ERCOT said Friday it has approved the retirement of Public Service Company of Oklahoma’s coal-fired Oklaunion Power Station in the Texas Panhandle.
The Texas grid operator said staff have completed a reliability analysis and determined that the plant is not required to support transmission system reliability. The ruling clears the way for Oklaunion to be decommissioned and permanently retired as of Oct. 1.
Oklaunion Power Station | AEP
The 34-year-old, 650-MW plant’s ownership is split among utilities in both the ERCOT and SPP grids. AEP Texas owns a 54.69% interest in the plant. The other owners are the Brownsville Public Utilities Board (17.97%) in South Texas, PSO (15.62%) and the Oklahoma Municipal Power Authority (11.72%).
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. (The Members Committee will also be meeting but has no voting items scheduled.)
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
C. Manual 40: Training and Certification Requirements: Revisions resulting from cover-to-cover periodic review; includes updated temporary waiver language to allow more flexibility in addressing compliance with training and certification requirements.
1. Fuel Cost Policy (9:15-9:35)
The MRC will consider two different fuel-cost policy packages endorsed by the Market Implementation Committee in December. (See “Fuel-cost Policies,” PJM MIC Briefs: Dec. 11, 2019.)
The first package, compiled by a group of stakeholders, won 87% support and will be voted on as the main motion. The plan reduces penalties when a market seller self-identifies violations of its FCP and provides a “safe harbor” for force majeure scenarios and other situations of noncompliance that weren’t contemplated by the policy. The plan would also expand the use of temporary FCPs.
The PJM Industrial Customer Coalition and Calpine offered revisions to the first package that they said would address the RTO’s concerns about language applying penalties and duplicating benefits. The revisions clarify that the full penalty would be imposed if a unit is marginal in the day-ahead or real-time markets with a cost-based offer. A unit committed on its price-based schedule that later fails the three-pivotal-supplier test during its minimum run time or hours of its day-ahead commitment would also not incur the full impact factor unless the other conditions for market impact were met. About 81% of the committee endorsed this proposal.
Texas regulators last week approved a stipulated settlement of a CenterPoint Energy rate case that was a little more than 8% of the utility’s original request (49421).
The Public Utility Commission showed CenterPoint little love during its open meeting Friday, signing off on a $13 million settlement. The Houston utility had requested a $161 million recovery in April 2019, saying it had increased its customer base by 20%, installed 2.5 million smart meters and invested $6 billion in facilities since January 2010.
Left to right: Texas PUC Commissioners Shelly Botkin, Chair DeAnn Walker and Arthur D’Andrea discuss CenterPoint Energy’s rate case.
The agreement also reduces CenterPoint’s return on equity from 10% to 9.4%. It had asked for 10.4%.
CenterPoint filed the proposed settlement agreement in January. Parties included PUC staff; the Office of Public Utility Counsel; the city of Houston and other city coalitions; Texas Industrial Energy Consumers; Alliance for Retail Markets; Texas Energy Association for Marketers; and Texas Competitive Power Advocates.
The PUC also approved a rate-case-expense rider for Entergy Texas, allowing the utility to recover $6.4 million (48439).
The commission approved two settlement agreements resulting in $775,000 in administrative penalties:
EDF Energy Services was docked $475,000 for failing to reserve sufficient capacity to meet its responsive reserve service obligations (50304).
Oncor was penalized $300,000 over annual service quality (50350).
MISO last week released a set of draft future scenarios that would reflect in its transmission planning process the increasingly dominant role clean energy resources will likely play within the footprint as Midwest states push to decarbonize and electrify vital parts of their economies.
The RTO will use more aggressive renewable generation projections beginning with its 2021 transmission planning cycle (MTEP 21). Late last year, it released three draft 20-year futures — Announced Plans, Accelerated Fleet Change and Advanced Electrification — that take into account utilities’ decarbonization plans, the push toward renewable generation and increasing electrification in the footprint, respectively.
