Most determinations of levelized cost of electricity (LCOE) ignore
grid integration costs. As share on the grid of variable generation, or variable renewable energy (VRE), basically wind
and solar, grows the cost of accommodating that generation also grows. This
means that the cost to accommodate a unit amount of variably generated power
grows as percentage of wind and solar on the grid grows. LCOE has been criticized
as a metric for investment decisions with good reason. It is a misleading
metric. Some models consider accounting for avoided costs of building new
generation (say for distributed resources addressing peak shaving) but those
should also account for unavoidable costs (say for battery back-up, peaking
plant back-up, or start-stop damage to peakers). Clearly, LCOE as a metric is inadequate
and needs to be revised into something more functional. Scientist Joseph Fournier notes that those very significant extra hidden costs, including transmission and distribution, are passed on to consumers:
“Ultimately, grid operators amalgamate the total costs of
the system and pass these onto the retail consumer.”
“Those who use unit Levelized Cost of Energy (LCOE) of a
unit facility are ignoring reality and guilty of misrepresentation.”
In the early
years of solar and wind cost accounting the cost of grid integration could be quasi-ignored
but as integration costs per unit of power increase those costs become harder
to ignore. Grid integration for renewables is more expensive than grid
integration for more concentrated fossil, hydro, and nuclear power plants. Intermittency
is the costliest variable of wind and solar when comparing to other resources.
Part-time resources can’t run a full-time world without humungous spending on
back-up generation resources: batteries, gas peakers, distributed energy
resources that can be tapped, and the extra transmission lines and components
to enable the shifting of loads when needed. Solar and wind need to be moved via
transmission to where they are needed when they are being overgenerated at peak
generation times or the power is lost in curtailment.
Various
methods of estimating full system costs attempt to quantify cost per MWh
produced in order to compare full system costs for different energy
sources. The EIA has a method and papers have been written suggesting different
costs and ways to classify and attribute grid integration costs. In my 2022 book
Natural Gas and Decarbonization I coined the phrase levelized cost of
grid integration (LCOGI) The basic formula is: Levelized full system cost
of electricity (LFSCOE) = Levelized cost of generation (LCOG) + Levelized cost
of grid integration (LCOGI), or LFSCOE = LCOG + LCOGI. Grid integration costs
are of several types. All energy sources have some grid integration costs, but
variable generation has the highest costs.
Robert Idel writes in his 2022 paper in Energy:
“ … the function of supply in electricity markets is
not to generate electricity but to provide a specified amount of electricity to
a specific place at a particular time. The locational aspect adds significant
additional costs to renewables that are generally less flexible about where
they can be sited than fossil fuel plants. As a result, a larger grid is
required to transport the electricity from, e.g., hydropower plants to the
demand in urban areas. These transmission costs are partly taken care of in some
LCOE estimates when a transmission cost adder is included in the LCOE. But the
timing aspect turns out to be even more crucial and the focus of this paper.”
His explanation of the crux of the issue is pretty
useful:
“As long as the share of intermittent generation is
low, sufficient dispatchable generation capacity will usually be available to
step in and replace missing intermittent generation output. Economically, the
fact that intermittent generation has no obligation to meet the demand can be
seen as a hidden subsidy. One can even go one step further and argue that
intermittent generation is of zero value if it cannot be made available to
consumers who demand a steady electricity flow. To do that, however, supply and
demand on the network must always be in balance. In effect, the ability to
schedule other generators to continuously maintain that balance is necessary to
give value to renewable output. The dispatchable generators thus raise the
value of renewable generation, but the subsidy is “hidden” because the latter
does not have to pay for it. Once the share of intermittent generation
increases to a certain level (and dispatchable capacity is shut down), efforts
have to be taken to maintain system reliability. But who should be responsible
for these costs? How can the cost of integrating renewables into the system
(which increases significantly with their market share) be included in the
evaluation of their cost?”
