State regulators in SPP and MISO on Monday separately approved recommendations to engage the SPP Market Monitoring Unit and the MISO Independent Market Monitor to conduct a joint analysis on seams issues between the two grid operators.
| ACES
The SPP Regional State Committee, meeting by conference call, agreed unanimously with the RSC-Organization of MISO States Seams Liaison Committee’s recommendation to work with the Monitors. The MMU and IMM brought a scoping plan to the Liaison Committee earlier in May, offering to identify and study seams issues, quantifying costs and benefits of proposed solutions when possible.
The recommendation directs the Monitors to immediately begin a Tier I study of market-to-market coordination, rate pancaking and joint dispatch.
A Tier II study following the completion of Tier I would focus on interface pricing, interchange optimization and regional directional transfer limits.
Both studies are to be completed by June 2020.
Tier III will serve as a parking lot for several other issues: exchanging firm flow entitlements in M2M transactions, targeted market efficiency projects, and outage and day-ahead coordination.
Kansas Corporation Commissioner Shari Feist Albrecht, who represents the RSC on the Liaison Committee, said stakeholder comments on potential study subjects centered on rate pancaking and joint dispatch.
“We decided that might be a significant issue from a state perspective,” Albrecht said. “We’re just trying to get some ballpark numbers to identify potential savings.”
Albrecht hopes the Monitors can finish their Tier I work in “six months or so,” then move on to Tier II.
The MMU’s Greg Sorenson addressed RSC concerns that the study would add incremental costs, saying the Monitor’s goal is to conduct four independent market studies each year; the RSC/OMS analysis would serve as one of those four studies.
The OMS Board of Directors also voted overwhelmingly to approve the Monitors’ joint study Monday in an email ballot, with 14 members in favor, one abstention and two non-participants, Executive Director Marcus Hawkins confirmed.
“Since both boards have approved the scope and prioritization, the monitors will now start to develop their work plans on the first phase of the study,” Hawkins said in an email to RTO Insider.
MISO stakeholders at a June 4 Seams Management Working Group conference call asked why the study was being conducted by the Monitors rather than RTO staff.
“We were looking for some independent analysis,” Missouri Public Service Commission economist Adam McKinnie explained.
The Liaison Committee has been meeting since mid-2018 to help improve the grid operators’ interregional coordination, which has never produced a major project. (See MISO, SPP to Ease Interregional Project Criteria.) That has frustrated some stakeholders and caused market inefficiencies.
Committee members will meet July 21 at the National Association of Regulatory Utility Commissioners’ summer policy summit in Indianapolis. The committee has invited FERC commissioners and staff to attend.
HARTFORD, Conn. — New England regulators are struggling to deal with how rapidly public policy is transforming the region’s wholesale electricity markets, state officials said Monday at the New England Conference of Public Utilities Commissioners’ (NECPUC) 72nd annual symposium.
As if to drive home the point about the pace of change, Connecticut Gov. Ned Lamont alerted the conference that his state would expand its offshore wind commitment more than six-fold.
“We had a 300-MW commitment, and our legislature, virtually as we speak, is going to up that commitment to 2,000 MW … over the next five to seven years,” Lamont said. (Two OSW bills — Senate Bill 975 and House Bill 7195 — were on Monday’s Senate agenda.) He was speaking just days after the Massachusetts Department of Energy Resources issued a report calling for that state to solicit an additional 1,600 MW on top of an existing 1,600-MW procurement.
“We’re doing the right thing to make sure we have a carbon-free future and a reliable, predictable energy source that allows our region to continue to grow and prosper,” Lamont said.
The governor said he had faced an energy crisis shortly after being elected last November.
“I got a call from [Department of Energy and Environmental Protection Commissioner] Katie Dykes, who said we may have an issue with Millstone, the nuclear power plant that supplies 50% of our electricity,” Lamont said, referring to Dominion Energy’s threat to shut down the 2,111-MW plant, claiming it was no longer financially viable.
In December, Millstone was thrown a lifeline as one of the winning bidders in a state solicitation for nearly 12 million MWh of zero-carbon energy, securing purchase of about half its output for 10 years. (See Conn. Zero-Carbon Awards Include Nukes, OSW, Solar.)
“We solved that Millstone problem … and I’m going to make sure that no governor gets stuck again in the same situation I was,” Lamont said.
Market Disconnect
Restructuring of the electricity industry was meant to shift risks from ratepayers to the market players who stood to profit from their investments, said Sharon Reishus, president of Reishus Consulting and former chair of the Maine Public Utilities Commission.
