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April 21, 2019

NYPSC Refines Value Stack, Boosts Community DG

By Michael Kuser

The New York Public Service Commission on Thursday modified its value of distributed energy resources (VDER) compensation policy and authorized $43 million in state funding for solar and other community distributed generation projects in the Hudson River Valley and New York City (15-E-0751).

The commission’s order refines the compensation rules it set in 2017. “The decisions in this order improve the predictability, transparency and accuracy of DRV [demand reduction value], locational system relief value (LSRV), and capacity value calculation and compensation,” the commission said.

The New York PSC held its regular monthly session in Albany on April 18.

The order directs utilities to file tariff revisions within 20 days, to be effective June 1.

It also noted inconsistencies in utilities’ marginal cost of service studies and initiated a proceeding to “determine what methodologies will lead to the most accurate results” (19-E-0283).

The new rules incorporate, with modifications, most of the recommendations commission staff made in two white papers in December. (See NY Examines VDER Capacity Value Compensation.)

In a white paper on compensation, staff said that the current DRV and LSRV rules “may represent an attempt to achieve greater granularity and precision than is reasonable and possible in an open, administratively determined tariff mechanism.”

The paper said the commission must balance the desire to provide precision in compensation with “the risk that a more sophisticated tariff may result in price signals that do not fully incentivize and motivate developers and customers to make decisions based on the objective of maximizing grid value.”

Commissioner Gregg Sayre said that in restructuring the market for distributed energy, “paradoxically, we have to set market rules and even in some cases have to set prices in order to move toward our goals.”

Thursday’s order adjusts the calculation of DRV to reflect performance during a larger set of hours and to lock in the value for 10 years. It also changed the LSRV — the value of using DERs to avoid distribution system investments — giving such projects compensation for responding to utility calls. PSC staff had called for phasing out the program.

The rules expand Phase One net energy metering eligibility for self-serving projects under 750 kW; modify the Alternative 1 Capacity Value calculation to reflect NYISO monthly prices and solar PV load curves; and modify the Alternative 2 Capacity Value calculation to better reflect actual peak hours.

Commissioner Diane Burman voted against the VDER measure, saying the late delivery of the draft order — 9 p.m. on April 15 — did not give her enough time to be fully briefed on the matter.

“You can point to the staff white papers and say we just made modifications to that,” Burman said. “It’s not good enough, especially because it requires going through not just the white papers and looking at the potential modifications, but … looking at all of the different things that this hits.”

PSC Chairman John Rhodes acknowledged that he had previously heard Burman ask staff to try to get draft orders to the commission well ahead of a scheduled session. Commissioner James Alesi joined Sayre and Rhodes in approving the order.

Storm Response Faulted

The commission concluded investigations into utilities’ responses to storms in 2017 and 2018, including two nor’easters that struck the state last March that left hundreds of thousands of customers without power. The commission also established the Office of Resilience and Emergency Preparedness to improve the state’s ability to respond to the impact of severe weather events.

The PSC accepted a joint settlement agreement on New York State Electric and Gas’ and Rochester Gas & Electric’s responses to the March 8, 2017, windstorms, which cut power to 250,000 customers (17-E-0594).

While National Grid had restored service to 90% of its customers within 36 hours, and all of them by March 12, it took NYSEG until March 13 and RG&E until March 17 to complete work.

“It was disappointing at the time that NYSEG and RG&E took longer to restore service than National Grid, given relatively comparable service territories and damages,” Sayre said.

The settlement requires RG&E to spend $2.8 million and NYSEG $1.1 million on resilience programs and improvements to their emergency response practices. Administrative Law Judge Sean Mullany and Christian Bonvin, Department of Public Service chief of electric distribution systems, testified that the costs would not be reflected in the companies’ rate bases or operating expenses.

Sean Mullany (left) and Christian Bonvin

The PSC also issued a re p ort on its investigation into the 2018 winter and spring storms, finding that NYSEG and Consolidated Edison “not only struggled with providing accurate [expected time of restoration] but also did not make optimal use of social media or their websites to keep customers and public officials well informed.”

The commission’s show cause order directed the utilities to provide a status report by April 26 detailing their implementation of the recommendations and to file revised emergency response plans (ERPs) by May 15 (19-E-0105, et al.).

Court Action Sought on NYSEG

The PSC also issued an order instructing its counsel to begin a special proceeding against NYSEG in the New York Supreme Court “to stop and prevent future violations” of commission regulations and orders by the utility (19-E-0288).

The order cited the DPS’ 77 recommendations for NYSEG in its report to implement in its ERP and its conclusion that the company may have violated its ERP on 20 occasions in the 2018 storms. It said the 2018 storms were just the latest in “a pervasive pattern of inadequate response and restoration performance,” dating to Superstorm Sandy in 2012.

