Page 1157 – RTO Insider

December 22, 2019

Western Order 845 Filings Need Fixes, FERC Says

By Hudson Sangree

Four Western utilities generally complied with FERC rules intended to make it easier for generators to connect to transmission grids but had shortcomings in several common areas, the commission found last week.

FERC evaluated the filings against Order 845’s 10 reforms meant to increase the transparency and timeliness of the generator interconnection process. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

Problems arose under reforms involving contingent facilities, provisional interconnections and new technologies.

Contingent Facilities

In Avista’s filing, for example, FERC said the company had failed to identify specific requirements for contingent facilities. Contingent facilities are unbuilt interconnection facilities and network upgrades on which an interconnection request’s costs, timing and study findings depend.

“Avista’s proposed Tariff revisions lack the requisite transparency required by Orders No. 845 and 845-A because the proposed Tariff revisions do not detail the specific thresholds or criteria that Avista will use as part of its method to identify contingent facilities,” FERC wrote. “Without this information, an interconnection customer will not understand how Avista will evaluate potential contingent facilities to determine their relationship to an individual interconnection request.”

FERC directed Avista to file a further compliance filing within 60 days with the “specific thresholds or criteria it will use in its technical screens … to achieve the level of transparency required by Order No. 845.”

Similar deficiencies were identified and ordered corrected by FERC in the filings by PacifiCorp, PSCo and PNM.

FERC’s findings on contingent facilities echoed last month’s determinations on the Order 845 filings of Portland General Electric, Tampa Electric Co. and others. (See FERC Finds Partial Compliance on Order 845.)

Provisional Interconnection

PacifiCorp, PSCo and PNM fell short when it came to provisional interconnection services, FERC found.

Order 845 required transmission providers to let interconnection customers request provisional interconnection service when studies show there’s a level of service available to accommodate an interconnection request without new interconnection facilities or network upgrades, and when the interconnection customer wants to make use of that service while it completes facilities for its full interconnection.

PacifiCorp’s proposed language stated that it would update provisional interconnection studies “as system conditions warrant.”

That, FERC said, would “create too much discretion for PacifiCorp regarding the frequency for updating provisional interconnection studies.”

PSCo proposed to conduct updated provisional interconnection studies “if necessary, on a quarterly basis” — a proposal FERC rejected.

“While the commission gave the transmission provider discretion to determine the frequency for updating provisional interconnection studies in Order No. 845, PSCo’s proposed inclusion of the phrase ‘if necessary’ provides PSCo unfettered discretion to determine the frequency at which it will update provisional interconnection studies,” the commission wrote.

PNM had the same issue, FERC found.

Incorporation of Advanced Technologies

In Order 845, the commission allowed an interconnection customer to incorporate some technological advancements to its interconnection request without losing its queue position. It required transmission providers to develop and include in their procedures a definition of permissible technological advancements that, by definition, do not constitute a material modification.

Avista said it would use “reasonable efforts” to assess a technological change request. FERC said that language wasn’t acceptable. The company also failed to explain how it would evaluate a technological-advancement request to decide if it was a material modification and didn’t establish a time frame for making an evaluation, FERC said.

“Accordingly, we direct Avista to file, within 60 days of the date of this order, a further compliance filing that cures these deficiencies or explains why these requirements are not necessary for this aspect of Avista’s proposed procedure,” FERC said.

PNM and PacifiCorp had similar problems with their technological-change request procedures, FERC said.

December 22, 2019

ISO-NE Planning Advisory Committee Briefs: Dec. 19, 2019

New England’s carbon emissions could decrease by an average of 1.4 million to 1.5 million short tons per 1,000 MW of offshore wind capacity added in the region, with production costs falling by $128 million to $138 million, according to a new study by the New England States Committee on Electricity, the ISO-NE Planning Advisory Committee heard last week.

Impacts decrease as more megawatts are added, based on preliminary results from NESCOE’s 2019 Economic Study outlining scenarios with as much as 6,000 MW of OSW additions. It was presented by Patrick Boughan, an RTO senior engineer for system planning.

NESCOE, Anbaric Development Partners and RENEW Northeast submitted requests for additional studies at the PAC meeting in April. (See ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)

Possible additions of 8,000 MW of offshore wind will be discussed at a subsequent PAC meeting. All such additions are in the southern portion of the New England system, Boughan said.

