|Two men on a wild and barren
plain suddenly spy a huge bear charging towards them. One man
immediately starts putting on his running shoes. “How futile!” the
other exclaims, “you’ll never outrun that bear!” His companion
drily replies: “I don’t need to outrun the bear.”
In any race, it’s vital to understand whom you need to outrun
and what it takes to win. Yet an incomplete picture of the
competitive landscape may be the nuclear industry’s greatest
impediment to sound strategic planning, profitable investment, and
credible public discourse.
This knowledge gap is understandable because the industry has
been working so hard to achieve impressive progress in so many
areas at once: operational consistency and reliability, simpler
and cheaper designs, better inherent safety, streamlined siting
and approvals, stronger government support, and other
prerequisites for nuclear revival. But while these demanding tasks
have taken so much attention, our bear has gained speed,
approaching from behind.
Steve Kidd, the World Nuclear Association’s head of strategy
and research, asked in NEI (September 2005): “How can new nuclear
power plants be financed?” He predicted this would “prove very
challenging” in the private capital market, even though several
studies found circumstances in which new nuclear build could
compete with “building gas- or coal-powered generating capacity of
similar magnitude.” Investors, he suggested, remain concerned
about public opposition, siting and licensing, quick construction
at predictable cost, safety, security, liability,
nonproliferation, waste, decommissioning, and smooth operation.
And he felt nuclear power’s economic merits would emerge if we had
“power markets where different technologies can compete on a level
playing field and where long-term investment in capacity is
These issues remain important and challenging, yet the market
reality is even more complex. Resolving all perceived risks
wouldn’t ensure nuclear power’s market success. Rather, new
nuclear plants and central coal- or gas-fired power plants are all
uncompetitive with three other options whose status, prospects and
value propositions are not well understood within the nuclear
industry: certain decentralised renewables,
combined-heat-and-power (CHP), and efficient end-use of
electricity. In a rapidly evolving energy marketplace full of
disruptive technologies, nuclear power’s biggest challenges are
not political but economic.
Most nuclear advocates consider the various ‘micropower’ and
‘negawatt’ (electricity saving) alternatives necessary and
desirable but relatively small, slow, immature, uncertain, and
futuristic – complementing central thermal stations without
threatening their primacy. In this view, nuclear power will
predominate within a balanced low-carbon electricity mix, and
generation will remain overwhelmingly centralised, because nothing
smaller could scale up enough to power a growing global economy.
As the WNA website states: “Only nuclear power offers clean,
environmentally friendly energy on a massive scale.” Yet this view
is hard to reconcile with recently compiled industry data.
The World Alliance for Decentralised Energy’s (WADE’s) March
2005 compilation from industry equipment sales and project data
estimated that decentralised resources in 2004 generated 52% of
the electricity in Denmark, 39% in The Netherlands, 37% in
Finland, 31% in Russia, 18% in Germany, 16% in Japan, 16% in
Poland, 15% in China, 14% in Portugal, and 11% in Canada. WADE’s
definition includes CHP gas turbines up to 120MWe, CHP engines up
to 30MWe, CHP steam turbines only in China, windpower and
photovoltaics (PVs), but no hydropower, no other renewables, no
generators below 1MWe, and no end-use efficiency.
Figure 1 shows the annual output of low- and no-carbon
micropower compared with nuclear power. No hydroelectric dams over
10MWe are included. Average nuclear capacity factor (load factor)
is assumed to rise linearly from 84.1% in 1982 to 88.5% in 2010.
Up- and downratings, new units commissioned, and permanent
retirements are shown consistently for all technologies.
Worldwide electrical output of decentralised low- or no-carbon
generators (except large hydro)
This data shows that micropower has already eclipsed nuclear
power in the global marketplace already. About 65% of micropower’s
capacity and 77% of its output in 2004 was fossil-fuelled CHP,
which was about two-thirds gas-fired, and emitted 30% to 80% less
carbon (averaging at least 50% less) than the separate power
plants and boilers or furnaces it replaced. The rest of the
micropower was diverse renewables, whose operation, like nuclear
power’s (neglecting enrichment), releases no fossil-fuel carbon.
