How Market Rules Are Holding Back Energy Storage

Energy storage is surging. The
U.S. Energy Storage Monitor Q4 2018
estimates that
installations totaled 338 megawatts in 2018, and will grow to 3.9
gigawatts by 2023, much of it front-of-the-meter utility-scale
projects.

This exponential growth has been driven by state mandates and
regulatory actions (especially in California) and limited to
vertically integrated utilities outside of the organized power
markets serving two-thirds of all U.S.
electricity consumers. Despite storage’s value to the grid, it
has not found success in wholesale markets.

This mismatch is best explained in two words: rules and revenue.
Wholesale market rules are organized around legacy assets,
restricting storage from selling all potential services, which in
turn limit storage’s wholesale revenue streams. 

Recognizing these barriers, the Federal Energy Regulatory
Commission issued
Order 841
to stimulate access to wholesale markets. At the end
of 2018, FERC-regulated independent system operators (ISOs)
responded with their implementation plans. 

The Energy Storage Association’s overview
of these proposals, with filtered comments by effects upon possible
revenue streams, provides helpful insight.

Source: Estimation by Customized Energy Solutions, Ltd.
*Topic letters and numbers correspond to layout of Order 841
**Green: Likely compliant; Yellow: Potentially non-compliant; Red:
Non-compliant

Storage can generate revenue in organized power markets in three
ways:
platforms, products and paydays
. Because different projects tap
these potential revenue streams in different ways, implementation
plans for Order 841 will affect them quite differently.

Platforms: The best-laid plans

ISOs conduct planning processes identifying opportunities for
new transmission to improve reliability or market efficiency,
and storage
is increasingly being considered
as a lower-cost,
non-transmission alternative to boost reliability.

Here’s an example: A relatively isolated area on the grid must
plan for losing a transmission line or local generator during peak
demand. Rather than adding transmission or local generation,
building storage can carry the local grid
through an emergency
. If the economics add up, the project
can be built and paid on a cost-of-service basis, financed through
regulator-approved transmission charges.

Storage here plays the same role as “reliability
transmission expansion
,” but it can also play the role of
“economic transmission” — transmission built to move surplus
energy to constrained areas and thereby reduce prices. This was
part of FERC Order 1000’s vision, which required regional
transmission operators to consider “non-transmission
alternatives” in planning processes. But only one economic
storage-as-transmission project exists within any ISO territory
today, located
near Baltimore
 on the PJM grid.

ISOs have hesitated to fund such projects, because while
“reliability” storage is tied to a definite grid emergency risk
which determines its usage, “economic” storage requires ISO
instructions about when to buy and sell power. This could challenge
ISO market independence, since how ISOs dispatch storage invariably
affects prices, which could make them look like self-dealing market
participants.

However, ISOs already regulate power flow over transmission,
which certainly affects power prices. When ISOs propose new
transmission to relieve congestion in high-demand areas (and thus
reduce high prices), local generators are first to complain about
lost revenue.

ISO independence in these cases is preserved by combining
transparent cost-benefit analysis and security-constrained economic
dispatch with financial
transmission rights
 — standard methodology for fairly moving
power across transmission lines and distributing revenue from
arbitraging local price differences. Markets can dispatch storage
in similar ways, according to transparent optimization, and assign
financial storage rights to whoever paid for storage. Like
transmission, storage would become “open-access,” benefiting
consumers.

While storage provides similar services to transmission, it
offers additional benefits, such as improved ease of siting
compared to transmission siting and permitting, which can take
years to resolve, depending on the proposal’s complexity. For
example, Tesla needed only six months to construct and connect a

100-megawatt South Australia storage facility
providing
reliability services comparable to transmission upgrades —
and saving
customers $40 million
in one year.

The concept of storage-as-a-transmission-asset is in its
infancy, focused on potential reliability asset roles. ISOs have
said very little on how Order 841 will shape this potential revenue
stream — but this is a space to watch.

Products: Fee for services

While ISOs are uncomfortable paying for storage services through
transmission access charges that passively incorporate storage into
the grid, some have been receptive to storage competing to provide
fixed services like fast frequency response, capacity, or
regulation.

But technological neutrality may not be achievable in many cases
where services were defined before batteries and other clean
technologies like renewables changed the game. Order 841 was meant
to push open this door, but implementation plans still leave much
to be desired.

Theoretically, fitting storage into technology-neutral products
should be simple. But storage resources are energy-limited (they
can’t convert fuel to electricity forever), they must be charged
and take more energy to charge then they deliver, and they may be
entirely driven by power electronics (no spinning inertia).