The analysis also shows annual average LMPs decreasing as offshore wind increases.

“Congestion is concentrated at the Surowiec-South interface [in Maine] and decreases as you add more offshore wind, decreasing by an average $16.5 million per 1,000 MW of offshore wind capacity,” Boughan said.

The assessment of offshore wind additions for the study do not take into consideration transmission upgrades associated with interconnection to the grid or Forward Capacity Market participation, he said.

“We’re using 2006 [National Renewable Energy Laboratory] offshore wind profiles due to their availability. However, we have new 2015 offshore wind profiles in development right now, and all these results today will be rerun with 2015 profiles,” Boughan said. “While we do expect those changes to affect the model, the trends we see in this presentation are expected to hold, and not vary significantly.”

Improving the Regional System Plan

ISO-NE Director of Market Development Carissa Sedlacek presented a summary of the 2019 Regional System Plan and asked stakeholders to help improve the process for making the plan.

Following a public forum in Boston in September, the RTO’s Board of Directors approved the 2019 RSP, which was posted on Oct. 31. (See Overheard at ISO-NE Regional System Plan Public Forum.)

“It takes nearly a year to develop the RSP, and we’re asking you what else we can do to make it better,” Sedlacek said.

The RTO last May held Grid Transformation Day as a special PAC meeting to present and discuss the technical challenges of a hybrid grid. The meeting and attendance exceeded expectations, she said. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)

“In January, we will send out a survey to PAC members and other stakeholders to seek input on how to improve the plan, focusing on finding new ways to keep the RSP forward-looking, and on how to streamline the development process,” Sedlacek said.

December 22, 2019

Ruling Reinstates MISO TO Funding of Upgrades

By Amanda Durish Cook

FERC last week approved a MISO proposal to once again allow transmission owners to provide initial funding for transmission upgrades needed for generation projects, possibly upending more than 100 interconnection agreements struck over a three-year period.

The commission’s decision means contracts signed between June 24, 2015, and Aug. 31, 2018, can be revised to allow TOs and affected-system operators to “unilaterally elect to provide initial funding for network upgrades, if they so choose,” the commission said (EL15-68-003, et al.). The order applies to pro forma generator interconnection agreements, facilities construction agreements and multiparty facilities construction agreements (GIAs, FCAs and MPFCAs).

FERC’s order is the culmination of four years of back-and-forth rulings between the commission and the judiciary — and is still a point of contention within the commission’s ranks. Commissioner Richard Glick dissented, saying the order lacked reasoning and didn’t address possible preferential treatment of TOs over interconnection customers.

MISO policy previously allowed incoming generators to self-fund new construction regardless of whether TOs wanted to fund the construction themselves. FERC in 2015 directed the RTO to remove the option for a TO to elect to fund the interconnection upgrades.

The D.C. Circuit Court of Appeals vacated FERC’s decisions on the self-funding option in early 2018, saying the commission didn’t consider complaints from Ameren and five other TOs who claimed the policy forced them to accept “risk-bearing additions to their network with zero return” and essentially act as “nonprofit managers” of network “appendages.” The TOs had argued the Federal Power Act and Constitution prohibits FERC from forcing them to construct and operate generator-funded network upgrades. The case was remanded back to FERC.

MISO last year said FERC’s decision could affect GIAs dating back to 2015 and submitted a pre-emptive compliance filing to reflect TOs having the option to self-fund network upgrades. (See MISO Files Revised Upgrade Funding Provisions.)

With the commission’s order, the RTO is now faced with creating a process for amending agreements and determining financial fallout.

FERC directed MISO to file Tariff edits within 60 days to reinstate the TO-funding option, “provided that such election is done in a not unduly discriminatory manner.” The commission also asked for a list of all interconnection agreements over the three-year period in which the TO would like to exercise the initial funding option.

“‘When the commission commits legal error, the proper remedy is one that puts the parties in the position they would have been in had the error not been made,’” FERC said, quoting a 1999 D.C. Circuit decision over rates on the Trans Alaska Pipeline System. “Providing transmission owners and affected-system operators the right to elect the transmission owner initial funding option for any GIA, FCA and MPFCA that became effective during the interim period is an appropriate remedy in this case to give effect to the court’s vacatur, as it seeks to return the parties to the position they would be in if the commission had not issued the now vacated orders.”

