electricity system is very fragmented due to administrative, infrastructural and natural factors, despite regional coverage of some of the US power markets. For coal and gas plants to compete, they not only need to be connected to the same electricity system, but also to belong to the same administrative unit (market or regulated state). Maps of geographic location of coal and CCGT capacity show that capacity is very unevenly distributed. See Appendix A, Figures 11‐13. California stands out as a state where a large underutilised gas capacity has no coal capacity to displace, and therefore we have subtracted it from the switchable potential, as per above. In states where conditions are otherwise favourable to fuel switching, the electricity grid may limit switching. Specifically, there is very little trade between the three main interconnections in the coterminous American states (Western, Eastern and ERCOT), and within these interconnections, there is limited long‐distance transmission capacity. This means that for fuel switching to occur, a CCGT plant needs to be not too distant from a load served by a coal‐fired plant. Additionally, even where transmission is theoretically available to transport a load, congestion in the transmission system may limit the dispatch of generating units and therefore the coal to gas switch. Finally, in states where coal‐fired generation serves primary as a base‐load energy source, the geographic distribution of plants is relevant to the task of maintaining grid stability. In those states, it may be difficult to switch to base‐load power fueled by CCGT if the geographic distribution of CCGT plants is not comparable. The US Congress Research Service (Kaplan, 2010) conducted a high‐level analysis to identify all major coal plants with one or more existing CCGT plants within a ten‐mile radius, on the assumption that these CCGT plants would be best placed to displace coal within the constraints of the local transmission network. The hypothetical surplus generation for each CCGT within the ten‐mile radius was calculated and assumed to displace generation from the coal plant. At a high level (and examining only this variable), the analysis suggested that existing CCGTs near coal‐fired plants could account for up to 30% of the displaceable coal‐fired generation. Greater displacement of coal by existing CCGTs would depend on more distant CCGTs that might face network constraints. Kaplan (2010) concludes that this analysis “emphasises the importance that
Coal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
the configuration and capacity of the transmission system will likely play in determining the
actual potential for displacing coal with power from existing CCGT plants.” However, it is
impossible to accurately gauge the implications of the layout of the two sets of plants for
switching without a fully integrated model of the entire fleet that can estimate the impact of
changes in the merit order.
Page | 18
Gas transmission
In addition to the constraints of the electricity transmission network, the physical capacity of the
national gas transmission network also affects switching potential. While the regional pipeline
system is designed to deliver the necessary gas to individual plants to allow each to run at full
capacity, increasing the utilisation of the entire CCGT fleet to 85% implies a significant increase of
natural gas production and distribution at the national level (Beach et al., 2012). Beach et al.
estimate that a 7% increase in pipeline capacity (around 4.6 tcf or 130 bcm) would be required
compared to 2008 levels, which falls well within the 22.6 tcf aggregate expansion of pipeline
system capacity targeted for completion by early 2012.
Even if additions to the gas network may seem to have been adequate to allow for a significant
expansion in gas‐fired generation, complications arise in relation to markets for wholesale gas
and gas haulage. The National Petroleum Council (2011) finds that most power generators – and
particularly those selling into unbundled wholesale electric markets – choose less expensive,
interruptible transportation gas pipeline capacity rather than firm contractual capacity. During
peak winter demand conditions, pipeline customers with firm contractual rights use their full
contractual entitlements, meaning that pipelines frequently do not have additional capacity for
interruptible transportation customers. The NPC cites an instance in January 2004 in New
England where 6 GW of gas‐fired generation was unavailable to run at peak times because the
operators had chosen to rely on interruptible transportation, and the winter conditions resulted
in all parties with firm commitments using these to deliver natural gas to residential and
commercial customers. In a 2006 report on gas‐electricity interdependency, the North American
Energy Standards Board (NAESB) identified six areas where standardisation and harmonisation
would facilitate better integration of US gas and electricity markets. Given the lack of uniformity
in approaches in electricity markets, realising these initiatives is challenging. However, this may
become more pressing if is to account for a larger share of the US power generation mix.
The preference among gas‐fired generators for interruptible gas haulage contracts stems in part
from a mismatch between US electricity and power markets. Access to gas transmission networks
is harmonised across states, through standards developed by the NAESB which were designed to
improve transparency and efficient scheduling. These standardised approaches stand in contrast
to the practices in electricity markets, which are not standardised even within one inter‐
connection. For instance, important differences between gas and power wholesale markets exist
in relation to the definition of day and intraday schedules. These differences are exacerbated by
the fact that the gas haulage market is far less liquid, reacting more slowly to rapid changes in
energy demand. NPC (2011) notes that “as a consequence of these inconsistent timelines, the
owner of a gas‐fired generator must either buy gas without knowing if its power will be
scheduled, or submit a power bid before knowing if the gas can be purchased and scheduled. The
cost of covering the risk created by the inconsistency in timelines must be reflected in
generators’ power offers”.12 This has an impact on the relative competitiveness of gas‐fired
generation.
