Last year, the California Public Utilities Commission launched
an effort to grapple with how the rise of distributed energy
resources, third-party energy services business models, and community-choice
aggregators were fundamentally altering the state’s energy landscape — for
good, or potentially, for ill.
As a regulator with the mission to keep energy affordable,
reliable and decarbonized, the CPUC’s main concern was how these trends are
taking market share and power away from the state’s investor-owned utilities,
which it regulates, and putting it into the hands of third parties over which
it may or may not have control.
On Thursday, the CPUC’s Policy and Planning Division
released a new white paper on this “California Customer Choice Project,”
condensing the past year’s learnings into a set of history lessons, along with
a list of potential pitfalls — and a few possible solutions — for a state
that’s rapidly approaching a turning point on this path.
Distributed net-metered solar, community-choice aggregators
(CCAs) and “Direct Access” customers are expected to account for as much as 25
percent of retail electric load as of this year, according to CPUC data. That
share could grow to as much as 85 percent by the mid-2020s, based on
projections of the rapid growth of behind-the-meter DERs, as well as the
rapidly expanding roster of cities and counties seeking CCA status.
“Californians have signaled in a variety of ways that they
like choice over how they get their electricity,” CPUC Commission President
Michael Picker, who launched
the customer choice project last year, said in an interview this week. “But
what are the best ways to give them that choice and still achieve all our
goals? That’s a very hard thing to answer.”
As with a similar white paper that launched the customer
choice project last
May, this week’s report has far more questions than answers. In a written
introduction, Picker laid out some of the key high-level questions, including:
“How do we protect safe delivery of electricity to meet
customer demand in an increasingly fragmented market?”
“How will we ensure that increasing fragmentation of
suppliers and buyers will add up to meet our ambitious clean energy goals?”
“How will we make sure that different players are meeting
their responsibilities to provide all the energy resources we need to make the
grid work?”
But amidst its questions, this week’s white paper does
contain a few strong policy suggestions, some that would require new
legislation, and others that are part of proceedings already underway at the
CPUC, the California Energy Commission and state grid operator CAISO.
Key ideas include an integrated procurement process for the
state, exploring regionalization of energy markets beyond the state’s borders,
and defining what happens if a third-party energy provider gets big and then
fails. “I would expect to see proposals later this summer to take care of some
of these issues,” Picker said.
The CPUC will be holding a workshop in the coming months to
discuss the new white paper’s findings. Picker said he expects it to be a forum
for DER providers, CCA advocates and proponents of increased direct access to
energy markets to explain how they’re intending to help solve the problems it
identifies.
Avoiding a repeat of the 2001 energy crisis
Some of the goals can be summed up fairly succinctly. “We
don't want to have the lights go out, and we don’t want to have massive price
increases,” Picker said — a nod to the state’s own disastrous history with
energy deregulation in the 1990s.
Much of the white paper is dedicated to a history of this
flawed deregulation plan, the resulting energy crisis of 2000-2001, and the
responsive creation of the regulatory structures that still guide the state
today. Those include resource adequacy requirements, the loading order and
preferred resources, the state’s renewable portfolio standard, utility
power-purchase agreements with independent power producers, frozen residential
rates, caps on direct access, and the rest.
The report also delves into four other markets that have
deregulated to one degree or another — New York, Illinois, Texas and the United
Kingdom — with an eye toward which aspects of their implementations are
helpful, cautionary, or inapplicable to California’s unique set of
circumstances.
California’s investor-owned utilities Pacific Gas &
Electric, Southern California Edison and San Diego Gas & Electric still
serve about 84 percent of the state’s load, compared to 16 percent by public or
municipal utilities and 12 percent by CCAs.
But the ranks
of CCAs have grown dramatically in the past few years to include eight
operational entities, with more than a dozen more being formed or expanded at
present. For PG&E, the share of load served by CCAs territory has jumped to
nearly 20 percent, starting with Marin Clean Energy and Sonoma Clean Power, and
expanding to new CCAs being proposed in Silicon Valley and the East Bay. While
Southern California Edison still hasn’t seen much of an impact, the planned
formation of the Los Angeles County Community Choice Energy could change that
dramatically.