“There was not an explicit design of the wholesale markets to address state environmental goals. There was an assumption that you would not harm environmental goals,” Reishus said.
In moderating a panel on markets, Reishus asked: “How do state energy procurements keep from shifting risks back to consumers, and what are the risks of unintended consequences?” She added that the regional wholesale market may not survive if states continue to pursue their own separate goals.
New England has seen a disconnect between the roles of state policymaking and the design of the markets, said Vermont Department of Public Service Commissioner June Tierney.
“There’s this tension in the market design between affording the states the proper” authority to pursue environmental goals and the mission of the grid operator to secure reliable energy at the lowest cost possible, Tierney said.
“The market exists to serve the needs of six sovereign states … which push much more in the same direction than in contrary ones,” she said. “It’s about using American ingenuity to … meet a basic need our citizens have, which is the need for electricity.
“When we were struggling with CASPR [Competitive Auctions with Sponsored Policy Resources] … the bottom line of that issue was that ISO-NE was engaged in tweaking market design,” Tierney said.
Commissioner Richard Glick’s dissent caught her attention, she said. Glick contended that FERC had misinterpreted the Federal Power Act, failing to respect “that states, not the commission, are the entities primarily responsible for shaping the generation mix.”
“It isn’t FERC’s job to interpret the Federal Power Act as if the states didn’t have legitimate interests in propagating laws that effectuate renewable energy policy,” Tierney said.
Answering Reishus’ question about unintended consequences, Maine PUC Commissioner R. Bruce Williamson said, “In Maine, it’s a constant battle. We have to remind, even to unwilling ears, that there are cost implications to some of the great ideas.”
The region sees the benefit of retaining existing carbon-free resources in the market, but there is a misperception that state procurements of energy drive prices higher, Massachusetts Department of Public Utilities Chairman Matthew Nelson said.
“Out-of-market contracts get seen as the bogeymen here, but the most recent one occurred in Massachusetts and actually saw real reductions to ratepayers,” Nelson said. “We live in a complicated market, and ISO-NE is doing its best … but there’s no going back to a vertically integrated electricity market.”
“Folks start realizing they are paying for a renewable project in their bills, but [they] don’t understand the benefits,” said Nicholas Ucci, deputy commissioner of energy with the Rhode Island Office of Energy Resources.
“No system is perfect, especially one that is two decades old,” Ucci said. “This is a work in progress.”
DEEP Commissioner Dykes said Connecticut has “gone from a minimal percentage of our load contracted to … close to 100%.”
“The contracting will only go so far,” Dykes said. “We have to assume that states are going to continue pursuing their environmental goals. The real question is: Are we going to do so in a coordinated way?”
New Hampshire Public Utilities Commissioner Kathryn Bailey noted that in 1996, her state was the first in the country to pilot restructuring utilities.
“Customers now have the ability to purchase their energy through competitive suppliers,” Bailey said, adding that the emphasis on least-cost generation resulted in an overreliance on natural gas.
Now, as regulators and ISO-NE work to both mold and adapt to a new resource mix, “utility-scale storage will be the answer to the prayer that we have today, and we’ll be able to balance the reliability with the long-term contracts that continue to be negotiated,” Bailey said.
“Having storage is really flexible and it’s probably going to be the answer … when we still need flexible resources, but 50% of the demand is powered by long-term contracts,” Bailey said.
An American Transmission Co. effort to improve reliability in central Wisconsin could within two years provide MISO with its first-ever storage-as-transmission asset (SATA) project.
ATC is proposing to build a 2.5-MW/5-MWh battery on a 138-kV line in the Waupaca, Wis., area, installing two capacitors and upgrading a nearby 69-kV bus to accommodate the project. The project would cost an estimated $9.1 million and be in service at the end of 2021. ATC said the battery would be available for two-hour discharge times.
The company is proposing the project for inclusion in MISO’s 2019 Transmission Expansion Plan (MTEP 19) to function as strictly transmission. MISO is so far prohibiting SATA projects from also providing market services. (See MISO Limits Storage as Transmission Asset Ownership.)
During a West subregional planning meeting Friday, MISO staff said the project still requires study, including determining how it could impact load service risks and system reliability. The RTO said it will present final project justification results at another subregional planning meeting on Aug. 23.
The company has also submitted two alternatives — another battery farther north and a traditional wires solution — in the event that MISO finds negative impacts from the originally submitted battery format. The 5-MW/10-MWh alternate battery project would cost $10.4 million, and a rebuild of the Whiting Avenue-Hoover 115-kV would cost $12.4 million. Both would stick to a late 2021 timeline.
