Most energy observers recognize that the cost of renewable
energy has declined dramatically in the last decade. The investment firm Lazard
produces a periodic report on the average cost of generation from different
electric power sources – the “levelized cost of electricity” in energy geek
parlance. Their latest
report shows that over the last decade the levelized cost per
unit of electricity from new utility-scale onshore wind and photovoltaic (PV)
solar power plants has dropped about 70 and 90 percent, respectively.
In many places, the cost of new renewable generation is at or below that of
existing conventional sources like natural gas, coal and nuclear.
This would seem to be good news for those interested in making
energy clean and cheap. Yet, a recent study suggests that policies that mandate
renewable use have driven up the retail price of electricity and have been an
expensive way to achieve greenhouse gas reductions – often an implicit reason
for those mandates. While it seems paradoxical that electricity prices could be
rising while generation costs are falling, this possibility is an artifact of
how electricity markets work and how these workings have grown more complex as
the industry evolves from a more centralized fossil fuel-based generation base
to a more distributed and renewable base. Let’s explore this and see what it
says about the road ahead.
Why Renewable Generation
Costs Have Plummeted
There are several reasons for the steep reduction in renewable
costs. One is the improvement in basic product design. Wind turbines are now much larger and have much higher capacity factors than
a decade ago. Although the new designs are more expensive up front, increased
capacity and capacity utilization have outpaced those higher costs to lower the
cost of energy produced. A typical base-to-blade tip height for onshore
turbines is now often over 500 feet – as tall as the Washington Monument – and
we are seeing single turbine capacity of 5 MW or more, enough to power around
1,700 US homes over the course of a year.
Another reason for the cost decline is improvement in
manufacturing efficiency which has lowered the costs of producing solar PV
panels dramatically, particularly in China. And per unit installation “soft”
costs are declining as project developers gain more experience and
installations have moved from small scale (rooftop solar) to utility-scale
operations (solar farms of hundreds of acres).
These dramatic renewable generation cost declines have been
attributed to policies such as tax credits, preferential feed-in tariffs, and
renewable portfolio standards (RPS), which directly target the use of
renewables, expand demand and create cost-reducing economies of scale to meet
that demand. Renewables that were once inarguably much more expensive and
required large subsidies and mandates to incentivize adoption have slid into
grid parity territory, now able to compete directly with conventional sources
in many places.
How Electricity Prices Can
Rise While Generation Costs Fall
The release this spring of a working paper by
economists at the Energy Policy Institute at University of Chicago (EPIC)
ignited a debate on the cost-effectiveness of renewable mandates. The paper
examined the effects of renewable portfolio standards (RPS) programs, which
have been adopted by 29 states and Washington DC, finding that these policies
have raised retail prices considerably and have reduced CO2 emissions
only modestly.
We will return to that debate in a moment, but for now let’s ask
- if the cost of renewable power generation is falling, how can their use cause
retail prices to rise? \
This paradox is even more striking when we consider that more
renewables actually can drive down the wholesale prices that
electricity generators are paid. Because variable renewable energy (VRE)
resources wind and solar incur virtually all of their costs up front and incur
no fuel costs to produce electricity, the average cost of VRE generation is
much higher than the marginal cost, which is close to zero. Much electricity in
the US is transacted in states with competitive wholesale electricity markets.
Marginal costs set prices in competitive markets, which means that the
penetration of VRE can push down wholesale power
prices, even more so when the VRE resource is receiving a per unit subsidy, as
is the case with wind. This is something that has placed financial
pressure on legacy resources such as coal, nuclear and natural
gas plants that do incur fuel costs and other marginal costs of generation. It
would seem, then, that higher renewables should lead to lower electricity
prices.
But wholesale prices are paid to the generators; the retail
prices paid by final customers reflect the full cost of delivering electricity.
Generation, though the largest component, only accounts for 44 percent of the
total cost. The other main costs affected by renewables integration are
transmission and distribution of electricity to its point of use, reliability
costs to maintain stable voltage and frequency, maintenance needed to keep the
system running, depreciation and taxes.
Unit costs, however, tell only part of the story. Individual
power generators, whether conventional power plants or wind farms, seldom
operate in isolation; they are each part of a larger grid-connected system that
aggregates power across generators to deliver power to a region of consumers.
VRE’s effect on system costs will depend in part on the cost of the electricity
that it is displacing, which in turn depends on the location and timing of its
deployment. Wind generation at night in the Midwest may be displacing coal,
while solar generation in the afternoon in California may be displacing natural
gas, each with different cost profiles. And to handle the intermittency of VRE,
system operators need to activate ramping resources more frequently to meet demand.
These flexible plants are typically more expensive to operate and thus higher
deployment can raise total system costs even as renewable costs decline.