As modern humans
living in the modern world, we have expectations of affordable electricity
being available to us. Up to $4 billion people around the world do not have adequate
electricity access, about half of the people in the world. Intermittent
electricity is obviously not an option so all intermittent sources must be
backed up. Those needs drastically increase the costs of providing a certain
amount of electricity for all 24 hours of a day and all seasons of the year. Thus,
the real value of dispatchable electricity is much higher than that of
electricity that is subject to the limitations of intermittency. While this is
no doubt true, the total net difference in value is difficult to quantify. The
value of electricity changes through time. The juice must be apportioned in a
balanced way so on a grid electricity supply and demand must be kept in balance.
This requires availability of generation to replace other generation when it
becomes unavailable. It becomes unavailable on different time and intensity scales:
no sun at night, less sun in the winter, less sun on cloudy days. Night and day
are quite predictable. The seasons are generally predictable. The clouds are
not predictable. Even though night and day are quite predictable electricity
demand may or may not be predictable. We know there is a commonly occurring electricity
supply-demand imbalance, the solar duck curve, on hot late afternoons in places
with high solar penetration on the grid like California during high air
conditioner usage after people return home from work and increase demand just
as solar resources are going dark. But as we saw in August 2020 in California
when this caused forced power outages, it was reserve capacity that was
inadequate. There is a cost to having reserve capacity on stand-by ready to provide
power. The inadequacy was partially due to the effects of heatwaves that cause
outages at gas-fired plants so that dropped off some reserves, but it was
mostly due to the sheer need for power. Other contingencies like low hydro
output and unavailability of imported power from a nearby grid due to low wind
output and their own higher needs due to heatwave, also contributed to the problem.
Power system operators must prepare and make available if needed multiple power
generation sources to be on stand-by ready to provide power if and when needed.
Gas combustion turbine peaking plants that only run 5% of the time are a poor
investment, can require significant maintenance due to starting and stopping
frequency, put out more carbon emissions per MWh than combined cycle gas plants,
and some or much of those emissions are attributable to changes in supply from intermittent
sources. However, they are needed as an affordable way to provide reserves. There
should be an accounting difference applied between more efficient gas power (combined
cycle) and less efficient gas power (simple cycle gas turbine).
Household Electricity Prices: U.S. Avg vs. California and Germany. Source: Alex Epstein. Fossil Future. 2022.
System LCOE or Levelized Full System COE (LFSCOE) –
Models and Accounting
Before I look
at Robert Idels LCOE accounting I want to mention a few other attempts to
quantify full system costs for economic analysis and for comparing the cost and
emissions attributes of different energy sources. The following section is excerpted
from my 2022 book, Natural Gas and Decarbonization:
New Ways to Compare: System LCOE to Account for Grid
Integration Costs and Other Comparisons
Through time
the lack of fuel costs of solar and wind add up to operational savings. There
is no need to pay-as-you-go. That is why levelized cost of electricity often
show wind and solar as being the cheapest forms of energy during the full life
of the projects. While this may be true, the upfront costs of wind and solar
are quite high, as noted, over three times those of natural gas combined cycle.
For solar in particular, but also wind, there may be grid integration costs
that may not be attributed in the graphs below and those costs will increase as
more of that variable generation penetrates grids. Gas is available 24/7. Solar
is available in the daytime but much less in the short cloudy days of winter in
the most populated parts of the US. Wind is intermittent and variable. The
second of the two graphs below, shows that it is lifetime fuel costs that make
lifetime LCOE slightly higher for natural gas relative to wind and solar.