ATC said its preferred battery project is designed to more reliably maintain up to a 155-MW load level, capturing more than 90% of historical load levels in the Waupaca area. The area is currently at risk during multiple outage conditions, MISO expansion planner James Slegers said.
“At certain load levels, the system cannot sustain the load,” Slegers said.
Waupaca contains a local 69-kV system supported by a nearby multi-segment 115/138-kV transmission line. MISO said local loads cannot be sustained when both ends of the 115/138-kV supply line are out of service. ATC currently uses an operating guide to open line segments to serve load radially on the 69-kV system after load levels reach a certain point and after a first outage. While the operating guide allows loads to be served after a second contingency, it places up to 114 MW of load at risk of disconnection, according to MISO. ATC’s battery is designed to operate after a second contingency.
“There are not many hours in a year that you could take a maintenance outage and not sectionalize the system,” Slegers said, adding the solution aims to allow multiple maintenance outages without a loss-of-load risk.
MISO has completed a reliability assessment on the battery project. So far, it found the most effective siting of a SATA solution is near the Harrison 69-kV substation in the area, although other nearby 138-kV buses between Arnott and Waupaca “performed similarly well.”
MISO Manager of Expansion Planning Lynn Hecker said the RTO has so far been using a conservative, approximately 20-year life cycle assumption in battery reliability studies.
The RTO has yet to develop life cycle cost comparisons for ATC’s battery and alternate projects.
Slegers said MISO is open to studying even more project alternatives, if stakeholders offer them. The RTO has said it will work with stakeholders “to understand technical details and evaluate any additional alternatives proposed.”
He noted that the ATC project evaluation will serve as a starting point and “lessons learned” for other SATA projects proposed in future MTEP cycles.
LITTLE ROCK, Ark. — The predominance of renewable energy and battery storage in the nation’s RTO interconnection queues is certainly no secret.
SPP’s queue is dominated by 51.8 GW of wind projects in all stages of study and development. That’s on top of 21.6 GW of installed wind capacity and another 7.7 GW of unbuilt projects with signed interconnection agreements. Layered on top of that is 25 GW of solar projects in the queue — 215 MW is already installed — along with 4.5 GW of battery storage.
Casey Cathey, SPP manager of reliability planning and seams, listed those numbers as he moderated a panel Thursday devoted to planning for an evolving grid.
“What’s our next challenge?” Cathey asked ITC Holdings’ director of regional planning, Alan Myers.
“Isn’t that enough?” Myers responded, drawing laughter from those gathered last week for SPP’s Engineering Planning Summit.
Turning serious, Myers offered a response: “It’s matching that variable to the variability of the load.”
“It used to be generation was the variable. Now, we’re seeing load becoming a huge variable,” said fellow panelist Holly Carias, NextEra Energy Resources’ director of origination. “It will take different technologies to maximize what we already have. Not only with transmission, but on the load side. We have to focus on providing service to the end customer and give them a better customer experience.”
Daniel Brooks, who manages the Electric Power Research Institute’s grid operations and planning research group, threw a wrench into the discussion when he reminded the panel and audience, “EVs are coming.”
Brooks said 10 to 20 years ago, automakers were first attempting to turn a car’s wheels with batteries.
“Listen to those [original equipment manufacturers] today. They’re completely committed to moving to electric vehicle fleets,” he said. “Some heavy-duty vehicle fleets are talking about multi-megawatt charging stations. That’s a challenge, but an opportunity as well.”
As Brooks is fond of saying, “It’s tough to make predictions, especially about the future.”
So far, SPP has been pretty successful with its forecasts. It says its planning efforts have resulted in $10 billion of construction projects over the last 14 years, allowing the RTO to focus on smaller upgrades and reliability projects.
The RTO’s Board of Directors in April approved a $1.8 billion Transmission Expansion Plan that will build projects in 13 states over the next five years. Members last year completed 98 transmission system upgrades in seven states at an estimated cost of $779 million.
A 2016 SPP study indicated $3.4 billion of transmission upgrades during 2012-2014 resulted in more than $240 million in fuel-cost savings for SPP members during the first year of the Integrated Marketplace. The RTO has said it expects the benefits to exceed a net present value of $16.6 billion into the 2050s, with a benefit-to-cost ratio of 3.5. (See SPP Begins Promotional Campaign to Tout Transmission Value.)
‘Big Boys’
“Transmission planning provides a lot of value, particularly when it results in construction,” SPP Engineering Vice President Lanny Nickell said in opening the summit Wednesday. “We have a lot of metrics that have determined we do provide a lot of value through the expansion of transmission.”