Micropower’s output lags its capacity by three years due to
typically lower capacity factors for small hydro (~46%), windpower
(~25-40%) and PVs (~17%) than for CHP (~83%), biofuelled
generation (~70%) and geothermal (~75%).
Worldwide, low- and no-carbon decentralised generators
surpassed nuclear power’s total installed capacity in 2002 and its
annual output in 2005. In 2004 they added 5.9 times as much net
capacity and 2.9 times as much annual output as nuclear power. The
respective industries project that in 2010, micropower will add
136-184 times as much capacity as nuclear power will add,
depending on CHP, wind and PV estimates (see Figure 2). Such
projections are quite uncertain, but qualitatively clear. After
2010, whether the ageing reactor fleet declines as projected by
Schneider and Froggatt (see NEI June 2005, p36) or more slowly as
predicted by the International Energy Agency (IEA), even with
major new nuclear build in countries like China, micropower will
continue to pull ahead.
Figure 2 shows net capacity added by each technology in each
year since 1990. Figure 2 also includes a leading indicator for
nuclear power: construction starts through 2004. Their unknown
size thereafter shouldn’t materially affect 2010 completions. In
2004, windpower just in Germany and Spain added 2GWe each,
matching the average global net addition of nuclear capacity per
annum (pa) during 2000-10. Worldwide nuclear construction starts
will soon probably add fewer GWe pa than PV installations.
Global additions of electrical generating capacity by year and
These comparisons omit another key decentralised competitor –
saved electricity – that is seldom properly tracked but clearly
substantial. At constant capacity factor, the 2.0% and 2.3%
decreases in US electricity consumed per dollar of GDP during 2003
and 2004 would respectively correspond to saving 14 and more than
16 peak GWe, plus 1GWe pa of utility load management resources
added and used. That’s 6-8 times US utilities’ declared 2.2GWe of
peak savings achieved in 2003 by demand-side management. Since the
USA uses only one-quarter of global electricity, and more
efficient end-use is a global trend, worldwide electrical savings
almost certainly exceed global additions of micropower (24GWe in
2003, 28GWe in 2004). Global additions of supply-side plus
demand-side decentralised electrical resources are thus already an
order of magnitude larger than global net additions of nuclear
capacity (4.7GWe in 2004).
Few investors and policymakers realise this, because most
official statistics under-report decentralised and
non-utility-owned resources, show only physical energy supply, and
pay little attention to drops in energy intensity, whatever their
cause (in most countries, chiefly more efficient end-use
technologies). Per dollar of GDP, US primary energy consumption
has lately been falling by about 2.5% pa; electricity by 2.0% pa.
Only 22% of the 1996-2005 increase in delivered US energy services
was fuelled by increased energy supply, 78% by reduced intensity –
yet the latter four-fifths of market activity remains dangerously
That invisibility lately led US merchant firms to lose ~$100
billion by building ~200GWe of combined-cycle gas plants for which
there was no demand.
This calamity for investors could soon recur on a larger scale
and not only in the power sector. The US Energy Policy Act of 2005
greatly increased subsidies and regulatory aid for energy supply
whilst largely ignoring demand-side resources. Yet ‘negawatts’
expand as energy prices and as policies that have held per-capita
electricity use flat for 30 years in California and are decreasing
it in Vermont spread to other US states.
Like micropower, efficiency tends to be installed more quickly
than supplies. If it continues to reach customers and grab
revenues first, it will glut markets, crash prices, and bankrupt
producers, just as it did under similar conditions in the
mid-1980s. This would intensify investors’ risk aversion.
Many factors tug energy outcomes in diverse directions.
Windpower, for example, is heavily subsidised in the UK where it
has yet been slowed onshore by local opposition, and offshore by
two years’ government debate on how to finance its links to the
grid. Similarly, US windpower gets a production tax credit (PTC)
but its erratic and brief renewals by Congress have repeatedly
bankrupted leading wind turbine producers. Overall, the
correlation between renewable installation rates and government
subsidies is not clear-cut. Neither are per-kWh subsidies’
relative sizes for renewables versus central plants, particularly
nuclear power. Nor is it obvious whether relative subsidies are
more or less important than the barriers that in most countries
still block fair competition. This analytic fog makes it dangerous
to assume that micropower’s success is subsidy-driven, or that its
obscure implementation obstacles are less important or tractable
than nuclear’s familiar ones.