In December, some stakeholders questioned whether the proposed futures went far enough in terms of renewable projections. (See Stakeholders Debate MISO Planning Futures.)
At a special workshop Thursday, MISO revealed an updated strawman proposal, assigning the futures more neutral Roman numerals instead of titles.
Future I — formerly Announced Plans — assumes an 85% probability that companies’ renewable growth and carbon-cutting goals will materialize and full certainty that states’ clean energy plans will come to pass. It also includes a nearly 35% renewable generation penetration and a 40% reduction in carbon emissions from 2005 levels by 2040.
“This is hedging the possibility that some of these plans are vague and may not come to fruition,” MISO Planning Manager Tony Hunziker said.
Future II — previously Accelerated Fleet Change — assumes MISO members meet or exceed decarbonization plans while carbon emissions drop 60% from 2005 levels. Electric vehicle adoption stimulates demand, while residential and commercial electrification reaches 39% of its technical potential.
Future III — Advanced Electrification — also assumes members fulfill their renewable plans and consumers adopt EVs. It foresees a sharp increase in demand because of electrification and residential and commercial electrification hitting 77% of its technical potential. MISO also experiences a minimum 50% renewable penetration level as carbon emissions dip 80% below 2005 levels.
MISO said the proposed MTEP 21 futures show “significant evolution” from those of MTEP 19, where renewable penetration topped out at about 36% of the resource mix by 2035 in the most aggressive future.
The RTO wants to have the new futures finalized by July.
Carbon emission modeling assumptions by future | MISO
Hunziker said MISO’s Board of Directors is “very interested” in moving ahead on the futures redesign in light of the RTO’s rapidly changing resource mix and recently filed integrated resource plans at state commissions.
“It’s still very much a draft,” Hunziker told stakeholders. “We’re pouring the concrete, but it hasn’t set yet, so we can still form it, push it around before it is set in stone.”
The futures will go before the Planning Advisory Committee at its March 11 meeting, where stakeholders will have another opportunity to suggest alterations.
‘Choking Point’
Some stakeholders asked how flexible the concrete will be when dried, asking if MISO was leaving room in its planning scenarios to include even more fleet transition. They said the RTO seems to be at an inflection point of utilities and states announcing stepped-up carbon-cutting measures.
Hunziker said MISO is introducing a survey tool as part of the futures’ analysis to continue to solicit companies’ announced plans along with state mandates and goals.
He also said the RTO is partnering with the Organization of MISO States to get commissions’ most up-to-date decisions on their utilities’ resource additions and retirements. The idea is to get a single repository of commissions’ decisions instead of MISO “minding the vast, expansive infowebs,” he said.
Mississippi Public Service Commission consultant Nick Puga asked if MISO has vetted the futures’ electrification predictions with outside consultants.
Hunziker said MISO’s electrification projections are based on internal research and data from outside consultants, including Applied Energy Group.
“If the Super Bowl ads were any indication, it looks like there will be a lot of electric vehicles … potentially in the next year,” Hunziker said.
Multiple stakeholders asked MISO to schedule a special workshop with stakeholders to describe the RTO’s approach to its electrification projections. Hunziker said MISO will consider the request.
Veriquest Group’s David Harlan asked that MISO provide stakeholders with each future’s projected subregional energy mix, capacity supply broken down by fuel type and load shapes. He argued that if the futures are intended to drive transmission investment decisions, members should have a better idea of which generation sources will be matched up with load on the subregional level.
Minnesota Public Utilities Commission staff member Hwikwon Ham reminded stakeholders that MISO is planning for new transmission, not trying to pinpoint exact locations of future generation.
“We don’t need to project where resources will be precisely available,” Ham said, adding that the system has recently become a “choking point” in getting new resources built and interconnected.
NEW ORLEANS — Could this be the year SPP and MISO finally agree on an interregional transmission project?
Maybe. At least that’s what staff responsible for planning at the RTOs’ seam implied last week during a panel discussion at the Gulf Coast Power Association’s 7th annual MISO South Conference on Feb. 11.