Stakeholders reviewed the transmission projects that could make up the 2019 Integrated Transmission Planning assessment, which will go before the board in October for approval.
The 2019 portfolio’s cost could be as high as $407 million, though staff estimate the projects could provide as much as $2 billion in benefits. Several of the projects target the southern corner of SPP’s footprint in Kansas and Missouri. There, congestion on MISO’s side of the seam has resulted in more than $60 million in market-to-market payments to SPP since March 2015. Constructing new 345-kV lines in the area could cost as much as $158 million, according to one proposed project.
Cathey noted SPP can no longer look at other RTOs — and Denmark and Germany, both leaders in renewable integration — for guidance on the ratemaking that will eventually help pay for the lines.
“SPP is kind of at the forefront of some of these challenges. We’re kind of the big boys now,” he said.
“A big gap I see is that relationship between planning and regulatory. We’ve always been on the tail end. We find out what the regulatory decision is, then we scramble to make our plan fit that,” SPP Planning Director Antoine Lucas responded. “I don’t think we can expect that we’ll drive the regulatory process, but there has to be some form of collaboration on the front end to develop solutions that benefit both sides. It will be a big value-add if we can figure out ways to work in different partnerships with different organizations to tackle these problems.”
As the summit wound to a close, Jay Caspary, SPP’s director of research and development and special studies, reminded stakeholders that the RTO and its members will also have to deal with the footprint’s aging infrastructure, some of which is more than 60 years old.
“We’ve got to manage these assets in the field,” he said, referring to himself as an “aging asset too.”
“There are a lot of uncertainties, but one thing that isn’t is that time marches on. These things are getting older by the day. I want us to get ahead of that.”
“There’s a lot to consider. It’s not like it was 10 years ago,” Cathey said. “These will be interesting times moving forward. We’ll see if we’re accurate with our transmission planning as we were with all the transmission we built 20 years ago.”
A NERC panel considering a proposal to limit reporting on system operating limit (SOL) exceedances will be seeking data to support its claims that excessive compliance requirements are a reliability threat.
Members of the standards development team (SDT) for Project 2015-09 (Establish and Communicate System Operating Limits) will be gathering the data in response to concerns by FERC staff over a proposal that would require logging, communication and documentation only when SOL exceedances last for 30 minutes or longer.
The proposal, which came in response to comments by the Midwest Reliability Organization, has received “a lot of positive feedback from industry,” SDT Chair Vic Howell, of Peak Reliability, told stakeholders Wednesday. Current NERC standards do not clearly define what is an SOL exceedance or when it must be reported, he said.
Howell provided a briefing on a May 2 conference call that he and several other SDT members had with FERC staff on the proposal.
“It wasn’t very clear [to FERC] that this was a reliability issue as much as it was a compliance issue. … We tried to explain that it is a reliability issue because if operators are so busy doing all this documentation for compliance evidence, it takes their eye off the ball for performing actual operations and addressing actual SOL exceedances,” Howell said. “We got to a place where FERC staff understood our concerns and … they wanted us to come up with data to back up our concerns.”
System operating limits development in the operations horizon | SPP
Following the FERC call, Stephen Solis of ERCOT compiled preliminary statistics to facilitate discussions of what the actual data request could look like. The preliminary data showed that in January, about 2% of the Texas grid operator’s five-minute exceedances of pre- and post-contingency thermal or voltage limits lasted longer than 30 minutes. He acknowledged that ERCOT’s data includes 69-kV lines that are below NERC’s Bulk Electric System threshold and a number of non-exceedances that show up as the values approach close to an exceedance.
Reporting only the exceedances of more than 30 minutes would require almost 40 communications a day, Solis said. “The rest of it is just normal everyday seeing things, responding; seeing things, responding; repositioning the system very quickly.”
Solis said if ERCOT had to report each of the nearly 76,000 five-minute exceedances for the month, “we’d have to hire two or three people just to get on the phone and call people.”
“It’s not realistic and that would be a detriment to reliability,” he continued. “Of every 50 violations, one will make it greater than 30 minutes. We’re doing a very good job of catching things, fixing things. If you’re going to penalize companies for doing a good job, there’s something broken there.”
Howell said the team will seek data from MRO and others outside the SDT but that it would not be an industry-wide effort. “Whoever we can get to give us the data and do the data analysis so that we have a good representation and a reasonable pool, then we’ll go with that,” he said.
FERC staffer Eugene Blick, who participated in the Wednesday SDT meeting, suggested the team obtain data from “multiple [reliability coordinators], because keep in mind, what you’re proposing to change is in a continent-wide standard applicable to all RCs and all [transmission operators].”
