The fledgling British commercial and industrial energy storage industry faces a mortal challenge from a proposed market rule change.
The U.K. energy regulator, Ofgem, published a proposed rule last week that would eliminate the current demand charge mechanism for commercial and industrial customers and replace it with a fixed charge, with a preferred implementation date of April 2021.
A fledgling storage industry had pitched onsite batteries as a means of reducing businesses' demand charges; without time-based charges, that particular need for batteries vanishes, leaving little incentive to acquire them.
The development spotlights the risks associated with hanging a business on a single, mutable market rule.
The storage industry has been burned by rule changes already, as in the frequency regulation market in PJM territory and the capacity market in the U.K. Customer demand management comes with its own particular risks.
“If the regulator or government doesn't think you are paying your fair dues, they can simply change the rules of the game,” said Rory McCarthy, a senior analyst covering European energy storage markets for Wood Mackenzie. “We see this happen time and time again, so we should probably stop getting so surprised.”
Worse than expected
The mechanism under fire is known as Triad, because the demand charge applies to three half-hour periods of wintertime peak system demand. Companies could export power during those periods to reduce their charge.
The preliminary “minded to” decision still needs to go through procedural steps, like stakeholder engagement, but appears likely to take effect after that.
The threat to Triad didn’t appear out of nowhere: Ofgem decided in 2017 to cut this benefit from front-of-the-meter assets, and indicated that it would evaluate doing so for behind-the-meter resources.
“As such, it has already hindered the industry from really taking off, alongside issues from frequency market saturation, capacity market de-ratings and suboptimal clearing prices,” McCarthy said.
Industry had hoped that some form of incentive to reduce load would be included in whatever replaced Triad, he added.
“However, this 'minded to' decision doesn't seem to bear such fruit, and we will likely have to adjust our outlook downwards for the C&I storage segment here to account for this,” McCarthy noted.
Without the demand charge use case, C&I storage developers will have to find other reasons for their product to exist. The next best bet is offering backup power to customers who have a strong need for energy resilience, like data centers, McCarthy said. But that won’t be easy.
“These consumers typically already have uninterruptible power supplies and backup generators, so their investments have already been made in these other incumbent technologies,” he said.
Demand managers beware
This turn of events reveals the fragility of the C&I storage industry’s favorite strategy, demand-charge management.
That’s the core value proposition of the C&I market in the U.S., too — almost all of which currently transpires in California, with robust policy support. But demand charges do not exist in perpetuity.
Utilities and regulators set rates to collect payment for the cost of electric delivery. They have to make choices about how to assess costs from different kinds of users, weighing factors like volumetric energy consumption and instantaneous demand for capacity. Rates may include some combination of fixed fees, volumetric charges and charges pegged to moments of peak system demand or customer demand.
If a customer has to pay a flat fee for consumption during a specific time window, battery storage may be able to significantly reduce the charge by predicting the hour and delivering power at that time (actual results may vary). That’s good news for the customer, and the storage developer, but not so good for the people who levied that tariff to efficiently distribute the costs of the electric grid.
Put another way, if everyone figured out how to avoid paying certain fees, regulators would have to figure out a new way of socializing the cost of the grid; that money still has to come from somewhere.
That’s what happened in the U.K. Ofgem became concerned that some customers were getting out of paying residual charges, which cover sunk network costs, McCarthy wrote in an analysis of the proposed change.
“The current Triad mechanism enables users to avoid residual costs (e.g., with storage), and Ofgem does not think this is fair for other users who can’t shift their load," he explained.
That attitude has yet to arrive in California's regulatory community, which has rallied behind energy storage as a tool to achieve decarbonization goals. Indeed, several C&I storage companies use their capacity to fulfill contracts with the same utilities that lose out on demand charges that get reduced by batteries.
In theory, there's a win-win scenario, where the bill reductions for customers produce a commensurate reduction in the system costs to meet peak demand. Getting this right requires savvy ratemaking that takes full advantage of the latest developments in distributed energy technology. New tech and old rules don't jibe as well.
Extrapolating from one regulatory environment to another is a tricky thing. At the very least, C&I developers elsewhere may read the U.K.'s likely decision as an omen of a possible future: If they do too good a job eliminating payments to their customers' utilities, that very success could bring the business case crashing down.
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