The nation-leading New York and California regulatory proceedings to create a marketplace opportunity for renewable and distributed generation have become almost encyclopedic in their complexity.
This assessment has been reinforced to Utility Dive by multiple sources, prompting the question: Did it have to be that way?
The New York Reforming the Energy Vision (REV) is now into its third year and second phase. According to the New York Public Service Commission (NY PSC), it spans at least 16 major proceedings, along with the investor-owned utilities’ rate cases.
There are also four related proceedings, as well as proceedings at the New York State Energy Research and Development Authority and the Federal Energy Regulatory Commission, the PSC emailed Utility Dive earlier this year.
The California Public Utility Commission’s (CPUC) work on distributed energy resources (DER) has evolved into twelve major proceedings as well as those overseen by the California Energy Commission and the California Independent System Operator.
The CPUC last year published a seven-page DER Action Plan summarizing its efforts into three categories and 15 “strategic directives” with four “objectives” through 2018. The NY PSC is working on a Roadmap for REV intended to offer the same overview.
What if New York and California started all over again? What if the regulators, policymakers, and utility and non-utility stakeholders knew then what they know now? What would be different? Could it be less complicated? What would the new rules be?
The New York vision
Pace Energy and Climate Center Executive Director Karl Rabago, a former Texas utility commissioner, has been an expert witness in the REV and other utility regulatory proceedings across the country.
New York’s REV might be credited with some of the commitments in Governor Andrew Cuomo’s (D) 2018 State of the State address, Rabago told Utility Dive in a phone interview earlier this year. Cuomo advanced proposals for energy efficiency, distributed and utility-scale solar, battery storage, transportation electrification and offshore wind.
“But we still haven’t done much for customer engagement or advanced metering,” Rabago said. “If the REV started over, the first thing I would do is manage expectations about how long things would take, because the power sector is a big and complicated industry.” The rhetoric raised expectations too high, he said. But it might have been necessary.
“Modernization of the distribution grid is a fundamental imperative that is ubiquitous and universal, whether or not a state has a progressive energy policy,” Rabago said. From the beginning, the REV offered a “compelling vision of a new market structure.”
States that undertake grid modernization without that vision face the risk of spending for system infrastructure to get nothing more than “fractional improvements” in System Average Interruption Frequency Index (SAIFI) and System Average Interruption Duration Index (SAIDI) numbers, he said. In New York, the PSC, led by former Chair Audrey Zibelman and others, risked articulating their vision. “They recognized that third party DER providers could not get into the market because a whole new structure was needed.”
They decided against trying to complete “the 90s project” of moving to a fully deregulated electricity sector, Rabago said. Deregulation was “a complete error because it takes a huge amount of regulatory oversight to transform the energy sector.”
The core REV vision is of engaged customers managing their own energy bills and, in doing so, helping to manage system costs, Rabago said. “It is customer empowerment through animation of a DER market that leads the transition to a more efficient, distributed, better managed, high renewables system.”
Dave Gahl, director of Northeastern States Affairs for the Solar Energy Industries Association (SEIA), agreed that the PSC’s “top down” approach offered that vision. But “they focused less on the step-by-step activities needed to enable that market.”
“In a process this big, there is always a risk of the perfect becoming an enemy of the good.”
Much of the complexity began when the debate between utilities and DER advocates over costs and benefits intensified. It became “over-complexified” with the attempt “to divine the perfect locational adder” for DER valuation and to create an “artificial adder” for low and moderate income customers, Rabago said. “In a process this big, there is always a risk of the perfect becoming an enemy of the good.”
Consolidated Edison spokesperson Allan Drury described another fundamental difference among stakeholders. ConEd wants “utility ownership of large-scale renewables” because it is better for customers than requiring utilities to procure such energy through power purchase agreements.
Other stakeholders argue the utility should be restricted to the role of distribution system operator. But if utilities own the generation, “customers will realize benefits over the project’s life, not just during the term of the contract with the developer,” Drury emailed Utility Dive in January.
Rabago, SEIA’s Gahl and others see this as a direct contradiction to the REV vision because it limits the role of the private sector. The objective is to “align” clean energy programs with that vision, Gahl said.
Rabago said REV can be “decomplexified” if commissioners make the process more transparent and more incremental and allow for mid-course corrections.
“Linear thinking won’t work because there is too much going on and the pieces are too interrelated,” he said. “Work on the VDER should be done with an awareness that storage is waiting in the wings and the question of compensating customers for demand response is coming after that.”
That approach would have slowed phase 1 but would have allowed stakeholders to obtain more data and use lessons learned to inform phase 2, Rabago said. “We were in a hurry to get to phase 2, because it would replace regulatory fiat with market value. But, with 40 people in the room, there are at least 35 different views of market value. And the debate lacks sufficient data to resolve the conflicts.”
Vote Solar Northeast Director Sean Garren endorsed this point. Many of the solutions being proposed “are merely political compromises rather than data-driven regulatory decisions,” he emailed Utility Dive in January.
SEIA’s Gahl was even more emphatic. The commission should ensure that enough data is available to “help the DER market understand where the opportunities exist on the distribution grid,” he said. But that will only come when advanced metering infrastructure is installed, he acknowledged. Comprehensive system data “is still years away” and the utility role as distribution system operator “is still only in its nascent stages.”