Blick said one other entity that commission staff have spoken to didn’t see the issue as a problem. “They didn’t have many SOL exceedances during their operating day because their [operational planning analysis] served as a means to filter or mitigate some of the SOL exceedances.”
He said seeming exceedances that result from telemetry or modeling problems should be excluded in the data collection.
Howell said the team will spend the next couple weeks refining its data request before seeking contributions.
NERC and the regional entities are proposing almost $207 million in spending in 2020, a 3.8% increase. Assessments are projected to increase by 2.9%.
The Electric Reliability Organization Enterprise budgets include a 9.8% spending increase for the Midwest Reliability Organization, which is absorbing the former SPP Regional Entity’s compliance enforcement duties, and a 35.2% jump for SERC Reliability, which is expanding to peninsular Florida with the phase out of the Florida Reliability Coordinating Council. (See FERC OKs SERC’s Expansion into Florida.)
Including the elimination of about 21 jobs at FRCC, and the addition of 20 at SERC, total ERO Enterprise headcount is projected at about 698, an increase of about 18.
The preliminary budgets were presented to the Board of Trustees’ Finance and Audit Committee (FAC) meeting Thursday. Final draft budgets will be posted July 15 and discussed at a July 18 FAC webinar. The board is scheduled to approve the budgets on Aug. 15 and submit them for approval by FERC and Canadian authorities Aug. 26.
The Compliance Monitoring and Enforcement Program (49%) and Reliability Assessment and Performance Analysis (18%) account for two-thirds of the ERO Enterprise’s spending.
NERC’s proposed budget is almost $83 million, a 3.8% increase driven by a 13.3% boost in spending for the Electricity Information Sharing and Analysis Center (E-ISAC). Excluding the E-ISAC — which will account for 11% of the ERO Enterprise budget and 27% of NERC’s — the organization’s spending will decrease slightly. (See “E-ISAC Continues Growth,” NERC Technology & Security Committee Briefs: May 8, 2019.)
In presentations to the committee, the REs projected salary inflation of about 3 to 3.5%, and benefits increases ranging from about 5 to 6% for MRO and SERC to 14% for Texas Reliability Entity.
TRE is also projecting its rent and utilities costs will increase nearly 28% when it renews the lease on its Austin headquarters in late 2020.
ReliabilityFirst’s budget, which is increasing 4.4%, includes funding for “overlap” hires to prepare for the departure for retiring employees. About 11% of RF’s employees are at or over retirement age.
SERC is projecting a 35% increase in meeting and travel costs related to the addition of the FRCC entities and the expansion of its board Executive Committee to 15 from 12.
MISO’s effort to improve a key communication system will come too late to smooth summertime emergency procedures, stakeholders said last week.
In post-mortems of a January emergency event in which less than a quarter of load-modifying resources (LMRs) performed to the RTO’s criteria, multiple stakeholders complained the MISO Communications System (MCS) was difficult to understand and navigate.
The poor generator performance resulted in MISO last month issuing market participants nearly $2 million in penalties and disqualifying 21 LMRs for the remainder of the 2018/19 planning year. (See “MISO: $2 Million in Penalties for Jan. 30 LMR Underperformance,” MISO Reliability Subcommittee Briefs: May 2, 2019.)
During a Reliability Subcommittee (RSC) conference call Thursday, Chair Bill SeDoris said the low LMR success rate in January is evidence of “serious procedural issues on both sides of the house.”
Customized Energy Solutions’ Ted Kuhn criticized the RSC for scheduling MCS improvement discussions for the third quarter, saying MISO is likely to call multiple summertime emergencies using an inadequate system while market participants wait on improvements.
“The current MCS is not sufficient. … Some of these things need to get fixed,” Kuhn said. Other call participants repeated the plea for quicker improvements.
SeDoris said MISO’s nonpublic Reliable Operations Working Group (ROWG) has taken up short-term improvements, including clearer communication when the RTO terminates a maximum generation alert.
Ron Arness, MISO director of Central Region operations, said the ROWG had a “healthy” discussion on how to improve usability of the MCS on Wednesday.
“There are some changes coming; those changes aren’t going to occur overnight. … Be patient with us,” Arness said.
But stakeholders say a mid-May emergency in MISO South already illustrates that the MCS is ill-suited for emergency communications. WPPI Energy economist Valy Goepfrich said when MISO called the May 16 maximum generation alert, it wasn’t clear the alert only extended to the South region.
MISO South May Emergency
MISO said the five-hour May 16 emergency was atypical, the result of a higher-than-normal forced outage rate combined with above-average temperatures and the usual spring maintenance season.