A simpler explanation for micropower’s market success might be
superior basic economics. Figure 3 supports this hypothesis by
comparing the cost of a kWh delivered to the retail meter from
various marginal sources.
Nuclear power’s competitors on a consistent accounting basis.
Levelised cost of delivered electricity or end-use efficiency (at
2.75¢/kWh delivery cost for remote sources).
In concluding that nonhydro renewables are unsuitable “for
large-scale power generation where continuous, reliable supply is
needed,” the WNA commits two common fallacies: supposing that
making large amounts of electricity requires large generating
units, and forgetting that ceteris paribus many small units near
customers are more reliable than fewer, bigger units far away.
Central thermal stations are no longer the cheapest or most
reliable source of delivered electricity, because generators now
cost less than the grid and have become so reliable that 98-99% of
US power failures originate in the grid. Thus the cheapest, most
reliable power is typically produced at or near customers.
Three-quarters of US residential and commercial customers use
electricity at an average rate not exceeding 1.5 and 12kWe,
respectively – severely mismatched to central plants’ GWe scale.
The WNA acknowledges a debate about scale, but ignores its
profound implications and assumes central plants will remain
dominant. Prudent investors favour micropower.
Of course, if decentralised resources had little potential to
meet the world’s rising needs for energy services, they’d be of
minor competitive concern: one should worry about a bear, but
hardly about a mouse. Yet a mighty swarm of mice is another
matter. The modern literature suggests that decentralised
resources’ collective practical potential has been understated, as
if the stunning technological and economic advances in
conventional energy supply didn’t apply to its rivals. To the
contrary, such progress tends to be faster in decentralised
resources. For example:
- At less than the delivered cost of just operating a
zero-capital-cost nuclear plant (~$0.04/kWh), potential US
electricity savings range from two to four times nuclear power’s
20% share of the US electricity market, according to bottom-up
assessments summarised by the Electric Power Research Institute
(EPRI) and Rocky Mountain Institute’s joint Scientific American
article (September 1990). EPRI’s Clark Gellings confirmed in
2005 that the US electric end-use efficiency resource is
probably now even bigger and cheaper, because better
mass-produced technologies more than offset savings already
captured. Utility-specific data confirms a broad downward trend
in the unit cost of ‘negawatts’.
- CHP potential in industry and buildings is very large if
regulators allow it. Waste-energy CHP alone is preliminarily
estimated by Lawrence Berkeley National Laboratory to have a
technical potential nearly as large as today’s US nuclear
capacity, though cost and feasibility are very site specific.
- Modern windpower’s US potential on readily available rural
land is at least twice national electrical usage.
- Other renewable sources of electricity are also collectively
important – small hydro, biomass power (especially CHP),
geothermal, ocean waves, currents, solar-thermal, and PVs. These
sources and windpower also tend to be statistically
complementary, working well under different weather conditions.
All renewables together (excluding big hydro), plus solar
technologies that indirectly displace electric loads
(daylighting, solar water heating, passive heating and cooling),
have a practical economic potential many times total US
electricity consumption – at least an order of magnitude greater
than nuclear power provides today.
- Even at such a scale, a diversified renewable portfolio
needn’t raise land-use concerns. For example, a rather
inefficient PV array covering half of a sunny area 160¥160km
could meet all annual US electricity needs. In practice, since
sunlight is distributed free, PVs would be integrated into
building surfaces, and installed on roofs, over car parks, and
along roads, both to save land and to make the power near loads.
Specious claims persist comparing (say) the footprint of a
nuclear reactor with the (generally miscalculated) land area of
which a fraction – a few percent for wind turbines – is
physically occupied by energy systems and infrastructure. In
fact, total fuel cycle land use is roughly comparable for solar,
coal and nuclear.
Thus renewables clearly have a very large global potential. The
IEA’s World Energy Outlook 2004 foresees a 2030 renewable
potential of ~30,000TWh pa (less than a quarter of it from
hydropower). Such massive production would become far easier with
CHP and efficient end-use. It still wouldn’t be easy, but neither
would central stations of similar output – especially for serving
the two billion people not now on any grid.