MISO transmission upgrades — | © *RTO Insider*

‘Not so Burdensome’

The commission acknowledged that MISO and its members face complex issues when reopening existing agreements but said the intricacies didn’t outweigh leaving the unfair treatment in place. Several MISO members, particularly those with projects in the interconnection queue, said the retroactive decision will threaten their ability to meet production tax credit deadlines if power purchase, tax equity, lender and other agreements must be revisited. The American Wind Energy Association argued that FERC’s decision could cause projects in the late stages of the queue to drop out, triggering a ripple effect of restudies.

“We find that these concerns are not so burdensome as to overcome the presumption that the commission should place parties in the position they would have been in absent the commission’s legal error. While we acknowledge that reopening existing GIAs, FCAs [and] MPFCAs may increase costs to certain interconnection customers or result in disruption to schedules … we are not persuaded that these potential impacts are so great that we should deprive transmission owners or affected-system operators of an opportunity to earn a return on the capital costs of the network upgrades built on their system that should have been expressly allowed,” FERC said.

The commission also said it would not establish a process for generation developers, generation owners and interconnection customers to recover losses in light of the change. Some MISO members had asked that FERC shield developers and interconnection customers from circumstances beyond their control, but the commission said the developers and customers had been “on notice that the commission’s orders on review could be remanded or vacated, and that a judicial remand and/or vacatur could require changes to agreements entered into during the pendency of these proceedings.”

“As such, interconnection customers could have taken steps to mitigate these risks,” FERC said.

Glick Dissents

Glick said the decision doesn’t address the commission’s previous concern that giving TOs the unilateral right to decide whether to fund network upgrades could be unfair to MISO’s interconnection customers. He said FERC’s decision may deprive interconnection customers the “opportunity to finance network upgrades with more favorable terms and rates.”

And he criticized his fellow commissioners for how they chose to address the court’s concerns in the order on remand.

“By simply reversing the vacated orders with nothing more than conclusory statements, the commission is now in the untenable position of neither addressing the reasons for the court’s remand nor grappling with the commission’s underlying concerns of undue discrimination,” Glick wrote.

He said the commission should have solicited briefing after the remand to make a decision with more substantial evidence.

Instead, Glick contended, the commission sidestepped “the most significant issue presented in this proceeding: Transmission owners in MISO have the incentive to favor their own generation over others seeking to interconnect to the transmission system, and giving transmission owners the discretion to pick and choose when to self-fund network upgrades vests them with the opportunity to do so.”

Glick said the commission should have granted a rehearing so it could better evaluate the risk of preferential treatment and discrimination. He also said MISO’s TOs failed to prove any harms they would suffer if FERC left the three years of contracts in place, while interconnection customers will have the “economic rug [pulled] out from under” them.

“Today’s order suggests that, to give effect to the court’s vacatur, it must permit parties to reopen interconnection agreements previously negotiated without the transmission owners’ and affected-system operators’ unilateral right to elect to self-fund network upgrades. While I agree with the commission that we must, on remand, give effect to the court’s vacatur, this is far from the only relevant consideration,” he said.

December 22, 2019

FERC Denies PJM Monitor’s Fuel-cost Policy Complaint

By Christen Smith

FERC last week denied a complaint from PJM’s Independent Market Monitor that alleged the RTO erred when it decided against penalizing Tenaska Power Services last year over supposed fuel-cost policy (FCP) violations (EL19-27).

The commission said it agreed with PJM’s interpretation of Tenaska’s FCP that allowed it to use third-party quotes for natural gas when the data it generally relies upon to calculate its energy offers are unavailable — as it was on Jan. 6, 2018.

“PJM reasonably found that Tenaska did not violate its FCP by using third-party quotes to develop natural gas costs when a lack of liquidity prevented the use of its more specific fuel-cost methodologies,” FERC wrote in its order. “The language in the Operating Agreement further supports the reasonableness of PJM’s conclusion that no violation of the FCP took place, as the lack of market liquidity is a market condition that permits the use of third-party quotes such as the [Intercontinental Exchange] data provided by Tenaska.”

The Monitor had interpreted the language of the FCP to prohibit Tenaska from making offers under such conditions — a choice that would leave the dual-fuel Brandywine Power Facility in Prince George’s County, Md., subject to nonperformance penalties should extreme weather conditions disrupt its fuel oil supply, Tenaska said. In defense of its actions, Tenaska had pointed to a statement from the FCP that says, “under a set of defined market conditions, natural gas costs may be based on independent third-party quotes.”

