FERC last week urged the Federal Communications Commission to conduct additional testing to ensure automated frequency coordination (AFC) will protect utilities’ use of the 6 GHz spectrum band, which the FCC is considering opening to unlicensed users.
In a letter to FCC Chair Ajit Pai, the commission noted the concerns of electric utilities, which use the spectrum (5,925 to 7,125 MHz) for point-to-point microwave links providing communications with substations, fault sensors, two-way meters and service crews. It is also used to provide situational awareness in rural areas where wireline networks are not available.
In proposing the use of the spectrum by unlicensed users, FCC cited estimates that North American mobile traffic, including unlicensed Wi-Fi devices, grew 44% in 2016 and is projected to grow nearly 35% annually through 2021. AFC would use a “database lookup scheme” to ensure that unlicensed users are not encroaching on an existing user’s priority access to the frequency in a specific area.
“We ask that you consider the implications for electric reliability and closely review the rulemaking comments that discuss the potential impacts of the proposal on electric reliability,” the commissioners wrote. “Should the proposed rule be adopted, we strongly urge you to consider requests from electric utilities and state regulators for additional testing of the AFC system prior to implementation. We understand the complexity of assessing the cross-dependencies between areas of critical infrastructure and would be pleased to offer technical assistance through FERC staff if it would be helpful.”
FERC Commissioner Richard Glick warned that the commission’s recent order regarding Duke Energy’s accounting treatment of its cybersecurity program sends a signal that it will let utilities sidestep its rules when convenient.
The order issued Thursday allows Duke to treat its Cybersecurity Informational Technology-Operational Technology Program as a single project for the purposes of calculating FERC’s allowance for funds used during construction (AFUDC) (AC19-75).
FERC permits utilities to record debt- and equity-related financing costs for projects under development as AFUDC, which is combined with actual construction costs in order to establish rates once the project is completed and contributing to utility service and revenue.
Thursday’s change is significant because several components of Duke’s cybersecurity program, such as automated asset identification, are already completed and ready to enter service. Under normal rules, this would mean the entire program must be removed from AFUDC; however, Duke contended that this would be unfair, as these constituent assets cannot make any contribution to revenue by themselves without the rest of the program. Customers would hence be paying for programs that were not creating value for them.
The control room at Duke Energy’s Buck combined cycle plant in Rowan County, N.C. | Duke Energy
FERC sided with Duke, saying that the commission’s current policy allowed it to recognize that individual parts of a project can enter service without the entire program becoming viable. But Glick argued at FERC’s open meeting last week that the move would encourage other utilities to classify projects as under development when they are in fact ready for service, in hopes of accruing more AFUDC and inflating their investments in order to justify higher rates for consumers.
“If we’re going to change our policy, that’s one thing,” Glick said. “But if we’re going to say that we’re keeping our AFUDC policy, but on the other hand we’re going to ignore what’s in our AFUDC policy — which is very clear … that if some of the components are ready to be placed in service, you take it out of AFUDC right then — I’m really concerned about the precedent we’re setting here.”
Glick’s dissent echoed an objection filed by the North Carolina Electric Membership Corp. (NCEMC) in response to Duke’s request in March. NCEMC pointed out that while a constituent project might not be able to fulfill its intended purpose without the rest of the program in place, it might still provide a benefit to consumers. The company said Duke had not “provided sufficient information to identify whether any of the component parts of the cybersecurity program” would be able to provide such a benefit, and essentially wanted FERC to rely on its word.
FERC acknowledged that its “determination is based on Duke’s representations regarding its cybersecurity program” and pledged that it would review the project to ensure it remained compliant with AFUDC policy — a promise that Glick found unconvincing.
“To me that’s a little circular logic, because in this particular order, we’re saying it is consistent with our AFUDC policy,” Glick said. “So I’m not really sure we can go back and address this particular issue — I think the die is cast, essentially, once we vote out this order.”
Another dissenting voice came from the consumer advocacy group Public Citizen, which observed that NERC assessed a $10 million fine earlier this year on an unnamed utility, widely reported to be Duke, for 127 violations of cybersecurity standards. (See NERC Seeks $10M Fine for Duke Energy Security Lapses.) The group objected to the idea of ratepayers supporting a cybersecurity program that NERC considers likely to suffer further instances of noncompliance in the future.
Public Citizen also questioned whether the proposed accounting change was intended to help Duke recover the cost of the NERC fine and of addressing the security lapses. In response, Duke said the request was not meant for this purpose and that “the cost of the cybersecurity program, including any approved AFUDC, will be recovered through those formula rates, which have been previously approved by the commission.”
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.
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.”
| EDP Renewables
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.
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.
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.
Locations of NREL offshore wind sites and interconnection points used for preliminary results | ISO-NE
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.”
Production costs are lower in unconstrained cases because they utilize more zero-cost energy north of Surowiec-South. | ISO-NE
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.
“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.
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.”
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.
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.”
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.)
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 linemen at work | FirstEnergy
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.
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 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.”
| MISO
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.)
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.
Greater Boston area electrical distribution map | ISO-NE
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.”
Greater Boston area generating units over 100 MW | ISO-NE
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.
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.)
To enhance reliability performance metrics, NYISO has begun to measure daily and monthly net load forecast performance against 30-minute and hour-ahead forecast errors. | NYISO
“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.