California’s bottom-up approach
Bandon Smithwood was SEIA’s director of California policy throughout the DER proceedings and recently became policy director for the Coalition for Community Solar Access.
“If you had asked me two years ago, I would have said the California proceedings lacked a coherent vision like New York’s,” he emailed Utility Dive earlier this year. “But now I think the ‘bottom-up’ approach to the grid modernization process is wise because it is avoiding some of New York’s challenges.”
California’s approach is described as “bottom-up” because it started with the basics of DER policy, like rethinking net energy metering (NEM), and allowed the vision to evolve.
The bottom-up approach “has not always been clear about where the process is going, though the DER Action Plan has helped provide a vision,” Smithwood said. But clarity is still lacking on how informational tools are to be used and it is impeding full resolution of technical issues like hosting capacity analysis and locational value.
The NY REV has revealed “the pitfalls of starting at the high-level vision and then making decisions about key underpinnings of the DER market without developing the specifics.”
Because there was no rush to achieve a new vision, California’s commission kept retail rate NEM in place to provide “regulatory certainty and continuity,” Smithwood said. And the bottom-up approach will keep it in place “at least until the Commission has developed the tools needed to evaluate alternative tariffs.”
Merrian Borgeson, energy program senior scientist with the Natural Resources Defense Council (NRDC), emailed agreement. “The right place to start” was with “foundational processes and tools for valuing DERs and integrating them into the distribution grid.”
The other good choice in that bottom-up approach was having the state’s investor-owned utilities (IOUs) participate in the groundwork, she added. By commission order, the IOUs played key roles in preparing distribution resource plans, running pilots to test DER integration theories, and developing tools to map grid hosting capacity.
Smithwood said it is not yet certain those tools will be workable. Only streamlined interconnections will prove that the hosting capacity analysis has been successfully developed. And important commission rulings are needed before the locational value that comes out of the Locational Net Benefit Analysis (LNBA) can be validated in real-world applications.
There are also still “big holes,” he added. First, the commission has not adequately considered the utility business model. Second, it has not given enough attention to “the customer perspective and how to ensure the state’s efforts to support expansion of DER adoption to more groups of customers who historically have lacked access.”
To address the utility business model, the proceedings should include a structured examination of cost-of-service regulation, he said.
The business model and NEM debate
Southern California Edison (SCE) Director of Energy Policy Gary Stern sees the coming debate about NEM as involving that question. There is a less-than-retail rate for DER generation exported to the grid that will both support growth and alleviate utility concerns about protecting non-DER-owning customers, he emailed Utility Dive earlier this year.
Stern raised questions that show the tension between utility and non-utility stakeholders over how to set the right remuneration to DER owners for the services they deliver to the system.
“What is that power worth to the utility, as we would use it in lieu of acquiring more power to the market? And what other social benefits or avoided costs occur from our taking that power?” he asked. “What costs will we incur to absorb that power into our grid? And what level of subsidy does it make sense for non-solar customers to pay to continue to encourage rooftop solar adoption?”
Brattle Group Principal and rate design authority Ahmad Faruqui, an energy economist, emailed that “DER are not an end in themselves.” Accurate cost-benefit evaluation should allow an understanding of whether they are “cost-effective from an economy-wide perspective.”
Faruqui said there should be a new rate design for residential customers that better reflects “the utility cost structure.” That means accounting for “a significant fixed component and a significant capacity cost component, in addition to an energy component.”
Well-designed rates that account for these three components “would ensure that the right amount of investment takes place in DER and in complimentary technologies, such as battery storage,” he emailed Utility Dive.
Smithwood agreed work is needed on rates. The proceedings should result in rates that are “accessible and manageable for customers” so that DER are more widely available. Instead, the proceedings have only focused on proper valuation, affordable and streamlined interconnection, and guiding the location of DER.
The result is a failure to provide wider access, he said. But a benefit of “being far along in the ‘bottom-up’ distributed resources planning process” is that the results of the LNBA proceeding may be used to create that needed access.
The three choices
NRDC’s Borgeson said California has made “significant progress” in developing “a framework for competitive solicitations for DER as non-wires-alternatives to traditional grid investments.” But it is not yet clear if the proceedings will find “rate structures, market opportunities, and other incentives” for DER so they can “provide grid benefits and help meet long term climate goals.”
Rabago has concluded these complex questions about how to integrate DER into the marketplace and give them fair valuation without imposing an unfair burden on utilities or non-DER-owning utility customers were inevitable. “Trying to hold them back was futile, because there is no way to hold back this market transformation.”
Now there are three choices for U.S. utilities, he said. The first is the Trump administration’s efforts to deny the market’s rejection of coal and nuclear, and it has been shown to be “counterproductive, anti-competitive and anti-market.”
A second choice is avoiding the deployment of smart grid technologies. It is not yet clear how this strategy will play out, but it does nothing to meet customer demand for DER.
“The third strategy is to recognize change is coming, with a price tag, and the way to respond is with a vision,” he said. “That is the REV.”