12
Fuel switching away from natural gas to diesel is a further option in these circumstances, but this has no impact on overall
substitution of natural gas for coal.© OECD/IEA 2013 Coal to Gas Competition in the U.S. Power Sector
Environmental regulation
The future retirement of coal‐fired plants as a result of more stringent environmental regulations
may open up opportunities for fuel switching where it might not otherwise be economically
viable. Permitting and licensing of new coal‐fired plants has become more challenging in the
United States, partly as a result of local opposition to the construction of new plants.
Page | 19
Consequently, as older, less viable coal plants are decommissioned, this may create opportunities
to switch to CCGTs or build fresh CCGT capacity.
Of the 299 MW of non‐lignite coal‐fired capacity as of 2010, around 110 GW did not have
emission control equipment (“scrubbers”) or firm plans to install this equipment.13 Among this
capacity, in the 55 GW of older and less efficient plants, the necessary investments to meet
increasingly rigorous emissions control requirements are relatively less likely to justify. Around
36 MW of this capacity is concentrated in mid‐western and southern states Illinois, Indiana,
Michigan, Wisconsin, Alabama, Mississippi, Tennessee and Kentucky.
An estimate of the impact of air quality regulations on coal retirements is provided in detail in the
next chapter.
13
Based on an analysis prepared by ICF International for the Interstate Natural Gas Association of AmericaCoal to Gas Competition in the U.S. Power Sector © OECD/IEA 2013
Estimates of switching: observed and projected
As highlighted in the first part of this report, beyond the theoretical current potential of 613 TWh
of annual output that could have switched in 2012, there are many other factors to be taken into
account to analyse correctly how, where and whether coal‐to‐gas switching can occur. This part
Page | 20 provides estimates of coal‐to‐gas switching that occurred in the year beginning October 2011,
and further switching that will occur out to 2017. The analysis focuses on the situation in 18
American states that account for approximately 75% of the unused CCGT potential in the United
States (selected on that basis).14 The 18 states accounted for 1 011 TWh of net generation output
in 2011 in the United States, or 46.5%. The states account for 78% of the installed CCGT capacity
in the United States but only 36% of installed non‐lignite coal generating capacity.
The estimates of switching simplify a number of factors, including some outlined in the first
chapter of this study, focussing primarily on elements that can be readily measured. A further
simplification is that the analysis examines each state as a producer and consumer but not an
importer of energy, since the EIA data is available at state level rather than at the level of
interconnection.
Observed switching
An estimate of observed switching has been made by comparing CCGT and coal output in the
year commencing October 2011 with output in the preceding 12 months. The year beginning
October 2011 is chosen because the last quarter of 2011 was the first time since the economic
downturn that gas prices for power producers at HH remained consistently below USD 4/MBtu
for a sustained period (longer than 3 months), USD 4/MBtu being a level below which switching
has previously been observed to occur.
The estimate of observed switching is considered in this manner:
Coal and CCGT‐fired output from October 2010 to September 2011 is compared with output
from October 2011 to September 2012, the first being a year of higher gas prices relative to
coal, and the second a period of lower gas prices relative to coal. Where both CCGT output
increased and coal output decreased year‐on‐year, the smaller of the two changes is assumed
to represent switching. This is against a backdrop of low or no growth in overall electricity
demand.
A likely scope for switching is gauged, by considering:
the gas price at which capacity will switch, in the absence of other constraints (in the
manner presented in Figure 7), as well as actual gas prices in the period under analysis;
the primary measurable non‐price constraints, being the volume‐weighted average of
coal contract terms; the efficiency of CCGT and coal plant relative to national averages;
the potential for increasing CCGT output based on existing plants, and the potential for
coal retirements; in order to determine whether overall conditions will be favourable to
switching.
The estimate of observed switching is considered in light of whether conditions appear
favourable. In other words, in a state where the gas switching price was met for an extended
period during the 12 months from October 2011, with short coal contract terms and considerable
surplus CCGT potential, significant switching should already have been evident in the year
14
Fourteen states in addition to four states where there is spare CCGT capacity but no coal output to switch (California,
Maine, Oregon and Washington).You can also read