An optimistic Casey Cathey, SPP’s manager of transmission planning and seams, assured a questioner that the grid operators will produce a coordinated system plan (CSP) this year. Two previous attempts have failed to yield an interregional project the organizations could agree on.
“We’re in heavy coordination and very close to coming up with some projects,” Cathey said. “For the first time in I don’t know how many years, we’ve got a good shot of getting a project through [the CSP].”
SPP’s desire for interregional projects has been driven by a wish to relieve congestion in eastern Kansas, which borders the MISO footprint. The growing impetus for MISO is the north-south transfer constraint between its Midwest and South regions.
As a result of a 2015 settlement agreement between the RTOs that also involves other parties, MISO is limited to 1,000 MW of contracted, firm transmission capacity between the two regions through SPP’s system, but it also has access to additional non-firm service capped at 3,000 MW in southbound flows and 2,500 MW northbound. (See SPP, MISO Reach Deal to End Transmission Dispute.)
Under the agreement, MISO pays SPP between $16 million and $38 million in base annual payments based on an annual available system capacity-usage factor. In February, that arrangement became subject to a 2 to 4% escalation rate. The limits also created problems during energy emergency alerts (EEAs) in 2018 and 2019, when MISO said the constraint prevented it from accessing resources to relieve the emergency.
With the agreement set to expire in February 2021, MISO is motivated to bring “operational certainty” to its members through new transmission projects or by purchasing additional firm capacity. (See MISO Floats New Option for Midwest-South Constraint.)
“One of our objectives is to get to the point of long-term regional certainty,” said Jeremiah Doner, director of seams coordination for MISO.
“There will be another EEA event, with possible load shed,” Cooperative Energy COO Nathan Brown warned. “We really need some focus there.”
SPP could also be looking at its first international interregional project, Cathey said. The RTO shares a direct tie with Canada’s SaskPower through Basin Electric Power Cooperative’s existing transmission facilities in North Dakota and completed its first international transaction in 2015 when it imported power during an emergency situation. (See SPP, SaskPower Make First International Trade.)
A provision in SPP’s joint operating agreement with SaskPower allows joint planning analysis and coordinated system planning. With the oil-rich province of Saskatchewan facing continued load growth, SaskPower and SPP have held preliminary discussions.
“[SaskPower] can help fund projects in SPP and therefore improve their import capability,” Cathey said. “There are just so many things going on.”
Electric Industry Outpacing Others in Cybersecurity
SPP Director Mark Crisson opened a special briefing workshop GCPA held on the RTO by noting the growing importance of cybersecurity in the electric industry.
“Twelve years ago, this wasn’t on anyone’s radar,” he said. He recalled that when he became CEO of the American Public Power Association in 2007, he would receive “private, confidential” briefings from the Department of Homeland Security on industry cyber threats that were not to be shared with anyone else.
“It’s much more of an industry dialogue with the government now,” he said. “The nature of these threats evolve all the time. It’s hard to stay ahead of the bad guys, but it’s critical for our industry. We are way ahead of what other industries are doing, both with the steps we’re taking, the information we’re getting from the government, and the teamwork between us and the government.”
Crisson said SPP has developed its own set of cybersecurity criteria “that allows [us] to evaluate how effective or robust our cybersecurity really is.”
SPP currently scores itself above average, or between three and four on a five-point scale, Crisson said.
“We feel like we’re making good progress, but there’s a lot more to do here.”
Uncertainty Product a Key for SPP Reliability
The workshop mostly focused on the SPP Holistic Integrated Tariff Team’s work to integrate the growth of renewable energy, boost reliability, and improve transmission planning and the wholesale market. (See SPP Board Approves HITT’s Recommendations.)
Bill Grant, regional vice president of regulatory and strategic planning for Xcel Energy’s Southwestern Public Service, joined a panel of SPP members in explaining the HITT’s recommendation to develop an uncertainty product as “the art of dispatching.”