But might decentralised supply- and demand-side resources be
too slow to deploy, requiring central stations to provide enough
reliable power, quickly enough, to meet burgeoning demand? This
widely held view seems inconsistent with observed market
behaviour. As shown above, micropower and efficient end-use,
despite many obstacles, are already adding an order of magnitude
more GWe pa than nuclear power worldwide. Their brisk deployment
reflects short lead times, modularity and economies of mass
production (they’re more like cars than cathedrals); usually-mild
siting issues (except in some unusual windpower cases); and the
inherently greater speed of technologies deployable by many
diverse market actors without complex regulatory processes,
ponderous enterprises, or unique institutions.
Of course every energy option faces specific obstacles,
barriers, and hence risk of slow or no implementation at scale.
Efficiency, for example, faces some 60-80 market failures, many
arcane, that have left most of it unbought. Yet US electric
intensity has declined at an unprecedented average rate of 1.5% pa
since 1996 even though electricity is the form of energy most
heavily subsidised, most prone to split incentives, least priced
on the margin, and sold by distributors widely rewarded for
selling more kWh. Such firms as DuPont and IBM routinely cut their
energy intensity by 6% pa with attractive profits and no apparent
Letting all decentralised resources really compete risks not a
dry hole but a gusher. Just during 1982-85, when California’s
three investor-owned utilities offered a relatively level playing
field, fair competition elicited 23GWe of efficiency plus 21GWe of
generation (13GWe of it actually bought) rising by 9GWe pa. The
resulting glut, 144% of the 1984 peak load of 37GWe, forced
bidding suspension in 1985, lest every fossil and nuclear plant be
displaced (which in hindsight could have been valuable).
Investors appreciate that diversification is wise but must be
intelligent. The strategic virtue of a diversified portfolio
doesn’t justify buying every technology or financial asset on
offer. The sweeping claim that ‘we need every energy technology’ –
as if we had infinite money and no need to choose – is often made
but cannot withstand analysis. The WNA’s website doesn’t mention
demand-side resources, and denies the existence of a large and
compelling literature of nuclear-free, least-cost, long-term
scenarios published over decades (in 1989, for example, Vattenfall
published a roadmap for rapid economic growth, full nuclear
phaseout, one-third power-sector CO2 reduction, and $1 billion pa
cheaper energy services). But investors with similarly limited
vision are in for a shock. As all options compete and as
increasingly competitive power markets clear, any supply
investment costlier than end-use efficiency or alternative
supplies risks being stranded by retreating demand.
OIL, CLIMATE AND STRATEGY
A major argument often made for new nuclear build is oil
displacement; yet this has already been largely completed. Only 3%
of US electricity is made from oil and less than 2% of US oil
makes electricity. Worldwide, these figures are around 7% and
falling. Most of that oil, too, is residual, not distillate, and
is burnt on relatively small grids by smaller plants with low
capacity factors, unsuited to nuclear displacement. Both oil and
fungible natural gas can be far more cheaply displaced by other
means, mainly by doubled end-use efficiency.
A more compelling need is displacing coal-fired electricity to
protect the earth’s climate. Yet nuclear power’s dubious
competitive economics could make it counterproductive, for four
- Most of the carbon displacement should come from end-use
efficiency, because it’s profitable – cheaper than the energy it
saves – and quick to deploy.
- End-use efficiency should save not just coal but also oil,
particularly in transport. Comprehensive energy efficiency
addresses 2.5 times as much CO2 emission as any electricity-only
- Supply-side carbon displacements should come from a diverse
portfolio of short-lead-time, mass-producible, widely applicable
and accessible, benign, readily sited, rapidly deployable
- The total portfolio of carbon displacements should be both
fast and effective.