PJM Fuel-cost Policy — FERC dismissed the Monitor’s complaint against PJM for not penalizing Tenaska Power Services last year over a supposed violation of its fuel-cost policy. | *Brandywine Power*

PJM asked FERC to dismiss the complaint in January 2019 on the grounds that the Monitor lacked the authority to override the RTO’s interpretation of Tenaska’s FCP. Ultimately, in a separate docket, FERC reaffirmed the Monitor’s right to protest FCPs. (See Another Win for PJM Monitor on Fuel-cost Policies.)

But FERC agreed with PJM’s decision not to penalize Tenaska, writing Thursday that the company “had a range of potential third-party quotes from which to choose and opted to rely on those on the lower end of the range.”

“The Market Monitor provides no basis for establishing this was an unreasonable choice under the circumstances presented in this case,” the commission wrote. “Thus, we conclude that PJM acted reasonably in finding that Tenaska acted in accordance with its FCP.

“We recognize that illiquid market conditions can present challenges in calculating accurate fuel costs,” the commission added. The ruling advised PJM stakeholders to continue to refine FCPs “to clarify processes for determining how a seller will develop its cost to address a wide array of market conditions, including illiquid conditions, consistent with PJM’s Operating Agreement requirements.”

The ruling comes just four days after the commission posted a mostly unredacted version of Tenaska’s January response to the Monitor’s complaint, including the FCP in use Jan. 5-6, 2018, when the alleged violations occurred. (See related story, FERC Releases Documents in PJM Fuel-cost Dispute.)

December 22, 2019

FERC Conditionally Accepts JCP&L Rate Request

FERC last week conditionally accepted Jersey Central Power & Light’s proposed rate request, subject to refund following hearing and settlement judge procedures (ER20-227).

The commission accepted the FirstEnergy operating company’s request for a 50-basis-point adder on its PJM base return on equity. However, FERC said its preliminary analysis found JCP&L’s request may be unjust and unreasonable.

FERC said the filing raised issues of material fact — including the determinations of base ROE and capital structure and the treatment of excess accumulated deferred income taxes — that couldn’t be resolved based on the record before it and ordered settlement procedures.

JCP&L filed its request in October to replace its current transmission revenue requirement with a new formula rate and associated protocols, effective Jan. 1, 2020.

The New Jersey Division of Rate Counsel, the state’s Board of Public Utilities and the Public Power Association of New Jersey opposed JCP&L’s request. They argued that the utility did not correctly apply the ROE methodology, resulting in an ROE above the applicable portion of the zone of reasonableness, and that it did not “sufficiently” prove that the adder will benefit ratepayers.

The groups also argued that JCP&L incorrectly presented its capital structure as a net long-term debt figure, ignoring FERC’s requirement of a gross long-term debt figure instead.

The commission found the requested adder to be consistent with Section 219 of the Federal Power Act and its own precedent. It conditioned its approval on the adder being applied to a base ROE that has been shown to be just and reasonable and subject to the resulting ROE being within the applicable zone of reasonableness, as may be determined in the settlement proceeding.

— Tom Kleckner

December 22, 2019

MISO Almost There on Order 845

By Amanda Durish Cook

MISO still has a handful of details to address before fully complying with FERC Order 845, the commission ruled last week.

FERC on Thursday directed the RTO to submit another compliance filing within 60 days to clear up its study process related to technological advancements, partial service requests and contingent facilities (ER19-1823-001, ER19-1960).

The commission issued Orders 845 and 845-A in 2018 and 2019, respectively, to increase the transparency and speed of generator interconnection processes. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

The commission found that MISO only partially complied with its directive that a customer be able to request interconnection service below its full generating facility capacity. It said the RTO omitted mandatory Tariff language showing that while interconnection service will be studied at the requested level, a project could be “subject to other studies at the full generating facility capacity to ensure safety and reliability of the system, with the study costs borne by the interconnection customer.”

FERC also directed MISO to explain why it gave itself 60 days to decide whether to conduct additional studies when an interconnection customer seeks to include technological advancements in its project prior to an interconnection facilities study agreement. The commission had previously prescribed 30 days to settle on any new studies and told MISO to either justify the two months or halve the timeline.