“We can handle the system a little differently if we have certainty,” said Grant, a former control center manager. “We have to develop tools for operators so they can react when there are any questions about the [generation] forecast.”
The HITT listed the uncertainty product as an “other reliability service,” which include new technologies that change the “underlying nature of grid operations that are not traditional operator tools.”
Grant pointed out that SPP’s market protocols and rules limit the flexibility dispatchers have to work with. However, the flexibility, or uncertainty product, is also needed as variable renewable generation takes a larger share of the fuel mix.
“Developing the uncertainty model will help us better learn about the market,” said Nebraska Public Power District’s Tom Kent, who chaired the HITT.
MISO saved members between $3.2 billion and $4 billion over the course of 2019, the RTO said last week.
The savings could be attributed to “enhanced reliability, more efficient use of the region’s existing assets and a reduced need for new assets,” MISO said in its annual Value Proposition study, which compares benefits of RTO membership against going it alone on the grid.
The estimated value to members was partially offset by $296 million in MISO administrative costs.
The savings are nearly identical to 2018, when MISO estimated it delivered between $3.2 billion and $3.9 billion in benefits to members. (See MISO Claims up to $3.9B in 2018 Benefits.) The RTO said it has documented nearly $27 billion in member benefits since 2009.
MISO executives discussed the most recent customer savings estimates during a special conference call Friday.
“Value Proposition on Valentine’s Day. Nothing could be more appropriate,” Executive Director of Market Operations Shawn McFarlane had joked at the Market Subcommittee meeting Feb. 6.
Breakdown of 2019 Value Proposition study | MISO
MISO said the lion’s share of last year’s value — $3.1 billion — could be chalked up to a diminished need for more grid assets. Those savings were further broken down to $415 million to $477 million from MISO’s wind generation integration, $154 million to $261 million from its demand response program and $2.2 billion to $2.7 billion from its vast geographic footprint.
Improved reliability accounted for a $405 million in savings, while a more efficient use of the footprint’s existing assets accounted for another $374 million, consisting of savings from more efficient dispatch ($283 million to $313 million), regulation reserves ($49 million to $54 million) and spinning reserves ($23 million to $25 million).
“The benefit of our large footprint is peaks occur at different times,” said Leonard Ashley, MISO senior business adviser of strategy and business development, adding that hot weather doesn’t often occur simultaneously in Indiana and the Dakotas, allowing the RTO to more easily distribute supply.
In its annual report, NERC cast 2019 as a “true pivot point” for the ERO Enterprise, thanks to initiatives aimed at improving the effectiveness of the organization and sharpening its focus on emerging challenges.
Consolidations Boost Efficiency, Engagement
The report highlighted several moves to reorganize the operation of the ERO Enterprise, with the transition of the Western Interconnection to multiple reliability coordinators singled out as “a significant accomplishment for all new RCs, their customers … and the grid.” The dissolution of Peak Reliability in December 2019 capped an 18-month process that saw the former RC hand over its functions to West’s RC Transition Earns Plaudits.)
NERC also held up SERC Reliability’s takeover of the Florida Reliability Coordinating Council in July as an example of effective integration to improve grid reliability. (See SERC Rethinking Board After FRCC Integration.) NERC applauded SERC’s “dedication to working together with affected registered entities … resulting in a stronger, more reliable and more efficient region.”
High-level organizational changes were featured as well, including formation of the ERO Enterprise Executive Committee. NERC CEO Jim Robb said the committee, comprising the ERO’s senior leadership team and the CEOs of the regional entities, can “symbolize and operationalize” the organization’s commitment to respecting the independence of REs while working together toward a “common mission of assuring a reliable and secure bulk power system.”
NERC also touted the formation of the Stakeholder Engagement Team in May, which set in motion the creation of the new Reliability and Security Technical Committee (RSTC) to replace several existing bodies. (See Three NERC Committees Likely to Merge.)
Emerging Risks Highlighted
The organization’s work raising awareness of new risks garnered attention too, with its efforts divided into four key areas: grid transformation, extreme natural events, security risks and critical infrastructure interdependencies.
