By Chris King
Listen in on any gathering of energy industry executives or regulators these days, and new utility business models are the hot topic, usually centered on distributed energy resources (DERs), such as storage, demand response, energy efficiency and microgrids. Deployment of these distributed technologies is being pushed as a potential means to defer or displace more traditional investments in distribution infrastructure – and provide savings for customers. However, as regulatory proceedings in California and New York have recognized, traditional utility business models and ratemaking provide limited financial incentives for utilities to partner with third-party technology developers to pilot and test these technologies.
The limitations of the current situation were well summarized by the New York Public Service Commission in its May order adopting a new framework for utility ratemaking and revenue models. The order noted that:
— “Cost-of-service ratemaking contains implicit disincentives to innovate.”
— It also promotes “a bias toward capital spending."
— Utilities have financial and institutional incentives to favor their own spending and their own facility investments, “versus an inclination to favor the use of third-party resources where they offer economic, reliability and environmental benefits.”
The result, according to California Public Utilities Commissioner Mike Florio, is that few examples exist of DERs being successfully and cost-effectively deployed to defer distribution system upgrades.
Florio set out to untangle this conundrum with his much-discussed April proposal for pilot programs that would provide shareholder incentives to California’s three investor-owned utilities (IOUs) for such DER deployments. As he intended, the proposal sparked a range of public comments, including support and alternative proposals for stakeholder incentives from the IOUs – Pacific Gas and Electric, San Diego Gas & Electric and Southern California Edison.
Florio issued a revised version of his proposal on Sept. 1, which, along with the utilities’ alternatives outlined in a Sept. 15 filing (not yet publicly available on the CPUC website), could provide models for other states and utilities – and promote the kind of utility-developer partnerships that can provide benefits for all stakeholders. The incentive models offer tangible solutions to regulatory disincentives that utilities now face when considering more rapid DER adoption. In contrast to policy directives, which can be complex and subject to ongoing debate, financial incentives provide a clear alignment of utility shareholder interests and DER provider goals.
Shared savings vs. shareholder incentives
Utility disincentives to deployment of DERs go beyond those cited by the New York Public Service Commission. Florio’s proposal added to the list:
— A dearth of information regarding the practical effects of DER deployment on utility systems
— A lack of clarity about the changes needed in utilities’ distribution planning processes to accommodate or counterbalance such effects
— Uncertainty about the commercial capability of markets to provide reliable, cost-effective DERs
— The difficulty for utility forecasting to differentiate between utility-provided and market-provided DERs
These challenges are well known, as is the incentive concept. What’s new is California’s specific approach. First, the California Public Utility Commission (CPUC) rejects the traditional concept of shared savings structures, where savings generated by a project are split between customers and regulated utility shareholders. The difficulty of such structures, Florio’s April proposal says, “arises when the amount of the savings is uncertain and open to dispute” – as has occurred in shareholder incentives for energy efficiency. Going with a shareholder incentive only is intended to avoid potential litigation.
SEPA's Beyond the Meter report explores the potential for a new customer-grid dynamic here.
Rather, the CPUC’s proposal is “a shareholder incentive for the deployment of cost-effective DERs that displace or defer a utility expenditure, based on a fixed percentage calculation.”
To ensure savings for customers, the utility receiving a shareholder incentive would have to show that using third-party DERs to meet a distribution grid requirement is cost-effective. Specifically, the amount paid to a DER provider, plus the amount of the shareholder incentive, would have to cost less than traditional grid reinforcement with larger transformers, new substations or other such investment.
Then, according to the proposal, the utility shareholders would receive a fixed percentage applied to the total amount paid by the utility to the DER provider. The proposed shareholder incentive would be based on a fixed percentage of the total amount paid to the DER provider each year. The proposed percentage, 4 percent, is based on shareholder expectations for returns on utility capital investments and would be applied annually to the amount paid to the DER provider in any one year.
What’s not to like? The proposal offers potential benefits for utilities, DER providers (which could see incentives triggering more rapid distributed technology deployments), and customers. Indeed, many of the parties involved in the CPUC proceeding -- including utilities -- are generally in favor of the proposal.
An argument for different incentive models
But, the utilities’ Sept. 15 filing and its suggestions for additional approaches to consider come at the challenges of DER deployment from a different perspective. It is not a lack of shareholder incentives that have limited deployment of DERs, the three utilities say, but “a lack of foundational frameworks,” such as
— How to plan a distribution system that relies on DERs
— How to define what DER services utilities can rely on in their distribution operations
— A cost comparison method for comparing the cost of traditional infrastructure with the net cost of market-provided DER
— A contracting process for utilities to acquire DERs
The good news, they add, is that these frameworks are under development in California in its Distribution Resource Planning proceeding.
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At the same time, SCE argues for a more expansive approach to any incentive pilots, saying more than one approach should be tested. It proposes two other incentive plans.
In the first, an upfront payment option, the utility would make a lump-sum payment to the developer after the DER project is completed. The payment would equal the total cost of development, minus, first, savings realized by customers who benefit from the DERs through lower monthly bills and, second, revenues earned by bidding the DERs into wholesale markets, for example, for energy or capacity.
For the developer, the payment would be additional revenue. For the utility, the payment would be added to its capital rate base and depreciated the same as traditional wires investments. Shareholders would be compensated at their normal rate of return for the portion of the payment funded with stockholder equity.
In the second option -- a contract for distribution services -- the utility would contract with a DER provider for only the grid services it needs (perhaps distribution capacity), but not for any of the associated energy or generation capacity benefits. The contract payments would be similar to the proposed upfront payment, in that the DER service provider’s customer and wholesale market revenues would be factored in. However, unlike upfront payments, the contract payments would be made annually and not put into the rate base.
The utility would also receive a fixed percentage payment – as in the CPUC shareholder incentive proposal. But, because the contract is for only a portion of services, SCE says, the fixed percentage would need to be “perhaps two to three times the magnitude proposed” by the CPUC.
We have known for a while that a world in which DERs are widespread will raise new challenges and complexities. These three incentive concepts offer concrete suggestions for solving the key utility business model question of shareholder incentives when DERs displace traditional grid investments, while also ensuring customer benefits.
Tellingly, the CPUC states, “At minimum, our willingness to address [the incentive] issue upfront should signal the investment community that our efforts to transform the California electric system will not be undertaken without regard for the continued financial health of the IOUs, even if the regulatory and ratemaking framework that ultimately evolves in California turns out to be quite different from the one currently in place. Throughout the important and dramatic changes currently sweeping this industry, our focus must remain on assuring safe, reliable and environmentally-sensitive electric service at just and reasonable rates, while maintaining financially healthy infrastructure providers.”
The CPUC’s final ruling is expected toward the end of 2016 and, hopefully, incentive pilots will be implemented in 2017. These different approaches to shareholder incentives are good news for DER providers. They go beyond general discussion of utility business model changes and are concrete steps in implementing and testing new business model elements.
Chris King is Global Chief Regulatory Officer for Siemens Digital Grid and a member of the Smart Electric Power Alliance (SEPA) Board of Directors. He can be reached at email@example.com.