On the larger commercial and industrial side, California’s
Direct Access program was heavily restricted after the 2001 energy crisis, and
now stands at about 13 percent of statewide energy load. These larger customers
are served by electric service providers, or ESPs — some of which also
implement CCAs for the communities that have created them.
One of the biggest problems with this shift is that the
investor-owned utilities still remain the provider of last resort in case a CCA
or an ESP fails. “One of the lessons of the last electricity crisis is that
SDG&E had to absorb a lot of customers really quickly from the failure of
electric service providers in 2001, and that meant they had to be buying a lot
of electricity in the spot market for customers they didn’t know they were
going to have,” Picker said. “Those kinds of things worry me.”
There’s also the problem with fragmenting reliability
requirements among many smaller providers, he said. This has already come up in
the area of resource
adequacy, or the reserves required to be obtained by all load-serving
entities in the state.
“We saw some people who were unable to get all their
resource adequacy requirements they needed last summer, particularly in some of
the locally constrained areas where it’s not easy to get that capacity,” he
said. While the CPUC doesn’t identify which parties failed to secure their RA
requirements, 11 waivers were applied for last year, most of them ESPs with
little certainty as to how many customers they would have the following year,
or whether they’d be in areas facing capacity constraints.
CCAs and ESPs also have much smaller balance sheets and much
higher costs of capital than utilities, which makes it much harder for them to
sign long-term power contracts, Picker said. “There are more and more
challenges emerging as people may not be able to finance long-term contracts,
because they’re engaging in short-term markets. […] Most ESPs and Direct Access
customers, they may have one-year contracts for big customers that need the
contracts this year, but don’t know if they’re going to be there next year.”
That’s a lot different from utilities, which continue to
serve customers in the same territories year after year. But “even the
utilities don’t know who their customers are going to be next year, because of
the CCA formation,” Picker said. “They don’t want to do long-term
contracts.”
Key principles and possible solutions
One of the potential fixes to the shared resource adequacy
challenge is a statewide procurement process, Picker noted. Illinois created
such a procurement structure for the municipal energy aggregators — its version
of CCAs — that now serve about 1.8 million of the state’s 5 million residential
customers, for example.
Picker also noted California’s controversial idea to expand
its grid markets to the broader Western U.S. region as a possible
solution. “That could make things work a bit more cheaply, and more reliably,”
he said. But there are stark differences of opinion among energy and
environmental groups as to whether it would open the state to dirtier energy
from the coal-heavy Rocky Mountain region and undermine its carbon reduction
goals.
There are also more fundamental issues that need to be
addressed, Picker said. For example, California has decoupled its utility
revenues and rate structures from the direct sale of electricity. But it hasn’t
yet decoupled the utilities’ financial health from the number of customers it
serves, he said.
“We don’t make them indifferent to the fact that other
people are taking away their market share,” he said. “That’s easy to fix if the
legislature is willing to” — perhaps, he suggested, by lifting the current
$10-per-month cap on fixed charges to cover fixed distribution system costs,
or instituting
demand charges for different elements that are driven by
congestion.
California’s investor-owned utilities have also been
influential in executing clean energy goals, from the RPS and loading order, to
their energy storage and EV infrastructure investment plans.
“There is a question whether the necessary capital
investment needed to decarbonize the electric sector to meet the state’s 2030
goals and beyond can be financed and, if so, delivered on time if the state
transitions away from a few larger buyers to many small buyers,” the report
noted.
Beyond the sheer scale of the investment needed, there’s the
matter of whether the CPUC has power to impose those same priorities on CCAs,
ESPs or Direct Accrss customers, Picker noted. Right now, the CPUC doesn’t even
have the authority to adjudicate customer complaints or billing disputes
between load-serving entities and their customers, as it does over the
utilities and their customers, the paper noted.
“In theory at least, CCAs should harness the sense of
community and local elected officials to do more than just resell electricity,”
Picker said. “They should be doing things to help people commit to
electrification of transportation, to decarbonize and electrify
buildings.”
Of course, CCAs and their backers have long said that one of
their main motivations has been to push beyond the utilities' clean energy
goals and purchase renewables more directly. The paper notes that “CCAs have
argued that having local control will yield lower rates, a greener grid, better
service, more technological innovation, greater distributed resources such as
behind-the-meter and more rapid response to customers’ needs. Metrics need to
be established to ensure that the statewide goals are met as well.”
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