Security was the highlight of some of NERC’s biggest events in 2019. The most obvious example was the GridEx V security exercise in November, which featured the participation of more than 7,000 security professionals from nearly 530 industry and government organizations, 29 FBI field offices and 26 state governments. (See GridEx V Throws New Tech Curveball.) October’s GridSecCon 2019 provided opportunities for physical and cybersecurity experts to share knowledge on drones, insider threats, supply chain risks and a range of other topics. (See Overheard at GridSecCon 2019.)
Less visible, but equally important, was NERC’s behind-the-scenes work creating a base for knowledge-sharing and cooperation by players in the ERO Enterprise and industry. The Electricity Information Sharing and Analysis Center (E-ISAC) notched several key milestones last year, with the appointment of new CEO Manny Cancel and new information-sharing agreements with the natural gas, oil and water sectors, as well as state and local governments. (See Former Con Ed Exec to Lead E-ISAC.)
The organization also made progress in updating its reliability standards to address supply chain security risks, along with creating plans for recovery from an electromagnetic pulse attack. Task forces focused on each of these areas saw NERC’s Board of Trustees adopt their recommendations at its most recent meeting. (See “EMP, Supply Chain Recommendations Approved,” NERC Board of Trustees Briefs: Feb. 6, 2020.)
“NERC’s mission to enhance the reliability and resilience of the North American grid requires constant vigilance in the face of dramatic industry change and the emergence of new threats by bad actors,” board Chair Roy Thilly said. “I am pleased to report that NERC, together with industry and the regions, continues to be successful in meeting this important responsibility.”
NERC has finished transitioning to the latest version of its situational awareness tool and plans to introduce it to reliability coordinators once the vendor developing the system has implemented new modeling software, the vendor’s CEO told the ERO’s Operating Reliability Subcommittee on Feb. 11.
Additional features being added to the tool include separate views for RCs, FERC and the ERO Enterprise, along with advanced data visualization tools incorporating a range of information such as substation performance, space weather, gas pipeline availability and fire tracking.
“We’re building a process that will allow you, the RCs, at very little manual work other than review, to continue to push updated model information into SAFNR v.3,” Legatt said. “Therefore, the impact to the RCs will be lower, and the accuracy of the tool will go up significantly.”
SAFNR v.3 went live for NERC and the ERO Enterprise in December 2019. Darrell Moore of NERC said that the tool will be rolled out to remaining stakeholders after ResilientGrid finishes building models with updated information from the RCs.
Clarity Sought on IROL Exceedance Metric
The task force revising the metric for identification of interconnection reliability operating limits (IROLs) brought two recommendations to the subcommittee for feedback: to ensure consistency in reporting by requiring operators to report all IROL exceedances with no operating margin added, and to change the threshold for reporting from 10 seconds to one minute.
“As the ORS is kind of our [forum] to talk to subject matter experts, we want your feedback on the proposed changes — should we start taking the steps to make this modification so that we can have a better, more valuable metric?” asked Maggie Peacock, manager of advanced analytics at SERC Reliability and chair of NERC’s Performance Analysis Subcommittee.
Several members of the subcommittee urged the task force to address what they saw as a lack of clarity in the recommendations. In particular, John Norden, director of operations at ISO-NE, said the metric should be clear as to whether it includes any buffer an operator has built into its system.
“It probably should be consistent, because the last thing we want to do is give doubt to an operator,” Norden said. “[If] you have a 1,000-MW transfer limit as your limit, and the operator gets to 28 minutes and he’s at 1,050, should he take action to get below 1,000 in the [last] two minutes, or should he say I have a buffer? … The limit’s the limit, as far as I’m concerned, and that’s what you should operate to, whatever you put in front of the operator.”
Members Object to RCIS 2021 Development
The group developing the successor to the Reliability Coordinator Information System (RCIS) is currently working on a request for proposals. It hopes to choose a vendor by the second quarter and introduce the tool by early next year.