“While we understand that MISO has a large number of projects in its queue and a wide variation in studies that may be needed, we find that MISO has not justified its proposal to allow it 60 days from the date of receipt of additional information from an interconnection customer or merchant HVDC connection customer to conduct further studies,” the commission said.

Finally, MISO must include a fuller description of how it determines which projects in its annual Transmission Expansion Plan are “contingent facilities.” FERC Order 845 defines those facilities as a generation project’s unbuilt interconnection facilities and network upgrades that, if delayed or canceled, “could cause a need for restudies of the interconnection request or a reassessment of the interconnection facilities and/or network upgrades and/or costs and timing.”

Surplus Interconnection Proposal Just Fine

FERC found that MISO easily complied with a directive that RTOs establish an expedited queue process allowing interconnection customers to use or transfer surplus interconnection service at existing facilities.

MISO submitted a partial compliance filing in May to address the surplus interconnection directive. It proposed to rename its existing net zero interconnection option to “surplus interconnection service” and include interconnection and steady state analyses, while removing an existing competitive solicitation process for surplus interconnection service and clarifying that the original interconnection customer or affiliates have priority rights to any surplus service. (See Little Work Needed to Comply with Order 845, MISO Says.)

December 22, 2019

ISO-NE Issues First Competitive Tx RFP

By Michael Kuser

ISO-NE on Friday announced its first competitive transmission solicitation to address reliability concerns associated with the upcoming retirement of the Mystic Generating Station in Everett, Mass.

The request for proposals seeks to address transmission facility overloads under peak load conditions in the Boston area, as well as system restoration concerns with the underground cable system in the area.

The RTO will review all the proposals in a two-step process before selecting the preferred solution. The deadline for phase 1 proposal submissions is 11 p.m. on March 4, 2020.

ISO-NE and its Planning Advisory Committee will review the proposals to ensure they address the identified needs and are feasible and cost competitive. The RTO will then identify finalists, who will be required to provide additional details to guide its selection of the preferred solution.

ISO-NE competitive transmission RFP — Greater Boston area electrical distribution map | *ISO-NE*

FERC OKs ISO-NE RFP Rules.)

Exelon announced last year that it would retire Mystic in 2022, but FERC approved a cost-of-service agreement between the company and ISO-NE to keep Units 8 and 9 operating through May 2024.

Under the competitive process, any qualified transmission project sponsor (QTPS) may submit a phase 1 proposal, while NSTAR Electric and New England Power are required to submit a joint backstop transmission solution for consideration in response to the RFP.

According to the ISO-NE 2019 Regional System Plan (RSP) posted on Oct. 31, “the peak load needs were found to be non-time-sensitive because the needs were present in the study horizon cases of 2028 but were not observed in the time-sensitive cases of 2022.”

In addition, the system restoration need for reactive support is considered a non-time-sensitive need because the retirement date of Mystic 8 and 9 is beyond the three-year time-sensitive period, the RSP said.

The competitive solution process is detailed in Attachment K, Section 4.3 of the Tariff.

The pro forma agreement between the RTO and the selected QTPS spells out the development, design and construction of the project, including project milestones, status reports and cost-containment measures.

The RTO modeled its agreement on the designated entity agreement that PJM uses in its competitive transmission solicitation process.

December 22, 2019

NYISO Management Committee Briefs: Dec. 18, 2019

NYISO’s Management Committee on Wednesday recommended that the Board of Directors approve creating a short-term reliability process (STRP) to evaluate and address reliability impacts.

Keith Burrell, the ISO’s manager of transmission studies, presented the proposal and said the STRP may result from both generator deactivation and transmission facility reliability needs identified in a quarterly short-term assessment of reliability (STAR) study.

The new setup would enable NYISO to respond to changes on the system in a timely fashion while providing a better structure than the ad hoc generator deactivation process to address observed needs, and improve workload management for the ISO and responsible transmission owners, according to Burrell.

Revisions would be applied to Tariff sections 23.4.5.6 and 30.4, which were posted on the ISO’s website on Dec. 17 at the request of the Independent Power Producers of New York.

Related Tariff changes would expand the generator deactivation rules to apply to non-market participants that possess the authority to decide whether or when to deactivate a generator. To address non-market participants, the revisions include changes to the generator registration documents and the creation of a new responsible generator party certification.