This last point highlights a troublesome implication of Figure
3’s cost comparison. Buying a costlier option, like nuclear power,
instead of a cheaper one, like ‘negawatts’ and micropower,
displaces less carbon per dollar spent. This opportunity cost of
not following the least-cost investment sequence – the order of
economic and environmental priority – complicates climate
protection. The indicative costs in Figure 3 (neglecting any
differences in the energy embodied in manufacturing and supporting
the technologies) imply that we could displace coal-fired
electricity’s carbon emissions by spending $0.10 to deliver any of
- 1.0kWh of new nuclear electricity at its 2004 US subsidy
levels and costs.
- 1.2-1.7kWh of dispatchable windpower at zero to actual 2004
US subsidies and at 2004-2012 costs.
- 0.9-1.7kWh of gas-fired industrial cogeneration or
~2.2-6.5kWh of building-scale trigeneration (both adjusted for
their carbon emissions), or 2.4-8.9kWh of waste-heat
cogeneration burning no incremental fossil fuel (more if
credited for burning less fuel).
- From several to at least 10kWh of end-use efficiency.
The ratio of net carbon savings per dollar to that of nuclear
power is the reciprocal of their relative cost, corrected for
gas-fired CHP’s carbon emissions (assumed here to be three-fold
lower than those of the coal-fired power plant and fossil-fuelled
boiler displaced). As Bill Keepin and Greg Kats put it in Energy
Policy (December 1988), based on their still-reasonable estimate
that efficient use could save about seven times as much carbon per
dollar as nuclear power, “every $100 invested in nuclear power
would effectively release an additional tonne of carbon into the
atmosphere” – so, counting that opportunity cost, “the effective
carbon intensity of nuclear power is nearly six times greater than
the direct carbon intensity of coal fired power.” Whatever the
exact ratio, their finding remains qualitatively robust even if
nuclear power becomes far cheaper and its competitors don’t.
Speed matters too: if nuclear investments are also inherently
slower to deploy, as market behaviour indicates, then they don’t
only reduce but also retard carbon displacement. If climate
matters, we must invest judiciously, not indiscriminately, to
procure the most climate solution per dollar and per year.
Empirically, on both criteria, nuclear power seems less effective
than other abundant options on offer. The case for new nuclear
build as a means of climate protection thus requires
Micropower and its natural partner, efficient end-use, have
surpassed and outpaced central stations despite many obstacles.
Being diverse, ubiquitous, plentiful, widely available, largely
benign, and popular, they are also hard to stop. To be sure, much
work remains to purge the artificial barriers to true competition
between all ways to save or produce energy, regardless of which
kind they are, what technology or fuel they use, how big they are,
or who owns them. But such a free market, for which Kidd rightly
calls, seems increasingly unlikely to favour nuclear power.
Rather, the economic fundamentals of distributed resources promise
an ever-faster shift to very efficient end-use combined with
diverse generators the right size for their task. That shift could
render insufficient or even irrelevant the resolution of the
perceived non-economic risks that preoccupy the nuclear industry.
The better the industry and its investors understand this, the
more likely they are to fulfill reasonable expectations, apply
their talents effectively, and help achieve the global energy,
development, and security goals to which we all aspire.
Research and comments by Rocky Mountain Institute colleagues
Nathan Glasgow, Ken Wicker, Kyle Datta, Dr Joel Swisher PE, and
John Anderson PE and by many other colleagues are gratefully
This article was first published in Nuclear Engineering
The standard studies to which Steve Kidd referred (MIT,
University of Chicago, IAEA, OECD, amongst others) all compare
only the busbar costs of central stations – nuclear, coal, and
combined-cycle gas. The assumptions and findings of MIT’s 2003
analysis, The Future of Nuclear Power, are adopted here. However,
to compare central stations (or remote windpower) fairly with
onsite CHP and efficiency one must add to the former a delivery
cost, conservatively assumed here to be $0.0275/kWh – the 1996
embedded average for US investor-owned utilities.
The MIT study found that a new 1GWe advanced LWR with a 40-year
life, 85% capacity factor and merchant financing has a busbar cost
of $0.0702/kWh (in 2004$), equivalent to $0.0977/kWh delivered. If
its capital cost fell by 25% (from $2094/kWe to $1570/kWe
overnight cost, compared to ~$2200/kWe for the new Finnish plant,
an apparent loss-leader), its construction time fell from five to
four years, the capital market attached zero nuclear risk premium
and fuel plus O&M cost dropped from $0.0157 to $0.0136/kWh (the
lowest-quartile recent US value), the delivered cost could
decrease to as little as $0.0715/kWh.