Creation of the new software, called RCIS 2021, is being conducted by the Eastern Interconnect Data Sharing Network (EIDSN), a group created in 2014 to further develop industry tools that NERC has decided it no longer wants to maintain. NERC initiated the project in 2017 to replace the current RCIS with a more modern architecture and provide a common platform for instant communication between RCs, as well as between RCs, NERC, and transmission owners and operators.
Some at the meeting raised strong concerns about a perceived lack of input from Western operators into the system, as EIDSN is composed of representatives from the Eastern and Quebec interconnections. These were amplified when EIDSN Executive Director Jim Schinski said that use of RCIS 2021, which is required by several NERC standards, will be subject to a fee paid to EIDSN.
“Speaking for my company, and I think for others, we’re going to have some strong objections to that,” said Tim Beach, director of reliability coordination at RC West. “Because you’re [requiring] us to participate … and pay, with no control over requirements or cost in the future.
“I understand the tool needs to be replaced. Full agreement with that. … But the process of getting there and the requirement to use it seems a little upside-down to us in the West,” he added. [Editor’s Note: A previous version of this article mistakenly attributed this quote to Tim Reynolds, manager of event analysis and situation awareness for the Western Electricity Coordinating Council.]
Richard Mandes of EIDSN told members that “they’re paying for that functionality today through NERC” and that the fee paid to EIDSN would cover the same services they are getting now. He also promised that members would have an opportunity to provide input into the design of the system through NERC before it is introduced.
Electric vehicle makers are now offering 90 models for sale in the U.S., and the nation’s charging infrastructure grew by 17% last year, according to data released last week by BloombergNEF.
Yet U.S. EV sales dropped 11% in 2019, accounting for just 1.8% of total vehicle sales, Bloomberg reported.
Nevertheless, state regulators said during a panel discussion at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit last week they remain upbeat about the potential for vehicle electrification to help decarbonization efforts — and maybe reduce system costs.
The number of public and workplace EV charging points rose 17% to 71,000 in 2019. Through 2018, about one-third of the EV chargers were in California. Most EV charging, however, is done at home. | BloombergNEF
“This is a really exciting time to talk about EVs,” said Al Freeman, an adviser for the Michigan Public Service Commission, who keeps a very busy Google alert to keep track of industry developments.
Michigan’s utilities have made “some really neat [pilot] proposals” to the commission, he said, including $13 million, three-year pilots by both Consumers Energy and DTE Energy, which were approved by the commission last year.
“There’s a lot of challenges, but they’re responding to it very well and being aggressive in the marketing and the education of it,” he said of Consumers. DTE has been similarly aggressive, he said. “A lot of their costs have come in below what they estimated, which will allow them to have a little bit more money for additional rebates.”
U.S. sales of electric vehicles dropped 11% in 2019, with battery electric vehicle (BEV) sales up 2% to 235,000 units while plug-in hybrid electric vehicle (PHEV) sales fell 36% to 76,000. Fuel cell vehicle (FCV) sales dropped 12% to 2,090 (too small to be visible on the chart). | BloombergNEF
2 Questions
Hanna Terwilliger, economic analyst for the Minnesota Public Utilities Commission, said EV growth is outpacing rooftop solar in her state, although enrolling owners in time-of-use rates remains a key challenge.
Terwilliger said Minnesota is seeking to integrate EVs in a way that benefits all customers and avoids adverse system impacts. It’s also considering whether it should encourage widespread adoption of EVs to meet policy goals, such as carbon reductions.
“Each state will have different answers to these questions, but we all need to … make sure we’re prepared because … even just one EV charging at a house can double their electric consumption, and they’re coming faster than other types of [distributed energy resources] like rooftop solar,” she said.
Americans have purchased or leased 1.4 million battery-electric and plug-in hybrid electric vehicles since 2010, according to BloombergNEF. Minnesota has about 10,000 EVs, most in its metro areas but with some penetration in rural areas as well.