The proposed revisions include a de minimis threshold of 1 MW to excuse generators with a lower nameplate rating from the obligation to comply with the generator deactivation rules in the STRP before they are permitted to deactivate.

The ISO anticipates February 2020 board approval and would file revisions with FERC requesting a May 1, 2020, effective date. With FERC acceptance, the first STAR would commence July 15, 2020.

The 2020 Reliability Needs Assessment would incorporate the effects of the Tariff changes.

NYISO Strategic Plan 2020-2024

Executive Vice President Emilie Nelson presented NYISO’s Strategic Plan for 2020-2024, saying that stakeholders want the ISO to continue to be an authoritative source of information for policymakers.

“We heard that we need to focus on our planning processes and that the class year work needs to be streamlined,” Nelson said. “Passage of the Climate Leadership and Community Protection Act further emphasized the need to continue to think through strategic priorities for the next five, 10 and even 20 years.”

The new law (A8429) requires 70% of the state’s electricity to come from renewable sources by 2030 and for power generators to be zero-emitting by 2040. It also raises the installed solar target to 6 GW by 2025 and calls for the state to procure 9 GW of offshore wind by 2035.

CEO Rich Dewey said the board concluded that “we’re working on all the right stuff but wanted us to think about the pace of change.”

“Given CLCPA, there’s going to be tremendous pressure on the schedule, and we need to move more deliberately and quicker than we have in the past,” Dewey said. “If you look at how much renewable and distributed energy resources are going to need to come online to achieve the goals, the pace of change will be faster than anything we’ve ever seen.”

EMS Update, New Reliability Metrics

Dewey said NYISO is working to deploy by Feb. 1 a new energy management system and business management system, both delayed in October because of problems related to stability and synchronization of data. (See “New System Software by March,” NYISO Management Committee Briefs: Nov. 20, 2019.)

“We moved into our parallel test window today and are running two systems side by side,” Dewey said. “We want to be ready for deployment as early as possible in 2020, as early as Feb. 1, if the weather permits.”

COO Rick Gonzales highlighted the use of new graphs in the monthly operations report to reflect enhanced reliability metrics, with the ISO now measuring daily and monthly net load forecast performance against 30-minute and hour-ahead forecast error.

— Michael Kuser

December 22, 2019

NERC Sees Opportunities, Challenges in Grid Evolution

By Holden Mann

“Significant and rapid change” will cause short-term challenges with resource adequacy in some regions, but utilities should be able to turn the evolving resource mix to their advantage with appropriate planning, NERC said last week.

NERC’s 2019 Long-Term Reliability Assessment reported that most regional entities had sufficient resource capacity to meet projected demand over the next 10 years. The two exceptions were ERCOT and Northeast Power Coordinating Council-Ontario, both of which were assessed as “marginal” because of anticipated shortfalls in generating capacity in the next five years.

In the case of ERCOT, the deficiency — about 4,900 MW by 2024 — is largely a result of the canceling of several planned wind, natural gas and compressed air energy storage projects, totaling about 3,900 MW, along with last year’s retirement of the 470-MW Gibbons Creek coal-fired plant. NERC also revised its summer peak demand forecast in the region upward by about 1,300 MW per year from 2019 through 2023, widening the gap further.

NERC grid evolution — TRE-ERCOT 5-year projected reserves (ARM and PRM) | *NERC*

Serious disparities between demand and capacity “could lead to an increased risk of entering emergency operating conditions” such as rotating outages during peak hours, NERC said. However, the organization noted that ERCOT has a large amount of Tier 2 resources — planned capacity that has completed a feasibility, facilities or system impact study, has requested an interconnection service agreement, or is included in an integrated resource plan — under development. These resources are projected to come online after 2023 and should be more than adequate to satisfy demand.

For NPCC-Ontario, the shortfall of about 600 MW is primarily because NPCC’s nuclear retirement and refurbishment program, which introduces the risk that planned upgrades may not be completed on schedule, leaving generating resources offline during periods of high demand. Here, the short-term deficiency is expected to be addressed by new market mechanisms to be introduced by Ontario’s Independent Electricity System Operator in the next few years that will allow additional resources such as off-contract generators and storage facilities to participate in auctions.

Wind, Solar, Gas Drive Resource Mix Changes

While long-term generating capacity is sound, the report did note that North American utilities will need to update their internal infrastructure to handle the developing resource mix.