“While unplanned outages are expected, the successive loss of [about] 4 GW of generation in a short period of time is outside normal expected operating conditions,” MISO said.
Outages and derates in MISO South reached 16.6 GW that day, and load obligations hit a peak of about 27 GW around 5 p.m. MISO said it was able to maintain reliability through two separate calls for LMRs with lead times of three hours or fewer. The RTO will provide LMR response data at a later date.
MISO South May 16 emergency (megawatts) | MISO
Arness said MISO South frequently experienced tight capacity conditions over the last three weeks of May.
The RTO expects tight operating conditions in South through June due to hotter weather and continuing maintenance activity. Arness told stakeholders to be prepared for more emergency alerts in the region.
Goepfrich noted that MISO didn’t come close to hitting the North-South transfer limit during the event and asked that it ensure that transfer capability is used before it calls on LMRs.
Outage Exemption Talk Ongoing
MISO last week also said it will expand a penalty exemption to include resources that return early from a planned outage, part of new outage scheduling rules.
The RTO will exempt resources from accreditation penalties if the start and end date of their submitted outages remain within 10% of the originally scheduled outage window “and/or [the resource] reduces the capacity of the outage” to provide MISO with more available capacity.
MISO originally proposed that unit owners submit a new outage request for both extended and shortened outages to allow it to evaluate the request based on maintenance margin supply predictions, putting a resource’s penalty exemption at risk. Units earn penalty exemptions if they schedule an outage at least four months in advance. However, stakeholders questioned the potential for MISO to revoke the penalty exemption on even shortened outages. (See “MISO Taking Second Look at Outage Change Penalties,” MISO Reliability Subcommittee Briefs: May 2, 2019.)
Jeanna Furnish, MISO manager of outage coordination, said the RTO still seeks to discourage “bad behavior” when participants schedule planned outages. She said significant shortening of outages impacts MISO data and forecasting and affects other available megawatts.
“We want the best information we can get about your outage schedule. We want you to return early if you reliably can … but we want to acknowledge this isn’t a free pass to schedule the longest outage you can then reduce,” Furnish said.
Some stakeholders still weren’t satisfied with MISO’s compromise.
“You’re creating a huge disincentive for generation to shorten their outages,” CES’ David Sapper said.
Furnish said she rarely sees generation return significantly early from outages, adding that many generators actually lengthen planned outages.
MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO is seeking to “strike a balance” to prevent generators from scheduling longer-than-necessary outages simply for the wiggle room.
Furnish put the 10% proposal to a round of feedback and encouraged stakeholders to offer exemption alternatives.
RENSSELAER, N.Y. — NYISO stakeholders on Thursday debated the content of a draft study on the impact of public policy on the New York grid and learned about the ISO’s proposed changes to its carbon price calculation.
The draft “Reliability and Market Considerations for a Grid in Transition” study comes after New York Gov. Andrew Cuomo in January nearly quadrupled the state’s offshore wind energy goal to 9 GW by 2035, while his proposed Green New Deal would mandate 100% clean power by 2040, increase renewable energy requirements from 50% to 70% by 2030, and require other clean energy benchmarks. (See New York Boosts Zero-carbon, Renewable Goals.)
“What we try to do in the report is to describe the challenges and fill in the gaps,” Mike DeSocio, the ISO’s senior manager for market design, told the Installed Capacity/Market Issues Working Group.
NYISO first presented an outline of the new study, which analyzes the projected Bulk Power System in 2030 and 2040, at the group’s April 15 meeting. (See NYISO Studies Grid Transformation, Fuel Security.)
| NYISO
“The ISO would be better off looking at what the market will be like in five years and not spend too much time preparing for 15 or 20 years down the road,” said Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers.
DeSocio agreed but said some of the needed investments are long-term.
“I think looking at 2030 and 2040 is important, at least to provide reality checks on what people are planning,” said Mark Younger of Hudson Energy Economics. “NYISO needs to go out to 2040 and assume all-renewable generation, then do a multiday analysis of very little wind or solar, which would provide you a good snapshot of what you need for backup if you rely upon fossil generation compared to what you would need if you relied upon storage as backup.”
Noting that the state recognizes a carbon-reduction imperative that the market does not, David Clarke, director of wholesale market policy for Power Supply Long Island, suggested that NYISO’s study consider how to optimize various as-bid resources and other alternatives to achieve the state’s targets. He noted that whether carbon pricing is ratified or not, “sequestration might be a better way to achieve the goals cost-effectively rather than other approaches, including carbon pricing.”