But while the Dakota Electric Association has almost half of their EVs enrolled in TOU or off-peak rates, Minnesota Power, Otter Tail Power and Xcel Energy have struggled to get participation above 10%. Terwilliger said a big challenge is the expense of installing a second TOU meter.
Asked to explain the disparity, Terwilliger noted that Dakota is an electric cooperative. “Anecdotally, from other co-ops that have similar rates, they’re also around 50%,” she said.
“There’s a number of reasons why co-ops have been more successful. They historically have had a lot more demand-response programs, and they’ve been able to expand those programs to include EVs. So, a lot of the infrastructure is already there. It’s less expensive to enroll customers in the rate. I think that co-ops also have a lot more direct communication with their members. Members want to read the newsletters that come out, versus if you’re trying to [communicate] something on a bill insert, there’s a lot of times people just throw it away.” Some customers get electronic bills and don’t receive bill inserts, she added.
U.S. sales of conventional hybrid electric vehicles (HEVs) such as the Toyota Prius rose 10% to 373,000 units in 2019. Conventional hybrids can only recharge their battery through regenerative braking. | BloombergNEF
She said utilities must enroll EV drivers in some type of managed charging rate when they purchase their cars. “Even if it’s not perfect, it’s much easier to switch a customer to more sophisticated program than it is to try and go and find them” after the sale.
It’s also important to have the rate structure ready to accommodate and encourage fleets switching to EVs, she said, noting Amazon’s plan to purchase 100,000 EV delivery vans, reportedly the largest EV order ever. “When they start coming into your service territory, Amazon does not want to wait for you to go through a regulatory process. They want a good solution there right now that’s going to save them money.”
Tim Echols, vice chair of the Georgia Public Service Commission, lamented that his state in 2015 abolished the $5,000 tax credit that had made it one of the early leaders in EV growth. He said the credit died because messaging about EVs’ environmental benefits took “all the oxygen in the … room.”
“I’m on my fourth EV. I’m a big proponent. But we’re making a switch [in messaging]. We have five Republican commissioners. Every constitutional officer in Georgia is a Republican. And we’re beginning to talk about how EVs charged at home overnight put downward pressure on rates. That’s the new red state message. Nothing else about the environment, because our left-leaning friends are going to come with us no matter what. … It’s the Republicans that are holding us up on this.”
NYISO can import 505 MW above grandfathered rights from its neighboring control areas for capability year 2020/21, with 332 MW available from ISO-NE and 152 MW from PJM, under the revised installed capacity (ICAP) values approved by the Business Issues Committee on Wednesday. Quebec and Ontario can add another 21 MW.
Including existing transmission capacity for native load, and other grandfathered rights, the ISO’s biggest import sources are PJM (1,232 MW) and Quebec (1,116 MW).
The individual limits allowed under the ISO’s MARS simulations were prorated to ensure they do not violate the loss-of-load expectation criterion. All of the resulting imports were deemed deliverable, said Frank Ciani, of NYISO’s capacity market operations unit.
NYISO can import 505 MW above grandfathered rights from its neighboring control areas for capability year 2020/21, with 332 MW available from ISO-NE and 152 MW from PJM. The grandfathered rights include existing transmission capacity for native load. | NYISO
The analysis excluded interface facilities with unforced capacity deliverability rights, controllable lines from PJM into the New York Control Area and the Northeast Utilities Service Co. 1385 line.
The BIC approved a motion to update Section 4.9.6 of the Installed Capacity Manual to reflect the results without opposition or discussion during the brief meeting.
The revised limits represent an increase of 62 MW over 2019/20, with PJM’s limit increased by 120 MW and Ontario’s reduced by 113 MW. The summer capability period strip auction opens March 30.
Transmission Congestion Contracts
In its only other action, the BIC approved revisions to the Transmission Congestion Contracts Manual, which was last updated in 2017.
The revisions add the historic fixed-price transmission congestion contracts extension product and incorporate technical bulletins on the PJM-NYISO interconnection scheduling protocol and modeling of the Rainey and Blissville phase-angle regulators.