Imposing a high price on carbon emissions ($100/t CO2) could
raise the nominal cost of new delivered coal power from $0.072/kWh
to $0.097/kWh (burning $1.33/GJ coal), and that of new
combined-cycle gas power from $0.067-0.086/kWh to $0.078-0.098/kWh
(at a levelised gas price of $3.6-7.6/GJ, equivalent to escalating
those initial constant-$ gas prices at 5% pa). Figure 3 shows how
these changes could shift the central plants’ relative costs.
However, the standard studies ignore decentralised competitors,
perhaps in the erroneous belief they’re too small or slow to
matter. Let’s consider three kinds. (There are more, notably the
diverse non-windpower renewables whose observed uptake bespeaks
economic merit, but to avoid complex site-specific comparisons,
and because windpower’s siting and intermittence make it a
difficult case, let’s use it as a surrogate for all decentralised
Lawrence Berkeley National Laboratory reported in August 2005
that more than 2.7GWe of US windpower projects installed during
1999-2005 had busbar costs, including PTC, ranging from $0.015 to
$0.058/kWh (excluding one outlier), with a capacity-weighted
average of $0.0337/kWh. Western US utilities’ resource plans use
levelised costs as low as $0.023/kWh, and the lowest 2003 nonfirm
wind energy contract price was $0.029/kWh, but we conservatively
assume $0.030-0.035/kWh. The 2005 spike in wind turbine prices,
25-50% above 2003’s, appears to reflect temporary imbalances: spot
shortages that have filled all makers’ books through 2006 are due
largely to PTC-related postponement of US projects from 2004 to
2005-6, whilst high steel prices will also boost central-station
costs. On the contrary, industry and government expect windpower’s
costs to fall by ~$0.01/kWh during 2003-12 – more than the
$0.0086/kWh levelised post-tax value of the PTC. For illustration,
Figure 3 optionally adds back windpower’s PTC but not the pre-2005
subsidies received by central stations, especially nuclear power.
Those nuclear subsidies are complex, diverse and disputed but the
most authoritative independent US expert, Doug Koplow, estimates
~$0.0079-0.0422/kWh, increased by another ~$0.034-0.040/kWh in the
Energy Policy Act of 2005 for at least the next 6GWe ordered.
For comparability with central stations, we assume that making
windpower fully dispatchable costs $0.009/kWh – two-thirds for
hydroelectric or other firming, one-third for grid integration. We
conservatively adopt that extra cost, higher than most western US
utilities pay or assume, partly in case some remote sites need
Conversely, central stations are assumed to incur no
reserve-margin nor spinning-reserve costs, though their larger
unit sizes make them tend to fail in larger chunks and for longer.
Intermittence does need attention and sound engineering, but it’s
not unique to renewables: every source of electricity is
intermittent, differing only in why they fail, how often, how big,
how long, and how predictably. Grid operators’ recent assessments
confirm that windpower’s intermittence even at high penetrations –
about 14% for Germany, 20-25% for several US grids, and 30% for
west Denmark – would be manageable at modest cost, typically a few
$/MWh, if renewables are properly diversified, dispersed,
forecasted, and integrated with the existing grid and with demand
The WNA’s latest (February 2005) renewables webpage disagrees:
it ignores technological and siting diversity and demand response.
The WNA therefore concludes that intermittent renewables “cannot
directly be applied as economic substitutes for coal or nuclear
power” and will require “reliable duplicate sources of
electricity, or some [unavailable] means of electricity storage on
a large scale” – “almost 100%” backup – raising windpower’s cost
to twice the “generation cost” of nuclear or coal.
Highly intermittent supplies were long assumed to be limited to
5-10% of grid capacity, then 20%; the WNA claims 10-20%. Yet with
better forecasting, grid integration, distribution automation and
smart power electronics such supposed limits continue to recede.