Burman dissented, questioning the logic of going to court.

“Why would we today, if we have an issue with their pervasive lack of response, why would we say in the settlement and in here that we’re good with things?” Burman said. “Plus, we’re not factoring in other storms that have happened since then that, my understanding is, NYSEG got credit for doing well.”

Burman said she found seeking injunctive relief against NYSEG as dismissive of the commission’s authority, as if she was to tell her two children, “Wait until Daddy gets home; he’ll tell you to listen to Mommy.”

John Sipos, acting general counsel for the PSC, said he would characterize it a different way.

“This order … would authorize counsel to seek an affirmative judicial order requiring compliance,” Sipos said. “It is a tool that the commissioners have as part of their enforcement and compliance toolbox. I would respectfully suggest that it is a significant tool, and I would also add that … other state agencies also sometimes seek civil action in New York Supreme Court.”

April 21, 2019

Sunrun Ruling Cuts Red Tape for PV Aggregators

By Robert Mullin

Rooftop solar aggregators scored a victory against paperwork Thursday when FERC issued a declaratory order exempting residential aggregations from certain filing requirements needed to obtain qualifying facility status under federal rules (EL18-205).

Residential solar company Sunrun last year petitioned the commission for two waivers related to QF certification under the Federal Power Act and the Public Utilities Holding Company Act.

The company — which has about 1,360 MW of PV capacity in 22 states and D.C. — does not currently make FERC-jurisdictional sales, but its petition signals it’s headed in that direction.

Sunrun scored a victory against paperwork when FERC issued a declaratory order exempting residential aggregations from certain filing requirements needed to obtain qualifying facility status under federal rules. | *FLS Solar*

In its initial filing, Sunrun explained that it intends to pursue “emerging” opportunities for aggregated distributed energy resources in organized electricity markets. It noted it has received “increasing inquiries from lenders and investors regarding QF status and the regulatory exemptions it affords.”

But the company first needed to untangle some of the red tape that comes with operating QFs.

Under FERC regulations, a facility seeking QF certification must either file an application with the commission or submit a Form 556 for self-certification. QFs are also subject to the commission’s “1-mile” rule, which holds that any small power production facility located within 1 mile of another small facility using the “same energy resource” and having the same owner will be considered one facility when calculating whether a facility exceeds the 80-MW cap on QF eligibility.

To relieve the regulatory burdens of the smallest operations, FERC’s 2010 Order 732 exempted facilities with net production capacities of 1 MW or less from both the filing and self-certification requirements. In its 2016 SunE B9 Holdings LLC decision, the commission adopted the use of the 1-mile rule for establishing whether a facility meets the 1-MW threshold.

Sunrun noted that most of its homeowner clients elect to have the company retain ownership of their PV systems, which, collectively, would be deemed owned by the same entity for the purposes of FERC’s 1-mile rule. And while 99.5% of the company-owned systems have a nameplate capacity below 20 kW, the concentration of Sunrun’s growth is such that it will not be able to rely on the 1-MW filing exemption in the future in certain regions.

“When the commission established the current rules for QF certification, it expressed a clear intention to keep residential PV systems free from the obligation of filing QF certifications,” Sunrun said. “As a consequence, the QF certification requirements were not designed with residential-scale systems in mind.”

Sunrun asked FERC to waive the 1 MW, 1-mile QF certification filing requirement for rooftop PV systems, contending its request was narrowly tailored to apply only to small (20 kW or less), separately interconnected, individual residential systems that homeowners have the option to purchase.

In granting Sunrun’s request, FERC agreed the waiver “is not designed in a manner to circumvent the commission’s regulations. Rather, the geographic concentration of residential PV systems financed by Sunrun, and the fact that individual homeowners make these location and financing decisions based solely on individual homeowners’ personal preferences, create the need for the requested waiver.”

The commission also said the facts in its SunE B9 decision, which involved a large non-residential PV system with 18 500-kW inverters, were “distinguishable” from those in the Sunrun decision.

“Given the significantly larger number of individual residential PV system sites at issue here, however, and also the nature and size of these systems (i.e., residential systems with net capacities of 20 kW or less), as well as the fact that new residential customers may be added at any time and existing homeowners have the right to purchase the facilities subsequently, the administrative burden that Sunrun faces in order to remain in compliance with the commission’s regulations would be significantly greater in comparison to the burden faced” in SunE B9, FERC said.

The commission also granted Sunrun’s second requested waiver, so that when the company must submit a self-certification for systems greater than 20 kW, it is exempted from the requirement of including information related to systems 20 kW or less within 1 mile.

