by Jeff St. John
September 28, 2018

Nevada has had a tumultuous few years when it comes to energy policy. In 2016, there was a war over the state’s decision to take away solar net metering, which eventually led to a 2017 reinstatement. This year, there are dueling ballot initiatives to either deregulate the state’s retail energy sector or pledge utility NV Energy to a massive build-out of solar and energy storage projects. 

Behind the scenes, Nevada lawmakers, regulators, utilities and environmental and consumer stakeholders have also been putting together a plan to integrate distributed energy resource (DERs) into the state’s grid planning and operations. 

This week, amidst little fanfare, the Public Utilities Commission of Nevada released its proposed decision (PDF) on this Distribution Resources Plan proceeding. In simple terms, it calls for NV Energy to delve into its medium- and low-voltage distribution grid to discover the hosting capacity, grid needs and potential DER impact and values of each circuit and feeder line across its 1.3-million-customer territory.  

If approved, this Distribution Resources Plan (DRP) would put Nevada in a small club of states — California, New York and Hawaii — that are actively asking their investor-owned utilities to bring DERs into their grid plans on a number of levels. These efforts start with the basics — getting data on how much DERs different circuits can support and forecasting their longer-term impact on supply and demand — and extend to more advanced features, such as circuit-by-circuit hosting capacity maps that can tie into to DER interconnection processes, and distribution deferral opportunities for recruiting DERs as replacements for traditional grid upgrades. 

California, New York and Hawaii are only part of the way toward implementing this vision. Nevada’s proposed DRP is just the start of its process. The first big step — a report from NV Energy on how it intends to implement the plan — is set for delivery in April 2019. It won’t be until 2022 that the new framework for valuing DERs will become part of its broader integrated resources plan. 

Still, for an effort that was only started in June 2017 with the passage of Senate Bill 146, Nevada’s DRP has emerged relatively quickly — and, for a potentially fractious effort, with a remarkable lack of friction between parties. 

The PUCN’s proposed decision itself cites the multi-month, multi-party “collaborative process” that yielded a consensus document between NV Energy and the various solar and environmental groups involved. 

While a group of DER advocates including Vote Solar, the Interstate Renewable Energy Council and Western Resource Advocates did file comments in June seeking some changes to the initial document, these suggestions were largely adopted without any challenge from the utility, Sara Baldwin Auck, IREC’s regulatory director, said in an interview. 

“The operating assumption is that what is reflected in this draft proposed decision will be adopted, given that it was a consensus-based, stakeholder-driven outcome,” she said. For a state that has “had a couple of years of policy uncertainty” for DERs, it also represents “a shift toward a future that’s necessarily going to integrate a greater number of resources into the distribution grid. This is a proactive process to integrate them, rather than the traditional method of reacting to them.” 

Nevada has also been able to learn from states that have done this before — specifically, California, which served as the model for SB 146’s version of a DRP. 

“Nevada learned from California,” Ed Smeloff, director of grid integration for Vote Solar, said in a Thursday interview. “California has gone through a lot of the deliberations on how you do hosting capacity analysis, how you do locational net benefits analysis,” and other such technical issues, and California Public Utilities Commission (CPUC) staff advised the PUC of Nevada and other parties on its own work. 

At the same time, Nevada’s proposed regulations were able to do “a bit of debugging” in terms of avoiding some of California’s early stumbles in its DRP,  Baldwin Auck said. These include specific provisions to ensure an accurate and open way to share the assumptions and data going into the DER forecasting, hosting capacity, locational benefits and grid needs analyses that will emerge from NV Energy’s execution of the plan, she said. 

The fundamentals of Nevada’s DRP plan

 The Nevada PUC’s proposed DRP lays out four key components: 

  • Load and distributed energy resource forecasting
  • Locational net benefit analysis to identify high- and low-value grid locations for DER solutions
  • A grid needs assessment to prioritize and screen projects that will address identified grid needs
  • Hosting capacity analysis to identify the available capacity for DERs at particular points on the distribution network

These categories hew closely to terms defined in California’s DRP proceeding, albeit under slightly different names. California calls its hosting capacity analysis an integration capacity analysis (ICA), for example. And while California has separated its own grid needs assessment (GNA) from the actual identification of DER distribution deferral opportunities, Nevada’s DRP would combine both of these features into its GNA. 