2026 Expected Total Capacity-Weighted Levelized Cost of Electricity (for life of plant). Data Source: Energy Information Administration. (Note: by 2026 wind PTC is expected to be phased out and solar ITC is expected to be phasing lower and adding it in would put solar PV at 29.04)
2026 Expected Total Capacity-Weighted Levelized Cost of Electricity (for life of plant) and Comparison of Upfront Costs and Lifetime Fuel Costs. Data Source: Energy Information Administration. (Note: by 2026 wind PTC is expected to be phased out and solar ITC is expected to be phasing lower and adding it in would put solar PV at 29.04)
The EIA’s
method of calculating final or total capacity-weighted levelized cost of
electricity is a complex formula. They consider and calculate levelized avoided
cost of electricity (LACE) and levelized cost of storage (LCOS) where
applicable. LACE seeks to estimate the value of dispatchability which addresses
some of the grid integration costs. No fuel costs help wind and solar catch up
economically through time, somewhere around year 30. Wind and solar are slow to
break even, but they are good investments through time. As we gain better
knowledge of how to integrate them effectively and lower those costs, we can
reduce future costs. Perhaps we need to factor in a levelized cost of grid
integration (LCOGI). This cost will vary by generation sources, supply, and
demand. It will also increase through time as grid integration becomes more
complex as expected with higher amounts of variable generation. This will also
add to the solar and wind costs through time as integration costs are expected
to rise through time which offsets both efficiency gains and cost reductions.
In comparing
levelized costs there are different ways to present those costs to suit the narrative
that the comparer wishes to advance. LCOE is often not a good way to compare
real world costs. There are differences in cash flow, opportunity costs,
discount rate, and present value. The simple fact that wind and solar have the
lowest “discounted lifetime average generation costs per unit of energy
($/MWh),” or LCOE, does not mean wind and solar are more competitive.
Different kinds of energy have different values. Reliable dispatchable energy
is worth more to the whole than variable generation. A 2016 paper in the
International Association for Energy Economics, Why Wind is Not Coal: On the
Economics of Energy Generation, does indeed attempt to quantify value of
different sources of energy. In the abstract of the paper they explain this
value as follows:
“Electricity is a paradoxical economic good: it is
highly homogeneous and heterogeneous at the same time. Electricity prices vary
dramatically between moments in time, between location, and according to
lead-time between contract and delivery. This three-dimensional heterogeneity
has implication for the economic assessment of power generation technologies:
different technologies, such as coal-fired plants and wind turbines, produce
electricity that has, on average, a different economic value. Several tools
that are used to evaluate generators in practice ignore these value
differences, including "levelized electricity costs", "grid
parity", and simple macroeconomic models.”
The authors
also note that LCOE and other common comparison methods introduce bias by not
properly valuating the reliability, dispatchability, and flexibility of
resources like natural gas. They introduce the concept of System LCOE as a
comparison method. I’m guessing this should include my LCOGI designation. They
mention two biases introduced by LCOE: 1) it favors base-load generation over
peak-load generation and 2) at high renewables penetration it favors that
renewables generation over dispatchable generation. To get a better
understanding of the limitations of LCOE and why it needs reconciled I include
a quote from the World Resources Institute from an August 2019 article by Laura
Malaguzzi Valeri, INSIDER, Not All Electricity is Equal – Uses and Misuses of
Levelized Cost of Electricity (LCOE):
“The LCOE metric is concerned only with costs. By
ignoring the revenue or value of the electricity generated, it implicitly
assumes that all technologies provide similar services. However, picking
electricity sources is not the same as choosing among brands of gasoline, as
not all electricity is created equal. Electricity generated now provides a
different value than electricity generated several hours from now because
demand for electricity varies over time and electricity storage is expensive.
Electricity generated farther from consumption centers is more expensive than
nearby generation because transmission is costly. Electricity generation that
is easy to predict is more valuable than unpredictable generation because it
helps electricity system operators maintain the balance between demand and
supply. Electricity generation that emits more pollutants is more harmful than
cleaner generation. This is why LCOE on its own is insufficient for determining
which technology investors or utilities should build.”
A February 2021
research paper in the International Journal of Energy Research seeks to
quantify the grid integration costs of solar PV. This study is from Italy where
combined cycle natural gas is currently the largest electricity generator.
Integration costs are separated into grid costs and balancing costs. Grid costs
include transmission costs, adequacy costs, curtailment costs, and the costs of
reinforcing the distribution network. Balancing costs include start-up costs
and decay of efficiency costs. Italy was separated into regions for the study.