“The same reasoning that justifies the commission granting the first waiver request also supports granting the second waiver request,” the commission said. “In particular, given the already substantial and growing number of PV systems of 20 kW or less in Sunrun’s portfolio, coupled with the fact that new client homeowners are added frequently and existing client homeowners may at any time exercise their option to purchase their 20-or-less kW PV systems, the need to continuously update the Form No. 556 for these changes would place a significant burden on Sunrun and the commission without any obvious benefit.”

April 21, 2019

FERC Proposes Revisions to NERC CIP Standard

By Rich Heidorn Jr.

FERC on Thursday proposed changes to NERC’s draft critical infrastructure protection (CIP) standard addressing the cybersecurity of real-time communications between control centers.

The Notice of Proposed Rulemaking, which builds on a proposal by NERC, seeks comment on requiring the electric reliability organization to add protections on the availability of communication links and data communicated between control centers. It also sought comment on requiring NERC to clarify the types of data that must be protected (RM18-2 0).

NERC proposed standard CIP-012-1 in response to FERC Order 822 (RM 1 5-14), issued in 2016. In addition to approving seven modified CIP standards, FERC’s order directed NERC to require responsible entities to implement controls to protect communications links and sensitive data communicated between control centers. (See FERC Postpones Action on Supply Chain Protections.)

The order acknowledged that not all communication network components and data require the same level of protection because they pose different risks to bulk electric system reliability. As a result, NERC said its standards drafting team focused on the types of real-time data a control center will communicate and whether their compromise would pose a high risk to grid reliability.

NERC proposed exempting operational planning analysis data used in next-day operations, saying if there is a risk such data have been compromised, the responsible entity can verify the data prior to any impact on real-time operations. Although “an operational planning analysis factors into how an entity operates, there is less of a risk that an entity would act on compromised data from an operational planning analysis given it will base its operating actions on real-time inputs,” NERC said.

Also exempt are oral communications, which are covered by standard COM-001-3.

‘Largely Responsive’

NERC’s proposed standard would apply to balancing authorities, generator operators, reliability coordinators, transmission operators and transmission owners that operate control centers. It would require them to identify security protections, where they are applied and the responsibilities of each entity for control centers owned or operated by different entities.

FERC’s NOPR called NERC’s proposal “largely responsive” to Order 822, saying it supports situational awareness and reliability by requiring rules to prevent the unauthorized disclosure or modification of real-time assessment and monitoring data transmitted between control centers.

But the commission said NERC’s proposal may not address all cybersecurity risks, saying it does not require protections regarding the availability of communication links and data. The commission said it disagreed with NERC’s contention that the issue of data availability is adequately covered by standards IRO-002-5 and TOP-001-4.

The commission said those two standards only require redundant and diversely routed data exchange infrastructure within control centers, not between them.

It also said the standard must be revised to add a definition of “real-time monitoring,” which is not spelled out in the standard or the NERC Glossary.

FERC said NERC has “broadly defined” real-time assessments, which RCs and transmission operators must perform every 30 minutes to identify any actual or potential exceedances of system operating limits or interconnection reliability operating limits.

But it said “real-time monitoring is not defined at all.”

“We are concerned that without further clarity, reliability standard CIP-012-1 may be implemented and enforced in an inconsistent manner,” the commission said.

Comments on the NOPR are due 60 days from publication in the Federal Register.

April 21, 2019January 25, 2024

FERC Tells SPP to End Exit Fee for Non-TOs

By Tom Kleckner

FERC on Thursday directed SPP to eliminate its exit fee for members who are not transmission owners or load-serving entities, granting a complaint by the American Wind Energy Association and the Wind Coalition (EL19-11).

The commission found the RTO’s exit fee to be unjust and unreasonable “because it creates a barrier to SPP membership for non-transmission owners and because it appears to be excessive.”

“SPP’s exit fee for non-transmission owners … is not needed to maintain SPP’s financial solvency or avoid cost shifts, and is excessive as a means of ensuring stability in membership and members’ financial commitment,” the commission said.

AWEA applauded FERC’s decision, saying the exit fee prevented environmental groups, consumer advocates, independent power producers, power marketers and other market participants from “contributing to [SPP’s] decision-making process.”

“We look forward to working with SPP to develop a more inclusive stakeholder process that will lead to better outcomes for ratepayers,” Amy Farrell, AWEA’s senior vice president of government and public affairs, said in a statement.

SPP said it was unable to respond to the order until it reviews it to “fully determine its implications.”

AWEA and the Wind Coalition, now known as the Advanced Power Alliance (APA), filed the complaint in November, charging that the exit fee results in unjust and unreasonable rates “because there is no causal relationship between a non-TO/LSE’s termination of membership and the majority of the exit fee” and because the exit fee is “a practice that directly affects jurisdictional rates … by creating a barrier to membership for non-TOs/LSEs,” resulting in their under-representation as voting members in SPP.

