Page 1052 – RTO Insider

April 22, 2019

Renewables Outlook to Get Boost in MTEP 20 Futures

By Amanda Durish Cook

After prodding by stakeholders, MISO now says it will boost renewable generation estimates in each of the four 15-year future scenarios that guide its annual transmission planning process.

MISO had previously proposed relying on an older set of futures to inform the 2020 Transmission Expansion Plan (MTEP 20). But stakeholder pushback prompted the RTO to increase the minimum renewable penetration levels for each future by 5%, bumping projections from 15-35% of the generation mix to 20-40%.

Speaking at a Planning Advisory Committee meeting Wednesday, MISO Planning Manager Tony Hunziker noted the high degree of consensus among stakeholders to increase renewable estimates.

Increased renewable projections in MTEP 2020 futures | MISO

The MTEP will also assume the solar investment tax credit — which allows a 30% federal tax deduction of installation costs — will continue into 2023. The RTO will also rely on the National Renewable Energy Laboratory’s Annual Technology Baseline capital cost projections for renewable generation instead of using a 30% variance on those projections.

However, some stakeholders said they’d like to see a more nuanced approach to projecting renewable growth based on subregional characteristics to avoid blindly increasing renewable projections. For instance, MISO shouldn’t expect significant wind generation growth in sunny MISO South, some noted.

“MISO is not a resource planner. We don’t dictate renewable resource additions,” Hunziker responded.

Entergy’s Yarrow Etheredge said MISO didn’t adequately support the case for a blanket increase of every type of renewable generation everywhere in its footprint.

“This is basically just an adder,” Etheredge said, asking MISO to defend the change using data.

Hunziker promised a complete rework of MTEP 21 futures with stakeholders and reminded PAC members that MISO was up against a June deadline to finalize MTEP 20 futures definitions and assumptions.

The RTO last month said it would rely on the same set of 15-year futures for the third straight year to evaluate transmission projects in MTEP 20, though some stakeholders criticized the RTO’s limited fleet change future as no longer a likely scenario. (See MISO Going Back to the Futures for MTEP 20.) The futures scenarios include a limited fleet change, continued fleet change, accelerated fleet change, and a distributed and emerging technologies future.

Hunziker said the renewable increase should alleviate specific concerns about MISO’s limited fleet change future, which has been criticized as improbable because it projects only an 11-GW growth in renewable generation through 2033. MISO’s interconnection queue currently includes about 420 projects worth a combined 70 GW; renewable resources account for about 90% of the queue. Historically, about 18% of proposed projects clear the queue.

Last month, members of MISO’s Board of Directors also questioned whether the limited fleet change future was still plausible.

“It seems like the rate of adoption is increasing,” Director Thomas Rainwater said, while also acknowledging that MISO is “no California” in terms of appetite for renewables. He asked if the RTO will consider “a more radical adoption” of renewables and distributed resources in a new set of futures for MTEP 21.

MISO Vice President of System Planning Jennifer Curran said the accelerated fleet change and distributed and emerging technologies scenario are fast becoming the most probable futures and noted the RTO will soon revisit how futures are developed. But she also cautioned that MTEP futures represent possible trends and are not meant to be forecasts.

At the April PAC meeting, Minnesota Public Utilities Commission staff member Hwikwom Ham said he remained concerned that the limited fleet change and continued fleet change scenarios still risk obsolescence because they don’t account for the zero-carbon pledges of multiple utilities and increasing electrification of the economy. He also pointed out that equity investors are now contemplating a company’s carbon footprint as a risk factor before making investments decisions.

“Who is going to be in the White House next year? It’s going to be a different business model,” Ham added, referencing President Trump’s rollbacks of environmental regulations.

Hunziker said MISO will raise those topics in the redevelopment of futures in time for MTEP 21.

Meanwhile, MTEP 20 marks the first time MISO will work with Purdue University’s State Utility Forecasting Group and Applied Energy Group to create separate load forecasts that reflect each of the four futures. The RTO this month reported that entities representing 77% of its load responded to its request for load, demand and energy data.

April 22, 2019

More Time Needed for Storage Compliance, MISO Says

By Amanda Durish Cook

CARMEL, Ind. — MISO will ask for at least another year to comply with FERC Order 841, saying the intricacy and expense of incorporating storage into its markets is greater than it originally anticipated.

MISO leaders say the original Dec. 3 go-live date to comply with the order is no longer feasible given FERC’s recent deficiency letter in response to the RTO’s proposed storage participation model. MISO was counting on the commission accepting its filing this month to maintain a strict timeline for adapting its market to storage participation.

FERC earlier this month issued separate deficiency letters to all six jurisdictional RTOs and ISOs regarding their plans for energy storage participation. (See FERC Asks RTOs for more Details on Storage Rules.) The commission specifically asked MISO for several more details and explanations related to its phased participation approach, proposed commitment statuses, complexities for distribution system storage resources, conflicting offers and bids, and make-whole payments. The RTO has until early May to respond.

MISO Director of Market Design Kevin Vannoy said the combination of a later-than-anticipated FERC order, remaining uncertainty about what the commission will decide after the RTO’s response and holding work on software changes because of that uncertainty led to the request.

“In our response to this request, we are going to ask for a deferral,” Vannoy told the Energy Storage Task Force on Thursday.

Vannoy said the deferral would be “no earlier than a number of months after a clean order.” When pressed, he said the RTO could request for 12 to 18 months from when FERC fully accepts its filing.

The “cost and complexity” of implementing new bid parameters for storage was greater than MISO predicted in 2018, Vannoy said. Work also remains on how energy storage operators will communicate data to the RTO, he added.

MISO is in the process of answering FERC’s multiple questions in the 10-page deficiency letter, he said.

“We didn’t see anything in there one way or the other that they were leaning towards rejecting or accepting the filing. We think they simply need more explanation,” Vannoy said of the commission’s tone in the letter.

FERC also asked MISO to explain a provision that prohibits distribution-level storage resources from pseudo-tying into a different balancing authority. Vannoy said RTO leadership feels that pseudo-tying storage is beyond the scope of the final rule.

MISO had warned stakeholders in mid-April that it was anticipating a “significant delay” in developing a functioning model for storage participation.

During an April 11 Market Subcommittee meeting, Vannoy said MISO staff have been discussing the deficiency letters with other RTOs. He said MISO is limited by what its legacy market platform can handle as it’s gradually swapped out for a new cloud-based market platform. MISO Senior IT Director Curtis Reister said the RTO is targeting a complete replacement of the platform by 2024, and rolling out a new market user interface — the site market participants use to submit bids and offers — in mid-2021. (See MISO Seeking Multiple Vendors for Market Platform Redesign.)

The Energy Storage Task Force meanwhile is set to sunset in June. Task force Chair John Fernandes said that through next month, the group will create a spreadsheet of storage issues that other stakeholder groups can concentrate on, focusing heavily on how the RTO will integrate hybrid resources that contain storage assets.

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, 2019

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