One of the conclusions I gathered based on charting and graphing the solar PV
integration costs was an avg. of about 31% additional costs for system LCOE
than for the solar PV LCOE alone. This is for solar PV without storage. Adding
storage in a solar-plus-storage has the additional costs at 24% for system LCOE
but the costs of storage would cancel that out and more, especially in the
short-term. Comparing this to the EIA’s
total system LCOE suggests that the EIA is leaving out some amount of
integration costs, particularly for PV solar. It calculates LACE which
addresses some of that and also accounts some distributed energy advantages of
renewables, but the challenges outweigh the advantages in many cases at
present. The EIA total system LCOE comparison shows that in 2026 it will be
similar for CCGT, solar, and wind, the three cheapest widespread resources.
CCGT will be a little higher in that scenario but does retain its value as a
dispatchable fuel, its lower up-front costs per electricity produced, and its
pay-as-you-go cashflow advantage. The Italian study suggests high integration
costs for solar PV at 31% of the standard LCOE of solar PV. It is not certain
how the EIA analysis calculates integration costs. With LACE they attempt to
measure economic competitiveness of different technologies. They use a metric
LACE-to-LCOE (or LACE-to LCOS in the case of storage), This is called the
value-cost ratio. A value-cost ratio of less than one indicates that cost
exceeds value and a value-cost ratio of greater than one indicates that value
exceeds cost. The EIA cost-value ratios for different technologies suggest that
by 2026 solar, some solar-plus-storage, geothermal, and CCGT will be the most
attractive investments in some areas. Solar PV is best at 1.06, CCGT is even at
1, and onshore wind is at 0.98.
System Levelized Cost of Electricity and its Components,
a solar PV case study. Source: Veronese, E, Manzolini, G, Moser, D. Improving
the traditional levelized cost of electricity approach by including the
integration costs in the techno-economic evaluation of future photovoltaic
plants. Int J Energy Res. 2021; 45: 9252– 9269. https://doi.org/10.1002/er.6456
Now we return
to include other attempts to quantify System LCOE. We can see that there are
many things that can be accounted to get an idea of the true cost of
intermittent resources. Unfortunately, many have to be apportioned or
attributed to renewables costs or fossil energy costs in varying amounts. Fossil
fuel power plants need transmission lines but far less total length in lines than
renewables do. Apportionment can be tedious and error prone. The goal of
comparing resources is to compare apples to apples, oranges to oranges, without
skipping anything major or apportioning incorrectly. Fossil systems must account
for the fuel, which costs varying amounts through time. Robert Idel’s analysis
is perhaps starkly realistic, showing that it is the hidden subsidy that values
renewables at low cost to provide when in fact they are expensive to provide. We
know wind and solar cost more to build as they have high upfront costs, but renewables
do not have fuel costs, so renewables increase in value through their life cycle
compared to resources that need fuel.
We know that grids
with high amounts of wind and solar provide electricity that costs more for
consumers than grids with lower amounts of it. One might also say that cheap natural
gas has masked some of those costs for grids that increased natural gas as well
as wind and solar on their grids. We also know that grid integration costs rise
as more variable generation is added to the grid. How much is the question.
Ueckerdt et al
in 2013 first described the notion of System LCOE to account for grid integration
costs. The paper describes LCOE as “the full life-cycle costs (fixed and
variable) of a power generating technology per unit of electricity (MWh).” They
also noted then that LCOE is it is/was is a flawed method that needs to be
refined and that more variability = higher costs. Power systems were modeled after
Ueckerdt etal’s marginal system LCOE of VRE2 for up to 60% VRE but not
higher. The 2018 EU modeling study mentioned above attempts to evaluate higher
than 60% VRE. The authors note that the two biggest strategies for managing variation
are transmission and storage. They also note that earlier modeling did not
consider trade between nearby grids, a variation management strategy enabled by
transmission. Robert Idel notes that Ueckerdt etal’s System LCOE accounts for
integration and balancing but is incomplete. He notes that LCOE of renewable
sources of electricity depend highly on their market share. Wind generation costs
remain constant when more is added but costs increase significantly. He notes a
calculation from the Ueckerdt etal method where the System LCOE for wind in
Germany increase from 60 EUR/MWh to almost 100 EUR/MWh if the share increases
from 0% to 40%.