The complainants argued than an administrative fee would be a more “appropriate mechanism” for SPP to recover its ongoing obligations, as do other RTOs and ISOs. They contended SPP does not attempt to correlate the exit fee’s assessment with the amount of costs caused by a withdrawing non-TO/LSE member, saying a public interest entity with no market activity would pay the same exit fee as an entity with thousands of megawatts of generation in the RTO.

FERC agreed, noting the only instance of an exit fee’s assessment came in 2015 when Trans-Elect Development Co. was charged $822,008 upon the involuntary termination of its membership for nonpayment of obligations. The commission said SPP calculates that the exit fee for an entity without load would be approximately $621,851, as of October 2018, and found that at even that level, the exit fee “could place a significant burden on smaller entities or new market entrants that are not transmission owners.”

The commission pointed to comments from DC Energy, EDF Renewables, E.ON Climate & Renewables, Invenergy Energy Management, TradeWind Energy, Texas Industrial Energy Consumers, Interwest Energy Alliance and public interest organizations that indicated they had not become members “because of the potential burden associated with paying the exit fee.”

SPP requires its members to pay a $6,000 annual membership fee. The exit fee is defined as the sum of the withdrawing member’s existing obligations (including any unpaid dues or assessments and any costs directly incurred by SPP because of the membership termination) and the member’s share of SPP’s outstanding long-term financial obligations (loans, leases and pensions) and general and administrative overhead for a three-month period.

FERC said SPP has grown “significantly” since 2006, when it last ruled on its exit fees. At the time, long-term financial obligations amounted to about $25 million, the commission said. But as the RTO has grown by building out its transmission footprint and administering an energy imbalance market and its Integrated Marketplace, it said, so have SPP’s long-term obligations.

SPP’s long-term debt peaked at more than $258 million in 2012, when it was developing the Integrated Marketplace. The markets went live in 2014, and SPP’s long-term debt has subsequently dropped to more than $215 million.

Membership benefits include the ability to: vote on SPP initiatives; elect members to the Board of Directors; propose changes to the Tariff, business practice manuals and governing documents; serve on committees, task forces and working groups; participate in closed or executive session discussions; request dispute resolution; and appeal decisions to the board.

Nonmembers or their representatives can attend open meetings and submit comments on proposals. They can also participate in the Integrated Marketplace and take transmission service under the Tariff.

Steve Gaw, a former Missouri legislator and regulator, has long represented the APA at SPP stakeholder meetings. As a regulator, Gaw also served on SPP’s first Regional State Committee.

SPP Granted Delay for Tariff Revisions

In a second order Thursday, the commission granted SPP’s request to defer revisions to its Tariff because of an implementation delay in a new settlement management system (ER17-1568).

SPP said several Tariff revisions were dependent on changes built into the settlement system, but that the system had “encountered developmental delays.”

The new settlement system was originally projected to go live May 1. However, that date has now been pushed back to Feb. 1, 2020.

April 21, 2019February 19, 2025

FERC Open Meeting Briefs: April 18, 2019

FERC Chairman Neil Chatterjee on Thursday named veteran commission attorney Maria Farinella as chief of staff to replace Anthony Pugliese.

FERC attorney Maria Farinella receives applause after being announced as the commission’s chief of staff. | FERC

“Maria’s longstanding career as an energy attorney, both at FERC for the past decade and in private practice, makes her uniquely qualified to fulfill this key role,” Chatterjee said in a press release.

Farinella worked as a senior attorney in the Office of the General Counsel’s Energy Markets Division from 2009 to 2011, and as a senior legal adviser in the general counsel’s front office from 2011 to 2019. She was a legal adviser to Chairman Joseph T. Kelliher from 2007 to 2009. She is a graduate of Smith College and American University’s Washington College of Law.

Pugliese, who abruptly left the commission March 15, had served as chief of staff since August 2017, before the arrival of Kevin McIntyre as chair in December of that year. He stirred controversy last July for remarks he made at a conference of the American Nuclear Society and on the “Breitbart Radio Show,” in which he praised President Trump and criticized Democratic governors for blocking gas pipelines.

Chatterjee last month denied any conflict with Pugliese but declined to say why he had left. (See Chatterjee Tight-lipped on Pugliese Departure.)

Chatterjee: No Comment on NEPOOL Rules

At his regular press conference after Thursday’s monthly meeting, Chatterjee declined to comment on whether he agreed with Commissioner Richard Glick’s criticism of the New England Power Pool’s policy of excluding the public and press from stakeholder meetings.

On April 10, the commission voted 3-0 to dismiss RTO Insider’s complaint under Federal Power Act Section 206 asking it to force NEPOOL to open its meetings or to strip it of its role as the stakeholder body for ISO-NE.