Andrew Antinori, senior director of the New York Power Authority’s Market Issues Group, asked whether it would be more efficient for the ISO to see whether or not a carbon charge will be implemented before expending resources studying different possible futures.
Howard Fromer, director of market policy for PSEG Power New York, asked whether the ISO has looked at using external resources to provide reserves.
“It seems the movement of resources across borders is going to become more important,” Fromer said. “I know we don’t currently have any projects to look at that, but it seems important to look at the whole seam issue and see how to access those resources.” (See NY Carbon Task Force Discusses Seams, ‘Leakage’.)
DeSocio agreed that external resources do fit into the picture.
“We’re probably going to need additional transmission, but it’s got to be strategic, and we’re probably going to need additional capacity, but it’s got to be strategic,” DeSocio said. “We need to get the energy prices right … that’s what it’s about here. … My bias is not to spend a lot of time on expanding new capacity products; that’s a pretty blunt instrument.”
The ISO’s timeline is to get an updated report out by the end of summer and add some quantitative analysis ahead of the Board of Directors’ strategic planning session in September, DeSocio said. By the end of June, the Analysis Group will provide preliminary analyses from a different study examining the market impacts of pricing carbon and will complete its report by the end of July, he said. (See More Details Divulged on New NYISO Carbon Pricing Study.)
Carbon Pricing: Calculating the LBMPc
After considering stakeholder feedback, NYISO has revised its proposed calculation of the carbon component in locational-based marginal prices (LBMPc), now subtracting a variable operations and maintenance (VOM) cost from the LBMP. The resulting value will then be divided by the estimated marginal fuel cost ($/MMBtu) plus the cost of emissions ($/MMBtu).
“Adding the cost of emissions was suggested by a few stakeholders last time to arrive at a more realistic heat rate,” said Ethan Avallone, the ISO’s technical specialist in energy market design who presented the analysis.
As discussed in previous meetings, NYISO will set the LBMPc to zero when the calculated LBMPc is less than zero and set the implied heat rate to zero when the calculated implied heat rate is below the minimum implied heat rate. (See Carbon Pricing Impact on Waste-to-Energy Examined.)
“We will use the LBMPc to allocate the carbon credit to [load-serving entities] and to prevent leakage and distortion of regional flows by charging imports and crediting exports the LBMPc, and also to provide market transparency,” Avallone said.
LBMPc calculation – fuel indices by region | NYISO
Internal generators are charged based on their actual emissions — not the LBMPc.
The implied heat rate produced by the calculation should be limited by a minimum and maximum to maintain an appropriate LBMPc, Avallone said. Absent a maximum value, the impact of shortage pricing on the LBMP could result in an inappropriately high implied heat rate; without a minimum, the impact of renewable generation on the LBMP could result in an inappropriately low heat rate.
The implied heat rate should be set to zero when less than the minimum limit and set to the maximum when above the maximum limit, Avallone said. A low implied heat rate indicates that zero-emission energy, which does not bid opportunity cost, is likely marginal.
NYISO would post minimum and maximum heat rates on its website and is considering stakeholder feedback to describe potential future revisions to eligibility criteria, he said.
In addition, the ISO will post the effective social cost of carbon (SCC), as determined by the state’s Public Service Commission.
The net SCC would be the gross SCC, established by the commission, minus the Regional Greenhouse Gas Initiative price.
Avallone also presented a summary of proposed Tariff changes to accommodate a carbon pricing regime, with new sections to describe carbon charges, payments and residual allocation.
NYISO is considering stakeholder feedback to describe potential future revisions to eligibility criteria and plans to review the proposed Tariff changes again at the June 11 ICAP/MIWG meeting, Avallone said. (See “Tariff Terms, Penalties,” NYISO Commissions New Social Cost of Carbon Study.)
Illustrative change in revenues, 1×1 gas combined-cycle, assuming new entry is needed | NYISO
Enhanced Fast-start Pricing
In response to a FERC order, NYISO is revising fast-start pricing to apply to all resources that can start up and synchronize to the grid in 30 minutes or less, have a minimum run time of one hour or less, and submit economic offers for evaluation.
The commission on April 18 ordered the ISO to revise its pricing logic to reflect the start-up costs of fast-start resources and relax the economic minimum operating limits of all fast-start resources by up to 100% to allow them to set prices (ER18-33). (See FERC Orders Fast-start Rules for PJM, NYISO.)
Under the proposed changes, “we use special pricing logic to better reflect the true cost of energy,” said Whitney Lesnicki, an ISO manager for energy market design, who presented the enhancements.