But “taking it out of the context of acronyms, what this really does is set forth the stepwise process by which NVE will be building up its different approaches, different methods and different models, to become much more sophisticated in its distribution planning process, and much more transparent in what’s going on in the distribution grid,” Baldwin Auck said.

Importantly, Nevada’s DRP specifically includes DER forecasting as part of its purview, she said. “It may sound like a no-brainer, but it’s not a common practice for utilities to forecast DER growth that anticipates them as being an integrated function of the planning process,” she said. “Most utility planning just looks at load.” But Nevada’s plan would specifically tie DER forecasting into “the new tools and practices they will be adopting,” she said. 

The most likely first deliverable on the DRP component list will be its hosting capacity analysis, she said. In simple terms, an HCA determines how much new DER any one circuit can accommodate. As defined by the Nevada PUC proposed decision, NV Energy’s HCA will be performed using load flow analysis and forecasted distribution capacity and configurations, using loading and voltage data from substation, feeder and primary node levels, to determine their capacity under a variety of normal and contingency operating conditions. 

IREC, Vote Solar and WRA were able to add several key conditions to the plan’s hosting capacity analysis, Baldwin Auck noted. “One of the things that’s most important, is the stuff around the hosting capacity analysis having clearly defined use cases,” specifically aimed at meeting the needs of the DER developers, customers and other stakeholders that will be using it. This hasn’t always been true for California’s ICA process, which has seen a fair share of friction between utilities and DER advocates over this subject, as we covered last week at GTM Squared.  

Nevada’s user-friendly HCA features will include color-coded maps indicating the hosting capacity available for each feeder or feeder segments, as well as downloadable and sortable data files with more granular hosting capacity information, including data broken down by technical criteria and hourly load profile. The PUC of Nevada also agreed that NV Energy must update its HCA at least twice a year to start, with a plan to accelerate that update schedule as the technology and processes are put in place to support it — “We’d like to see it published more frequently,” Baldwin Auck said. 

This work on HCA is expected to yield at least some milestones to share with stakeholders by the time NV Energy files its initial plan in April 2019, Smeloff said. “What we expect to see in this initial plan is, these are the investments need on the distribution system, feeder by feeder, substation by substation, across the state, needed to maintain reliability and accommodate the growth in DERs, including electric vehicles.”

The challenges ahead

Looking further ahead, “the grid needs assessment is really the key document that will come out of this,” said Smeloff. This document will combine data on the current “bottlenecks and constraints on the system, and what are the solutions — some of which will be traditional transformers, capacitors and wires, and some of which will be distributed energy resources.” 

This latter part of the GNA is where NV Energy will be identifying non-wires alternatives (NWAs). They’re one of the end goals of most state DRP-type proceedings — creating a holistic way for DERs to earn value for the services they provide the grid in lieu of traditional utility investment. 

“The plan will drive investment,” Smeloff said. “The question for the advocate community is how NV Energy is approaching this.” This final stage of Nevada’s DRP is likely to encounter the same challenges that NWA efforts in other states have encountered, as highlighted by GTM Research’s recent work on the topic. 

Utilities earn guaranteed rates of return on their grid infrastructure investments, leaving them little incentive to work hard to enable DERs to supplant that steady source of revenue. They’re also leery of contracting for DERs they don’t control as a replacement for traditional infrastructure upgrades, making it “possible that they may want to own some of these DERs on their own,” he said. “There may be some situations where that’s the appropriate solution. But I think you need to look at solutions that include demand response, solar, energy storage, and behind-the-meter resources.” 

At the same time, NV Energy and Nevada policymakers are aware that “more customers want solar, storage and EVs," Baldwin Auck said. “There’s a lot of customer-driven activity that’s fundamentally changing the distribution grid. To continue to ignore that, whether you’re a utility or a commission, or any other stakeholder, would not only be a lost opportunity, but will lead to a lot of costs incurred from inefficiencies or redundancies on the grid.”