Chatterjee joined Glick and Commissioner Bernard McNamee in concluding FERC lacked jurisdiction to force such a rule change (EL18-196). Glick filed a concurrence, saying that while he agreed with his colleagues on the jurisdictional issue, NEPOOL’s meeting policies are “misguided” and should be changed. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)

New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

Chatterjee declined Thursday to say whether he shared Glick’s view that NEPOOL’s meetings should be open. “I voted for the order. I think it speaks for itself,” he said, declining to elaborate.

LaFleur: Not Leaving Yet

Lame-duck Commissioner Cheryl LaFleur did not vote on the April 10 NEPOOL order or on an April 16 order regarding ISO-NE’s energy efficiency rules. (See FERC: ISO-NE Won’t Change EE Rules Without Stakeholder Talks.)

With the June 30 expiration of her term approaching, lame-duck Commissioner Cheryl LaFleur said she’s not leaving just yet. | © RTO Insider

The recusals led to speculation that LaFleur — who announced Jan. 31 that she would not be appointed to a third term — has begun to search for her next job. Although her term ends June 30, she could serve the remainder of this year if no replacement is confirmed.

ClearView Energy Partners said such recusals are “common when a sitting commissioner is interviewing with an entity that may be involved in proceedings before the commission.”

LaFleur, a New Englander, came to FERC after serving as executive vice president and acting CEO of National Grid USA.

LaFleur — who previously declined to give the reason for her recusal on the NEPOOL order — did not offer any clues to her plans at Thursday’s meeting, where she introduced her son and husband in the audience.

“For the members of our friendly press corps, the fact that I have my family here does not mean this is my last meeting,” she said, turning to reporters. “I will let you know when it’s my last meeting. I promise.”

PJM MOPR Issue ‘Really Complicated’

Chatterjee said the commission hasn’t yet acted on PJM’s proposed changes to its capacity market because of the complexity of the issues.

PJM, which normally holds its annual capacity auction in May, delayed it until August in the hopes that would give the commission time to rule on its proposed changes to its minimum offer price rule (MOPR). In June 2018, the commission ruled the RTO’s existing MOPR was unjust and unreasonable because it didn’t address price suppression from state subsidies for renewable and nuclear power. (See PJM to Hold Capacity Auction in August.)

Chatterjee was asked at his press conference whether FERC’s failure to act on the proposal suggested a 2-2 split among the current commissioners and the need to fill its fifth seat.

The chairman said although he was prohibited from discussing internal deliberations, he could comment “at the macro level.”

“When it comes to wholesale power markets, these aren’t things that break down on ideological or political lines,” he said. “It’s just something my colleagues and I and staff are working towards. It is not something that we’re gridlocked because of some kind of political difference. It’s really, really, really complicated.”

— Rich Heidorn Jr.

April 21, 2019

Chatterjee Denies Lobbying Against FERC Nominee

By Rich Heidorn Jr.

WASHINGTON — FERC Chairman Neil Chatterjee on Thursday denied a report that he lobbied to block the nomination of Republican David Hill to the commission.

Citing interviews with a dozen industry and political sources who requested anonymity, E&E News reported April 12 that Chatterjee made calls to energy companies and Republican allies to block Hill from replacing him as chairman. E&E quoted Hill, an energy attorney who served in the George W. Bush administration, as confirming that the White House told him he would be appointed FERC chair.

FERC Chairman Neil Chatterjee speaks to the press following the April 18 open meeting. | © *RTO Insider*

Chatterjee did not respond to E&E’s requests for comment before publication of the article. But in his regular news conference following the commission’s monthly open meeting Thursday, Chatterjee attempted to discredit the report.

Hill was the Department of Energy’s general counsel from 2005 until 2009 and NRG Energy’s general counsel between 2012 and 2018.

E&E said Hill’s nomination was all but official until lobbying efforts by Chatterjee, Energy Secretary Rick Perry and the coal industry caused the White House to abandon him. Hill had publicly criticized DOE’s bids to provide subsidies for struggling coal and nuclear generators.

Chatterjee gave his rebuttal Thursday when E&E reporter Rod Kukro, one of the authors of the article, asked him when he became aware that the White House intended to replace him with Hill.

Chatterjee challenged Kukro’s premise, saying two other reporters had pursued the story and published nothing because they were unable to verify it.

“I know you cited 12 sources that you talked to. I know for a fact that at least two of those sources pushed back aggressively on the story line, yet their statements weren’t reflected anywhere in the article. I also know that at least a couple of those sources directed you towards the actual people that were involved in this process and knew the details of it, and you ran the story without contacting the folks that were actually in the room and knew the circumstances of the story. You had no named sources. No corroboration.”