The goal of System
LCOE is to account for all costs, mostly grid integration costs, per unit of
energy produced. Authors of a 2022 paper on redefining System LCOE point out
the non-linear nature of power generation. Intermittency creates a demand for balancing
that increases non-linearly with higher VRE on the grid. They advocate to make
System LCOE more mathematically precise so that it can be standardized to weigh
for policy. They consider that System LCOE isolated for each technology should
be developed in order to make more detailed analyses. In terms of markets the
great variability and ranges in estimated LCOE for power projects makes it hard
to compare the economic merits of projects.
Marginal System LCOE (a better metric). Source: As above.
As can be seen from the graphs above, the Marginal System LCOE for wind doubles that of coal for a VRE share of about 75% and increases much faster after 80%. We can also see that wind was never cheaper than coal under that metric, as it is in the graph above of the inadequate and incomplete accounting of the Avg. System LCOE, where wind is cheaper than coal till about 50% VRE share and only accelerates slightly beyond 75-80% share.
A table from Idel’s paper seems to give solar and wind
very high LFSCOE’s but I am not sure the context here, it could be for higher
VRE penetration.
The bottom line perhaps should be a
reminder that when people say that wind and solar are the cheapest forms of
energy, that is not quite true at all, not even close really.
References:
Levelized
Full System Costs of Electricity. Robert Idel. Energy. Volume 259, 15 November
2022, 124905. Levelized
Full System Costs of Electricity - ScienceDirect
Joseph Fournier - LinkedIn post, April 2023.
Natural
Gas and Decarbonization. Kent C. Stewart. 2022.
Re-Defining
System LCOE: Costs and Values of Power Sources. Yuhji Matsuo.The Institute of
Energy Economics, Tokyo 104-0054, Japan. Energies 2022, 15(18), 6845; https://doi.org/10.3390/en15186845.
September 2022.
Lion Hirth, Falko Ueckerdt, and Ottmar Edenhofer. Why Wind Is Not Coal: On the Economics of Electricity Generation. The Energy Journal, 2016, vol. Volume 37, issue Number 3. Abstract. EconPapers: Why Wind Is Not Coal: On the Economics of Electricity Generation (repec.org)
Valeri, Laura Maguzzi. INSIDER, Not
All Electricity is Equal – Uses and Misuses of Levelized Cost of Electricity
(LCOE). World Resources Institute, Ausut 1, 2019. INSIDER: Not All Electricity Is
Equal—Uses and Misuses of Levelized Cost of Electricity (LCOE) | World
Resources Institute (wri.org)
Veronese, E, Manzolini, G, Moser, D.
Improving the traditional levelized cost of electricity approach by including
the integration costs in the techno-economic evaluation of future photovoltaic
plants. Int J Energy Res. 2021; 45: 9252– 9269. https://doi.org/10.1002/er.6456
Levelized Costs of New Generation Resources in the Annual Energy Outlook 2021. Energy Information Administration, February 2021. Levelized Costs of New Generation Resources in the Annual Energy Outlook 2021 (eia.gov)
The marginal
system LCOE of variable renewables – Evaluating high penetration levels of wind
and solar in Europe. Lina Reichenberg, Fredrik Hedenus, Mikael Odenberger, and Filip
Johnsson. Energy. Volume 152, 1 June 2018, Pages 914-924. The
marginal system LCOE of variable renewables – Evaluating high penetration
levels of wind and solar in Europe - ScienceDirect
System LCOE:
What are the costs of variable renewables? Falko Ueckerdt, Lion Hirth, Gunnar
Luderer, Ottmar Edenhofer. Energy. Volume 63, 15 December 2013,
Pages 61-75. System
LCOE: What are the costs of variable renewables? - ScienceDirect
No comments:
Post a Comment