More than 330 GW of installed capacity from wind and solar are planned to be added through 2029, growing their collective share of the grid to 26% from their current level of 15%, while nuclear and coal together decline from 29% to 23%. Natural gas is projected to decline as well, but at 36% in 2029, it will still hold the largest share of generating capacity.

This shift away from conventional synchronous generating resources will introduce new challenges, such as meeting demand shifts with intermittent renewables. NERC recommended that operators install additional system ramping capability to offset the variability of the sun and wind, along with upgrading their ability to forecast supply disruptions. Investment in transmission infrastructure is also needed in order to keep up with the spread of small-scale renewable energy projects, many of them in remote locations.

The report urged utilities to prepare for disruptions to the natural gas transportation system, such as line breaks and well freeze-offs, as well as identify how events in the electrical system itself — for instance, power failures to electric-powered compressors — might impact pipelines.

DERs and Storage Require New Thinking

Distributed energy resources, such as roof-mounted solar panels, will also play a growing role in the grid over the next 10 years, growing from 20 GW currently to more than 45 GW by 2029, accompanied by an expansion in grid-connected electric storage from less than 1 GW to nearly 9 GW (counting projects at all stages of construction). (See DOE’s Walker Sees Big Cuts in Storage Costs.) These projects have the potential to help maintain grid reliability and stability through decentralizing generation and locating it closer to demand. But utilities don’t always have visibility or control over the DERs, and their effects are “not fully represented in [bulk power system] models and operating tools,” NERC said.

“In areas with large or emerging DER penetrations, current operational models and system studies do not properly account for DERs. These models and studies will need to be improved to accurately represent the system’s behavior.”

The LTRA predicts utility-scale storage will grow from 708 MW as of 2017 to more than 8.5 GW by 2024.

“Before this storage is built and integrated into the BPS, the ERO should identify, assess and report on the risks and potential mitigation approaches to accommodate large amounts of energy storage on BPS reliability,” NERC said.

December 20, 2019

NERC Worries Standards Committee ‘Close to a Line’

By Rich Heidorn Jr.

A senior NERC official suggested Wednesday that Standards Committee members could jeopardize the Electric Reliability Organization’s effort to win recertification by balking at inclusion of ERO staff on standard drafting teams.

“One of the things that is important for not just our process but also for our accreditation with ANSI [the American National Standards Institute] is that we have a completely open process; that it be open to all participants,” said Howard Gugel, NERC vice president of engineering and standards. “I’m concerned that some actions that … this committee has taken over the last couple months are beginning to get a little bit close to a line that you may not want to tread closely to, especially in a time when we’re trying to do our ANSI accreditation.”

Gugel made his comments after some committee members attempted to block a regional entity official from the standard authorization request (SAR) drafting team on a cold-weather standard requested by FERC and NERC (Project 2019-06). He responded after Dominion Energy’s Sean Bodkin offered a motion to remove the official — identified as only “Candidate 6” — from the team.

NERC Standards Committee — NERC’s D.C. offices | © *ERO Insider*

“This is a philosophical issue for me. I don’t think the people who enforce the rule should be making the rules,” said Bodkin, Dominion’s NERC compliance policy manager. “Having an individual from the ERO actually participating in voting and drafting rather than supporting development of the standards isn’t really appropriate.”

Bodkin also said the candidate was ill-suited for the team because he had been an auditor for 11 years “and hadn’t actually been out in the field dealing with cold-weather issues.”

FERC and NERC called for the standard in their joint report on the January 2018 cold weather event that caused Gen Operators Cool to Winter Preparedness Standard.)

Gugel insisted there was no risk of “undue influence” by the official, noting that any standard would be subject to votes by NERC stakeholders, the Board of Trustees and FERC. “It’s different than other regulations,” he said.

He said including RE officials on SDTs is a response to “consistent feedback from the Standards Efficiency Review advisory group and [Members Representatives Committee] that we need more compliance input into standards development and specifically in the standard drafting team.”

Bodkin said RE officials should participate but should not have a vote on drafting teams. “ERO isn’t part of industry. It’s industry oversight, and the team should be made up of industry members,” he said.

NERC attorney Lauren A. Perotti responded that “there is no requirement [in NERC rules] that standard drafting teams be members of industry,” noting that the team that developed the geomagnetic disturbance standard included a NASA space scientist.