Chatterjee challenged E&E’s account that the White House and Hill began preliminary discussions in September 2018 about taking over for ailing Chairman Kevin McIntyre.

McIntyre, who was visibly unwell in his last commission meeting in July, relinquished the chairmanship to Chatterjee Oct. 24 after revealing that he had suffered a “serious setback” in his cancer fight. He died Jan. 2.

“David Hill is a good man, and I find it almost impossible to believe that David Hill would have been negotiating in September to be chairman of the commission while Kevin McIntyre was still alive and serving,” Chatterjee said.

“Well [Hill] was the source, and he was named in the story,” Kukro shot back. “Are you saying he’s lying that [National Economic Council Director] Larry Kudlow told him he was going to be chairman?”

“I can’t speak for conversations you had with David Hill,” Chatterjee responded. “I don’t know that that’s ever been corroborated by anybody.”

RTO Insider asked the chairman why he did not respond prior to the article’s publication.

“The story was so baseless that I didn’t think it merited a response,” Chatterjee said.

“So, you’re saying you had no conversations with anyone regarding Hill’s candidacy?” he was asked.

“No reporter has been able to identify a single individual that I contacted or what I talked about,” Chatterjee said.

“That doesn’t sound like a denial,” the reporter said.

“That’s a denial,” Chatterjee said.

April 21, 2019

MISO PAC Contemplates SATA Shakeup

By Amanda Durish Cook

The MISO Planning Advisory Committee will vote by email on a DTE Energy proposal to broaden the scope of the RTO’s effort to create new rules allowing storage projects to solve transmission needs.

DTE’s motion proposes that stakeholders and the PAC recommend that MISO include a path for non-transmission owners as well as TOs to own and operate storage-as-transmission assets (SATA). The motion will appear on an email ballot April 22-26.

MISO’s Carmel, Ind., control room | *MISO*

In developing the rules, MISO determined that only registered TOs should be eligible to own SATA in order to avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services.

DTE says non-TO SATA should be permitted to bypass the interconnection queue and connect to MISO’s transmission system via newly conceived storage interconnection agreements.

To be eligible to secure a storage interconnection agreement, DTE proposes that resources must resolve a transmission-reliability issue identified in the annual Transmission Expansion Plan (MTEP) process, “satisfy the same performance criteria” as other SATA in the MTEP analyses, and “be operated strictly at the direction of MISO’s transmission-reliability function to address such issues.”

DTE’s Nick Griffin said the motion will close an “equity gap” in MISO’s first SATA filing with FERC. Absent DTE’s provision, he said, the SATA ruleset would create preferential treatment for TOs and “create barriers for entry for storage.”

Griffin said the motion does not yet address cost recovery.

In a complicated interpretation of MISO’s stakeholder process, the Steering Committee last month directed the PAC to revisit the possibility of non-TOs owning SATA in response to DTE’s request. (See MISO Planning Committee to Reconsider Non-TO Storage as Tx.) Some stakeholders were concerned that PAC leadership prematurely suppressed conversation on DTE’s proposals by not holding a vote to gauge whether stakeholders thought the idea warranted further debate.

MISO has said stakeholders agreed before drafting the SATA rules that they would neither address non-transmission alternatives (NTAs) nor create an entirely new cost allocation as a part of the SATA policy development.

But MISO Director of Planning Jeff Webb said the RTO’s existing process to consider NTAs in transmission planning may cover what DTE seeks.

“As a general matter, we do not require non-transmission alternatives to complete the generator interconnection process unless the asset is a generation facility seeking access to the market,” Webb explained.

Not that Simple, Stakeholders Say

Entergy’s Yarrow Etheredge pointed out there is no structure in place for MISO to assume functional control over assets other than transmission. She said DTE’s proposal wasn’t as simple as minor Business Practices Manual or Tariff changes.

Great River Energy’s Jared Alholinna agreed that DTE’s motion would create a “gray area” around what is and isn’t transmission and could ultimately undermine the FERC definition of transmission.

“This is being characterized as quite narrow, but it really balloons out,” American Transmission Co.’s Bob McKee said.

Griffin said non-TO SATA could have similar treatment to a generator under a system support resource agreement, in which MISO dictates that assets be available for dispatch.

“We think with a few minor BPM and Tariff changes, we could achieve analogous treatment,” Griffin said.

But Etheredge said an SSR-style treatment still lacks the automatic controls that MISO has established with its TOs.

Xcel Energy’s Drew Siebenaler said the motion could create the discriminatory treatment DTE claims to combat because the proposal names a special interconnection path meant only for storage devices.

“I would view that as a discriminatory filing,” Siebenaler said.

DTE coming forward without a defined cost allocation was problematic as well, added Xcel’s Carolyn Wetterlin. She said she had never heard of a MISO project gaining approval without first having an established cost allocation method.