Windpower penetrations today are 20% in Denmark and up to 30% in
three German states. On windy, light-load days in certain regions
of Denmark, Germany, and Spain, windpower can exceed 100% of load,
foreseeably and manageably. Yet windpower’s grid integration costs
are proving negligible or very modest. The corresponding costs of
integrating other resources, all with nonzero forced outage rates,
are of course already borne unnoticed. Nor are “reliable duplicate
sources” proposed for nuclear plants, which in 2003 suffered
prolonged large-scale curtailments in Europe’s heatwave, restart
after the USA/Canada blackout and Tokyo Electric’s safety
CHP is a far more conventional and reliable resource already
common in many countries. Figure 3 shows US costs for three
arrangements, the first two based on actual projects by a leading
US developer, Primary Energy, with 0.9GWe of operating projects.
Conventional gas-fired combined-cycle industrial CHP – with
levelised gas prices of $5.4-8.7/GJ, a 10% pa return over 25
years, and unit sizes of 28-64MWe – delivers new electricity for
$0.038-0.073/kWh. Recovered industrial heat previously wasted can
be worth more than CHP’s other operating and capital costs, making
its net cost of delivered electricity negative (-$0.021 to
-$0.047/kWh) in the three 60-160MWe projects evaluated. We graph
instead their positive all-in electricity price
($0.011-$0.026/kWh), with the possibility of costs up to
~$0.04/kWh in less favourable cases. Well-integrated into a
commercial building and with demand-side management, gas-fired
‘trigeneration’ of power, heat, cooling, and perhaps other
services can deliver electricity at a net cost around
$0.01-0.03/kWh, or up to about $0.07/kWh with sub-optimised
The final major competitor shown in Figure 3 is efficient
end-use of electricity. Carefully evaluated programmes of many US
utilities have yielded reliable, durable, and accurately predicted
savings at societal costs ~$0.01/kWh or less in commercial and
industrial retrofits. Less optimised programmes or those
emphasising homes can incur average costs up to ~$0.03-0.05/kWh.
Alternatively, integrative design techniques well demonstrated in
many buildings and industrial sectors often achieve very large
savings at reduced capital cost, hence at a negative ‘cost of
saved energy’ (investment divided by the discounted stream of
lifetime electricity savings).
See www.rmi.org/sitepages/pid171.php#E05-08 for documention.
Decentralised resources’ cost advantage (Figure 3) is robust
even against implausible improvements in central stations’
technology or regulation. For example, if some new sort of fission
or fusion reactor could provide free steam to the turbine, the
remainder of the central thermal plant would still cost too much
to compete. And the cost comparisons shown have two other major
conservatisms favouring central plant: they reflect a static
snapshot of competitors’ costs, not (save one windpower
illustration) their continuing rapid decline in real cost; and
they count as zero all but one (thermal integration) of the 207
‘distributed benefits’ described in Rocky Mountain Institute’s
book, Small Is Profitable: The Hidden Economic Benefits of Making
Electrical Resources the Right Size. The market is increasingly
counting those benefits which collectively boost value ~10-fold,
enough to flip most investment decisions.
This increase in value has three separate causes, excluding
such externalities as environmental and social benefits. The most
important distributed benefits come from financial economics:
- Small, fast modules incur less financial risk than big, slow
projects. In a typical substation support application, this can
raise the tolerable capital cost of a distributed resource, like
PVs, by about 2.7-fold.
- Renewables avoid the financial risk of volatile fuel prices,
raising windpower’s typical value by about $0.01-0.02/kWh.
These and other financial-economics benefits typically boost
decentralised projects’ economic value by about an order of
magnitude if they’re renewable, ~3-5-fold if they’re not.
Better known are such electrical engineering benefits as
avoided grid costs and losses, increased reliability and
resilience, more graceful fault management, free reactive power
control (from DC sources inverted to AC), and longer distribution
equipment life (by means of reduced heating and tapchanging).
Together, these typically increase value by ~2-3-fold – more if
the distribution system is congested and new distribution capacity
can be deferred or avoided, or if especially reliable or
high-quality power is required. Finally, scores of diverse
‘miscellaneous’ benefits typically about redouble economic value –
more if ‘waste’ heat can be recaptured.
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Copyright 2005 CyberTech, Inc.