These differences mean existing market product definitions are
often ill-suited for storage. And while most incumbent participants
often provide ancillary services for just a fraction of their
revenues, storage projects dedicated to a single service (such as
regulation) could have their entire business model upended by
simple rule changes.

Storage attributes like how fast projects can change output,
their ability to reduce air pollution, or their quick and modular
deployment pace, are not always valued in markets. These attributes
provide grid benefits but need revised power market rules for
properly valuation. The standard equivalence for utilities between
batteries and natural gas peakers seems to require a 1-to-4 power
ratio (i.e., a 1 megawatt/4 megawatt-hour battery).

Impact of 4-Hour Storage Dispatch on Net Load in
California During Peak

Source: NREL

However, shoehorning batteries into definitions based on other
technologies is not necessarily economically efficient — some
peak needs may last longer, some may be more sporadic, and others
will change over time with the economics of generation sources. A
battery’s highest value application may involve a
portfolio including different power ratios
.

Incremental Peak Demand Reduction Credit as a Function
of Storage Capacity in California, 2011

Source: NREL

Collecting storage revenue by meeting grid-needs through
products aspiring for technology neutrality always depends on the
fine print. Shaping these products will be an uphill battle without
proactive
support from regulators
and market operators. As a new
competitive entrant to most markets, storage — especially
battery storage — is not always positioned to ensure rules
properly value their services.

Consider PJM’s approach to incorporating storage into its
capacity performance model. They propose that storage systems only
qualify for capacity payments if they can provide ten hours of
storage, a duration that severely disadvantages battery storage
economics, even though it may provide much-needed capacity over
shorter timescales.

Paydays: Profiteer or just an independent
businessperson?

Storage resources can avoid being shoehorned into the wrong
glass slipper by directly competing in energy markets. What could
be simpler than arbitrage: Buy low, sell high?

Unfortunately, today’s markets don’t provide enough revenue
this way. Consider daily wholesale electricity price differentials
in two ISOs with the most market spikes, California’s CAISO and
Texas’ ERCOT, where crudely estimated annual revenues from buying
low and selling high each day (with no roundtrip losses) come out
to $10-20 per kilowatt-hour of storage capacity per year, not quite
enough to be in the money but close to the prices coming out of
vertical utilities like NV
Energy’s recent announcement
adding 100 megawatts of
battery storage.

The closer to a real-time market storage operates in, and the
higher the power ratio, the more revenue is available from
arbitrage. For example, a battery storage unit with a 4 megawatt to
1 megawatt-hour power ratio and 20 percent round-trip losses
operating in the 2017 Houston load-zone real-time market could make
as much as $57 kilowatt-hour per year. This system would likely
cost $300-400 per kilowatt-hour plus some costs associated to the
high power ratio, making it an attractive investment, especially
with high
prices expected across ERCOT
 in coming summers.

This contrasts other ISOs with lower price differentials, and
highlights the ability of energy-only
power markets
 to illuminate where investments have the
most value.

Even if energy arbitrage revenues become sufficient to support
storage investments, today’s markets still maintain some
barriers. In ESA’s analysis of Order 841 compliance plans for
participation models, bidding parameters, and
state-of-charge-management, almost all the ISOs failed to fully
comply. 

Today’s energy storage opportunity, tomorrow’s energy
system disruptor

Storage has jumped from tomorrow’s clean technology to

one of today’s regulatory agenda drivers
, but the
industry’s true potential has yet to be tapped, especially across
multiple value streams. 

Storage projects are well-suited to access multiple value
streams. A clever ERCOT storage operator will switch between
bidding into ancillary regulation markets one day to arbitraging
energy price another day for maximum revenue potential. But Order
841 compliance proposals make this type of switching
problematic.

Like many leading ISOs, New England’s ISO-NE co-optimizes
energy and ancillary markets, obviating the need for participating
resources to figure which market they should bid in for best
revenues.  Theoretically, this arrangement should help storage
economics, but instead ISO-NE rules for ancillary markets force
resources to “de-rate” (i.e., pretend they can only run at a
lower power output) whenever they are bid in the energy
market. 

This prevents a battery from squeezing out as much output as
possible during system peak because it must maintain the ability to
provide a full hour of output on the back side of that peak (when
it is less necessary) to satisfy ancillary market rules.

These type of issues illustrate how
disruptive storage can be to existing market paradigms
. As more
and more storage comes online, ISOs must evolve through new rules
and market structures to accommodate the technology’s
potential — and better implement FERC’s Order 841 — to
maximize benefits for today’s electricity consumers.

Source: FS – Transport 2
How Market Rules Are Holding Back Energy Storage



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