MISO’s Environmental sector took the discussion as an opportunity to call out the SATA proposal as too limiting in the first place. Clean Grid Alliance’s Natalie McIntire said the current plan ignores the full spectrum of storage capabilities. She said MISO has rushed the first SATA proposal and “unreasonably” limited the scope of a possibly “precedent-setting” ruleset.

Webb acknowledged that MISO’s “first stage” SATA rules are intentionally narrow so that storage doesn’t have to scale the approximate three-year interconnection queue before being eligible to solve a transmission need.

“We wanted to clear that barrier first,” he said.

Webb promised MISO stakeholders future Tariff proposals that would allow expanded and multifaceted storage use in the footprint.

The PAC will hold a May 15 conference call to discuss refinement of the SATA filing and announce the ballot results on DTE’s motion.

MISO hopes to file the new rules with FERC in June or July. One SATA project is currently moving through MTEP 19 in the hopes that rules are in place by the end of the year.

April 21, 2019

April 24 TAC Canceled; OCN Workshop Set

The ERCOT Technical Advisory Committee’s leadership has canceled the committee’s April 24 meeting because of a “limited number of items to be considered” and does not plan to hold an email vote.

TAC Vice Chair Diana Coleman and Chair Bob Helton | © *RTO Insider*

Instead, ERCOT will use the date to hold a workshop on outage activity related to its operating condition notice (OCN) in late February. The OCN set in motion events that resulted in market complaints about the grid operator’s communication practices and transparency. (See ERCOT Generators Upset over Early March Weather Event.)

The workshop will begin at 9:30 a.m. The TAC’s next regularly scheduled meeting is May 22.

— Tom Kleckner

April 21, 2019January 15, 2025

West Wrestles with Resource Adequacy, Grid Reliability

By Hudson Sangree

SALT LAKE CITY — Regulators and industry experts from across the West last week heard about cyberattacks and natural disasters, having enough renewable energy to meet demand, and the possibility of using compact nuclear reactors to backstop wind and solar.

The s pring joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) focused on grid reliability and protecting crucial infrastructure. The conference spread across three days, with roughly 16 hours of panel discussions and approximately 175 people in attendance.

It opened with a panel on small modular nuclear reactor power plants, in which NuScale Power showed its design for a 60-MW reactor that is far more compact than traditional nuclear units. NuScale is working with the Utah Associated Municipal Power Systems (UAMPS) and the Idaho National Laboratory (INL) to develop a working module by 2026. (See With Big Nukes Dwindling, Supporters Focus on Modular.)

The NuScale unit looks like a 75-foot-tall, 15-foot-wide torpedo. Twelve of the units could be combined to form a 720-MW power plant covering 35 acres, much less ground than is usual today, said Chris Colbert, NuScale’s chief strategy officer.

“We’ve moved a number of components into the reactor pressure vessel, and what that allows us to do is to get rid of the piping and the pumps” that occupy much of the area in a traditional nuclear generating station, Colbert said. “When you go to a smaller design, you’re able to eliminate over two-thirds of the systems and components you find a in a typical reactor.”

That makes the unit simpler, with “less to operate it, less to maintain it and less things that can go wrong,” he said.

A compact nuclear unit designed by NuScale. | NuScale

Colbert and his fellow panelists acknowledged the public blowback that’s likely to greet any proposal for a new nuclear plant.

“Obviously we’ve got a lot of risk here,” UAMPS CEO Doug Hunter said.

The developers said they are planning to build the first generator at the Idaho National Laboratory, a nuclear research site larger than Delaware, with construction slated to start in 2023. They’re hoping the isolated site and lots of public outreach “will allow a new generation of reactors to exist,” said George Griffith, an INL relationship manager.

Colbert said the units will be needed to ensure reliability as older fossil-fuel generators are retired and a fast-growing number of states and cities establish carbon-free mandates. Wind, solar and hydroelectric may not be enough to keep the lights on because of varying weather and rainfall, he said.

“For those of you who’ve ever lost power for more than a day, you know what that can be like,” Colbert said. “Imagine if it did it all the time.”

Resource Adequacy Concerns

The same scenario was on the minds of state regulators and utility representatives who spoke at the meeting.

In a panel on Western resource adequacy and market purchases, Rick Link, vice president of resource planning and acquisition for Pacific Power, said diminished demand in the wake of the 2008 financial crisis had created surpluses and made it relatively easy to depend on market purchases to supply needed power.

The thinking went, he said, that “it may be cheaper to do that, as long as [the power’s] there, than spending $700 million to build a new gas facility.”