The ISO must submit its compliance filing by Dec. 31 and implement the changes by Dec. 31, 2020.
PJM presented a first read of its annual Manual 6 cover-to-cover review regarding financial transmission rights.
Brian Chmielewski, manager of market simulation, said staff are continuing their look into rule changes around FTR mark-to-auction credit requirements detailed in Section 6.7, but they’re moving ahead with default settlement rule updates, realignments to the OASIS refresh and the hourly cost component change, pending FERC approval.
Manuals Endorsed
Manual 01: Control Center and Data Exchange Requirements as a part of the cover-to-cover review.
Manual 03: Transmission Operations as a part of a cover-to-cover review.
Manual 07: PJM Protection Standards to update applicability references and an Institute of Electrical and Electronics Engineers standard reference.
Manual 11: Energy & Ancillary Services Market Operations and Manual 13: Emergency Operations to clarify the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.
Manual 13: Emergency Operations as part of a cover-to-cover review.
Manual 36: System Restoration as a part of a cover-to-cover review.
With about six months left before it seeks approval, MISO is polishing a draft 2019 Transmission Expansion Plan (MTEP) that could end up being one of the RTO’s most expensive buildout packages.
The draft so far contains 518 new projects at $4.3 billion to be recommended for approval. Included are 65 new projects valued at $771 million up for consideration in MISO South, stakeholders learned Wednesday at a subregional planning meeting.
MTEP 19 is so far clocking in at $1 billion more than the $3.3 billion, 442-project MTEP 18. (See MISO Board OKs Full MTEP 18 over Stakeholder Complaints.) MTEP 11, which contained the Multi-Value Project portfolio, holds the record for the most expensive proposal at $6.5 billion.
The highest-cost MTEP transmission projects in recent years have been in MISO South, which held five of the top 10 most expensive projects in MTEP 16 and MTEP 18, and eight of the top 10 costliest in MTEP 17.
MISO South Replacement Project
One of the priciest MISO South projects recommended in MTEP 19 will negate the need for two costlier projects approved for southern Louisiana the two previous years.
Cleco and Entergy’s proposed $81.5 million joint project near Lafayette can replace the North and East Acadiana Load Pocket (ALP) transmission projects that were set to cost a combined $213.1 million.
MISO engineer Patrick Jehring said the replacement Sellers LeBlanc project is poised to save customers $131.6 million, and the cost difference is the only “differentiating factor” between the projects. He said MISO supports the withdrawal of the ALP projects.
He praised Cleco and Entergy for working together on a lower-cost solution.
“This is really a good story to tell, and really only happened because of … significant collaboration between entities,” Jehring said. “The only way we got here is through engagement with Cleco, Entergy and the Lafayette Utilities System.”
The Sellers LeBlanc project involves a new 19-mile 138-kV line and a series reactor on an existing nearby 138-kV line for $66.7 million from Entergy. Cleco will take on the remaining $14.8 million by tying the new line into an existing 138-kV line and constructing a new autotransformer.
The project will resolve the overloading risk of multiple 138-kV lines around Lafayette. Additionally, MISO said there is approximately 300 MW of load in the Abbeville, La., area served by just one 230-kV line.
“It’s pretty obvious that we want to go with the cheaper project,” Jehring said. “We’ve truly identified the least-cost solution here.”
Jehring encouraged stakeholders to provide written feedback on the proposed project.
Issues in the Lafayette, La., area | MISO
Shortlist from MCPS
Meanwhile, MISO’s 2019 Market Congestion Planning Study (MCPS) has identified a short list of potential projects, with seven project candidates proposing to solve three separate issues making the first round of screening.
Three 345-kV projects ranging from $32 million to $85 million propose to solve congestion issues on the Helena-to-Scott County 345-kV line in southern Minnesota. MISO Economic Studies Engineer Karthik Munukutla said all three solutions are potentially eligible for market efficiency project categorization and cost sharing.
Two projects — a $58 million, 161-kV line rebuild and a $20 million new substation — are proposed to solve congestion on a 161-kV flowgate on the Iowa-Nebraska border. Finally, two new 115-kV lines at either $35 million or $37 million are competing to solve congestion on a 115-kV flowgate in southwest Arkansas. Munukutla said the four projects deal with MISO-SPP seams issues and will be added to the RTOs’ ongoing coordinated system plan study to see whether they’d make beneficial interregional projects.
Munukutla said he wanted to share preliminary MCPS results so stakeholders get an idea of which projects stand to provide the most value after initial transmission analyses. He said MISO expects to have more certainty in July about what projects may be selected from the study.