Moreover, these resources must be kept on hand to provide reliable capacity in
a market characterized by more intermittent supply and the costs of maintaining
this capacity is passed along to consumers.
To cost-effectively scale up renewables, they must be sited
where they are most productive – in places with plenty of sun, wind and land.
That is typically not close to the population centers where users locate, so
more transmission infrastructure is required to connect supply and demand. This
may be having an effect on system costs. Between 2012 and 2017, when non-hydro renewables generation grew by 77 percent, transmission
costs rose by 50 percent. While not all transmission cost increases
nationally can be attributed to renewables expansion – maintaining old lines
and modernizing for grid reliability are other reasons – there are notable
cases where renewables are driving transmission investments. The Competitive
Renewable Energy Zone project in Texas, for example, invested
$7 billion to connect wind generation in sparsely populated west Texas to the
state’s population centers.
The connection between generation costs and retail prices is
also affected by whether the state in question has traditional cost-of-service
regulation or has restructured to allow wholesale or retail competition. The
former situation may create more room for passing along to rate payers the
recovery costs of stranded non-renewable assets resulting from RPS mandates.
The EPIC paper mentioned above took many of these factors into
consideration and used econometrics to conclude that states with an RPS had
statistically significant higher post-implementation prices than those without.
Some critics argued against the methods used,
the extent to which it was peer-reviewed, and the implications drawn
for the wider policy debate. Criticism is standard fare in academic research,
especially when a critical and high profile policy is at issue. I don’t intend
here to divine the criticisms and render a verdict on the study’s validity.
Rather, if we were to take their findings at face value that RPS mandates drive
up retail prices, what does that foretell about future efforts to scale up
renewables?
The Past Is Not Prologue
As the saying goes, past results do not guarantee future
performance. For one thing, some of what is observed RPS effects on retail
prices may reflect the initial use of older, higher-cost renewable technologies
when the programs first started. As newer and lower cost technologies get
adopted, lower prices may follow.
But while early RPS programs may have created some high
generation cost legacies, the relatively modest targets may mean that system
limits were only barely tested – VRE levels in the US are still below 10
percent. Several states have
set targets for the US of up to 100 percent renewables by mid-century.
The
National Renewable Energy Lab reports that a large grid system
with 30 percent VRE can operate with minimal system disruption. Going beyond 30
percent, however, can present new challenges. Lawrence Berkeley National Lab
(LBNL) examined three scenarios (high
wind, balanced VRE, and high solar) across several different US power markets.
In each scenario, ancillary services costs to maintain reliability increase
substantially. They also report modest retirement of legacy capacity (4-16%),
especially coal, oil and steam turbines, which could lead to some stranded
asset cost pass-through to consumers during the transition. The LBNL study did
show annual average wholesale energy prices declining with increasing VRE
penetration, but also an increase in price volatility.
To the extent that intermittency contributes to higher system
costs, technological fixes like improvements in the capacity and cost of
grid-scale energy storage, economic fixes like real-time pricing to drive more
efficient demand response, and institutional fixes like the establishment of a
regional transmission organization (RTO) in the renewables-rich
western US, could mitigate these factors and push generation costs
down. Again, though, at the expense of higher transmission costs.
The more we move toward a system with a high share of
renewables, though, the more likely that the entire business
model for electricity will need to change. A world in which
high renewables penetration translates to low wholesale prices is a world in
which investment incentives are not strong for any form of generation. If
private capital is to fuel the renewables wave, it seems likely the sector will
need to move from a more commoditized market where revenues are determined by a
price per kilowatt hour to one in which revenue is generated by providing
guaranteed delivery of electricity when it is needed from sources either
desired by the customer or required by regulation. This is much like the way
phone and internet service is delivered today. When that happens, customer
costs will reflect quality more than quantity and the means by which generators
are compensated will become even more complex, but perhaps easier to identify
whether customers will pay more or less for higher use of renewables.
Brian Murray
I am Director of the
Duke University Energy Initiative, a university-wide interdisciplinary hub for
energy research, education and engagement, and research professor at Duke’s
Nicholas School of the Environment, where I teach courses in economics and energy
systems transformation. My work on the use of economic incentive mechanisms to
address energy and environmental challenges has informed public policy and
business decisions at home and abroad. I have worked extensively on the
economics of climate change policy, including the design of policy features now
being used in carbon markets to contain costs and price volatility. I hold both
a doctoral and master's degree in resource economics and policy from Duke
University and a bachelor's degree in economics and finance from the University
of Delaware. I have held many jobs over the years from caddie to construction
worker, telephone installer, tree planter, property manager, IT consultant,
research director, professor, and policy advisor.
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