State regulators who lead CREPC-WIRAB include (faces visible from left to right): Cliff Rechtschaffen, CPUC; Janea Scott, California Energy Commission; and Ann Rendahl, Wasington UTC. | © RTO Insider

But supply is tightening, and the situation is changing, he said. Those tasked with ensuring grid reliability can no longer just talk about economics and the best use of existing resources. Instead, they need to look at the development of new resources and innovative responses.

“It’s great timing to have this discussion,” Link said. “We may be transitioning into a period where we at least have to ask the question, ‘Will [the electricity] be there?’ So, it is more one of reliability, and that needs to be pushed front and center.”

Panelists focused on the need for a regional entity to coordinate purchases and generation throughout the Western Interconnection and having sufficient transmission capacity. States will have to play a bigger role in regulation and coordination, they said. And utilities need to be able to share information about their activities to avoid conflicts, some contended.

Washington Utilities and Transportation Commissioner Ann Rendahl said regulators are concerned that utilities are overly reliant on market purchases, putting consumers at risk of rising prices in times of high demand and tight supply.

John Sterling, First Solar, and Arne Olson, Energy and Environmental Economics, discussed solar as a dispatchable resource. | © RTO Insider

“What we don’t know is whether [the utilities are] all basically relying on the same resources,” Rendahl said. That would become clear in a cold snap or heat wave when supply tightens and prices shoot up, she and others said.

“There’s increasing uncertainty that there is sufficient resource adequacy in the next five years, creating an increasing possibility of a regional capacity condition” in the Pacific Northwest, Rendahl said. “Everyone is agreeing that we’re approaching this point.”

The “capacity surplus is quickly dwindling,” she said, “and the utilities … are not stepping forward to build capacity, leading to this very tight capacity market.”

Disaster Readiness

Other panels at the meeting dealt with electric vehicles and the need to protect utility infrastructure from terrorist attacks. (See Western EIM Looks to Expand Its Authority.)

The discussion returned repeatedly to the theme of making sure the lights stay on.

Attendees listen to a panel on EIM governance that included left to right: Stacey Crowley, CAISO; Jordan White, Utah Public Service Commission; and Cliff Rechtschaffen, CPUC. | © RTO Insider

During a presentation on the Initiative for Resilience in Energy Through Vehicles (iRev), panelists — including Laura Nelson, executive director of Utah Gov. Gary Herbert’s Office of Energy, and David Terry, executive director of the National Association of State Energy Officials — discussed EVs in the context of catastrophes. EVs could allow evacuations in situations where gas is unavailable and could ensure emergency workers have vehicles that run, they said.

Most areas only have a week’s worth of gas on hand at a given time, they said. Terry showed a photo of cars crowding a gas station after Superstorm Sandy in 2012.

Natural disasters such as Hurricane Katrina in 2005 and the 1989 Loma Prieta earthquake in the San Francisco Bay Area had shown the potential for the grid to go down for extended periods, said Doug Little, senior adviser in the U.S. Department of Energy’s Office of Electricity.

“Imagine if you had to live for a week without electricity. It’s pretty scary,” Little said during his talk on protecting defense-critical electric infrastructure in the West.

“Katrina got pretty ugly” in New Orleans, and San Francisco lost power for several days after Loma Prieta, he said.

“Now we have to worry about destruction by terrorists that have become more and more resourceful,” Little said. “We could see casualties and effects on security and economy from a cyberattack that would be comparable to weapons of mass destruction.”

A panel on Western Resource Adequacy was a big draw Thursday. From left to right: Arne Olson, Energy and Environmental Factors; Rick Link, Pacific Power; David Mills, Puget Sound Energy; and Ann Rendahl, Washington UTC. | © RTO Insider

Russia, China and Iran represent potential cyber-terror threats, he said. (See Senators Call for Urgency on Energy Cybersecurity.)

The federal government’s Advanced Research Projects Agency-Energy is investigating longer-duration battery storage to power the grid from 10 to 100 hours during disasters, Little said.

“If there was ever a time for megawatt-scale storage to be important, this is it,” he said.

April 21, 2019

FERC Proposes Revisions to NERC CIP Standard

By Rich Heidorn Jr.

FERC on Thursday proposed changes to NERC’s draft critical infrastructure protection (CIP) standard addressing the cybersecurity of real-time communications between control centers.

Also exempt are oral communications, which are covered by standard COM-001-3.

‘Largely Responsive’

The commission said those two standards only require redundant and diversely routed data exchange infrastructure within control centers, not between them.

It also said the standard must be revised to add a definition of “real-time monitoring,” which is not spelled out in the standard or the NERC Glossary.

But it said “real-time monitoring is not defined at all.”

“We are concerned that without further clarity, reliability standard CIP-012-1 may be implemented and enforced in an inconsistent manner,” the commission said.

Comments on the NOPR are due 60 days from publication in the Federal Register.