“I also wanted to point out that regional entities do in fact vote on standards,” she added, noting that the REs are one of 10 sectors represented on the Standards Committee. “That is why Guy and Steve are with us today,” she said, referring to committee members Guy Zito, assistant vice president of standards for the Northeast Power Coordinating Council, and Steve Rueckert, director of standards for the Western Electricity Coordinating Council.

Bodkin’s motion to remove the RE official from the candidate slate failed by a voice vote, and the committee ultimately approved the complete slate.

Bodkin and others prevailed, however, in their bid to block reconsideration of the committee’s vote in November to reject a consultant from Utility Services Inc. from a drafting team considering changes to PRC-005-6 (Project 2019-04). (See “Consultants Removed from SDT Nominee List,” NERC Standards Committee Briefs: Nov. 20, 2019.)

Standards Committee Chair Andrew Gallo said members may have voted based on “false information.” He said Bodkin incorrectly said the committee’s nominee selection criteria only allow consultants on SDTs if they bring technical expertise that no other team members have.

“The actual criteria is that the person be a subject matter expert … and clearly we think that this person meets that criterion,” Gallo said.

Gallo also said some smaller entities unable to assign their own staff to SDTs use consultants as a “proxy.”

“We thought we should try to be sensitive to the needs of these small entities,” he said.

Gugel confirmed that NERC had vetted the consultant and found him qualified to serve on the team.

Need to Review Criteria

The meeting ended with an agreement that the Standards Committee Process Subcommittee, which is chaired by Bodkin, will review the criteria for team membership.

“We seem to be revisiting criteria for standard drafting team appointments frequently,” said Jennifer Flandermeyer, director of federal regulatory policy for Evergy, who said the review would provide “opportunities for us to align thinking.”

“There’s a lot of things for us to balance and a lot of things to be considered,” she continued, citing the Standards Development Process Participant Conduct Policy, which prohibits participants from using the process for “commercial purposes … including, but not limited to, advertising or promoting a specific product or service.”

“We’ve had a lot of dialogue about what does ‘commercial benefit’ represent from the vendor/consultant community. How they benefit from that participation I think needs to be vetted out further. There are some really potential politically charged, tough conversations that we’ve got to have to make sure that we as the Standards Committee, working with NERC, get this right.”

Evidence Retention

The committee also endorsed the recommendations by a Standards Efficiency Review sub-team to reduce NERC’s evidence-retention schemes to five from more than 50. An earlier draft of the recommendations had suggested eight schemes. (See “Evidence Retention Report Posted for Comment,” Standards Committee Briefs: Aug. 21, 2019.)

Susan Morris, of the FERC Office of Electric Reliability (OER), asked whether the team had considered evidence-retention requirements of other regulatory bodies, such as the Securities and Exchange Commission.

Michael Puscas of ISO-NE said the team did not look. “The rationale for that was this is something that is directly related to the NERC standards and that looking at evidence retention outside of the NERC standards world didn’t seem to apply. It was apples to oranges in our estimation.”

Morris also said OER preferred NERC require the retention of evidence for the full period between audits.

Puscas said only some of the schemes would require such retention periods. “When you get into the rolling evidence-retention schemes, that would not apply because some audits are greater than a 36-month period,” he said.

“If you’re a generation owner or generator operator, you may have to keep it for six or seven years or longer” under such a requirement, said Gallo, of Austin Energy. “The idea that you would have to keep it back to the last audit is crazy. That’s me, not Austin Energy, talking.”

It was the last meeting for Gallo as chair of the committee. He will be replaced by Amy Casuscelli of Xcel Energy.

Other Actions

In other action, the committee:

approved the committee’s 2020-2022 Strategic Work Plan;
endorsed its 2019 Annual Accomplishments;
authorized the posting of proposed reliability standards CIP-004-7 and CIP-011-3 to clarify the requirements related to managing access to and securing bulk electric system (BES) cyber system information (Project 2019-02);
accepted modifications to the SAR for PER-003-2 (Project 2019-05);
appointed Dean LaForest of ISO-NE as chair of the SDT to revise the requirements for determining and communicating system operating limits (Project 2015-09); and
approved a correction of a typographical error in proposed reliability standard BAL-003-2 on frequency response requirements (Project 2017-01).