Four years after approval, MISO’s first competitive transmission project last week began transporting power in Southern Indiana and Western Kentucky.
LS Power’s Republic Transmission and partner Big Rivers Electric constructed the nearly 31-mile, 345-kV Duff-Coleman transmission project after their bid was selected by MISO planners in 2016.
MISO spokesperson Allison Bermudez said the project is now estimated at a total $64.9 million, noting that it will be a few more months before there is a final tally. The total project cost includes the costs of Vectren and Big Rivers Electric to expand their substations to accommodate the project, which weren’t included in Republic’s original proposal.
Republic’s original $49.8 million proposal — in 2016 dollars — was selected over 10 other developers’ bids. (See LS Power Unit Wins MISO’s First Competitive Project.) MISO originally placed a $59 million planning-level estimate on the work.
Duff-Coleman line | Republic Transmission
Republic’s bid contained caps on project implementation, inflation rate, return on equity (9.8%) and capital structure (45% equity). It did not cap operations and maintenance costs or offer rate concessions.
According to MISO information, Republic experienced a nearly $4 million increase due to construction cost estimates that were more expensive than anticipated and to acquire right-of-way rights. Vectren also recorded a $700,000 cost increase for an additional 345 kV breaker and for a 138 kV line relocation necessary for the Duff Substation expansion.
Republic did not respond to a request for comment about the cost increase. The increase was less than the 25% that would have triggered a MISO variance analysis, which would have provided a public record of cost overruns.
“The culmination of this project and its transition into operations ahead of schedule and within our cost commitments demonstrates the benefits that can be realized by consumers through FERC Order 1000 competitive transmission processes,” LS Power President Paul Thessen said in a MISO press release. “We appreciate the efforts of MISO, project participants Hoosier Energy and Big Rivers, and interconnecting transmission owner, Vectren, to make this project a success.”
MISO estimates the project will provide $1 billion in benefits to its central region over the next two decades.
Originally scheduled for completion in January 2021, the line was energized six months ahead of schedule Thursday, as Republic officially became a MISO transmission owner.
“New transmission-owning members bring diversity to our footprint, and the competitive transmission process allows us to work with our members to identify projects that create value for the entire bulk electric system,” MISO Executive Director of Systems Planning and Competitive Transmission Aubrey Johnson said. “Our existing member companies collaborated with Republic and MISO to bring this project to fruition.”
Once considered the “bridge fuel” to a clean energy future, natural gas faces a rapidly diminishing role in New England’s electricity outlook as the region pivots to massive offshore wind buildouts to meet emissions goals, industry participants heard last week.
Massachusetts officials project 25 GW of offshore wind generation in the region by 2050, translating into a volume that could be exported to other parts of the country, applied to manufacturing carbon-neutral hydrogen or used along with storage to provide electric heating for homes and offices.
Participants at the 166th New England Electricity Restructuring Roundtable heard that and more on Friday as more than 400 people tuned into the webinar hosted by Raab Associates and the normal physical venue sponsor in Boston, Foley Hoag.
Modeling the Future
The Bay State is exploring more than half a dozen long-term, deep decarbonization pathways by which the commonwealth can efficiently and equitably achieve Gov. Charlie Baker’s commitment to net-zero greenhouse gas emissions in 2050, said Massachusetts Undersecretary for Climate Change David Ismay.
“Our models are literally still running, and we’re looking for publication in the December time frame,” Ismay said.
One scenario includes the region’s pipeline system delivering a decarbonized gas, but as clean imports and offshore wind increase in the 2020s, the number of megawatt-hours delivered by gas plants decreases, he said.
“By 2030 the model is consistently selecting offshore wind as the least-cost, emissions-compliant resource for Massachusetts to access, and its share of megawatt-hours, as do those for solar, increases steadily through to 2050,” Ismay said.
(clockwise from top left) Zeyneb Magavi, HEET; Jonathan Raab, Raab Associates; Patrick Woodcock, Massachusetts DOER; Sheri Givens, National Grid; and Bill Akley, Eversource. | Raab Associates
“By 2050, across all the scenarios we’ve tested thus far, and unless it’s constrained artificially because of siting or construction delays, the model sees offshore wind becoming the dominant power provider for emissions-compliant electrons on the order of about 70% annually for Massachusetts,” Ismay said.
Gas turbine output drops to a de minimis level, providing less than 5% of the annual megawatt-hours over the course of the year in 2050, he said.
“Despite that low capacity factor, high-efficiency gas turbines burning a blended fuel that includes hydrogen have the potential to provide value to the electric system in 2050.”
Ismay showed an example of two hypothetical August days in the Massachusetts of 2050. On the first day, offshore wind begins to ramp up and provide 10 GWh of production, scaling from zero at about noon to no more than 5 GWh in the last hour.
Two days later, the model indicates as much as 25 GW of production in each hour of the day, so closer to 500 GWh of production that day.
“Here, if we were not looking across the economy, we might think we have to spill or curtail all that wind,” Ismay said. “Looking across the entire economy shows there is no need to spill offshore wind, that the state can become a net exporter of clean power within and outside of New England.”
Questioning the Era of Natural Gas
Massachusetts Attorney General Maura Healey on June 4 petitioned the state’s Department of Public Utilities to open an investigation into the future of the natural gas industry as the state transitions away from fossil fuels and toward a clean renewable energy future by 2050.
Tom Kiley, CEO of the Northeast Gas Association, in March gave a review of the natural gas industry to the ISO-NE Planning Advisory Committee and cited Energy Information Administration data showing that U.S. natural gas consumption grew in the electric power sector by 2.0 Bcfd (7%) but remained relatively flat in the commercial, residential and industrial sectors. (See “Natural Gas Use Rises in NE,” ISO-NE Planning Advisory Committee: March 18, 2020.)
Susan Tierney, Analysis Group | Raab Associates
But Susan Tierney, senior adviser at Analysis Group, said she’s been thinking about how supply is changing in a world of flat demand and described how over the past two decades, coal and oil dropped from 34% to 0.5% of power production in the region.
“My research shows we’re going to see a continuing role for natural gas, but it’s going to be tough,” Tierney said. “There have been steep declines in CO2 emissions since 1991, but over the next 30 years, the pace is going to have to be much faster. Changes in the past 20 to 30 years pale in comparison to what’s ahead in New England.”
Melanie Kenderdine, EFI | Raab Associates
The economic and social shutdown resulting from the COVID-19 pandemic has reduced New England loads by 5 to 8% and has led to record unemployment claims, including job losses in the clean energy sector, which may slow progress to the 2050 goals, said Melanie Kenderdine, principal at the Energy Futures Initiative.
Each state in the region ranks in the top 10 nationwide in terms of one or another area of energy sector employment as a percentage of the total workforce, while three New England states rank in the top 10 in terms of unemployment claims as a percentage of the total workforce, Kenderdine said.
Reframing the Issue
Ken Kimmell, president of the Union of Concerned Scientists, said the industry needs to reframe the idea of natural gas as a bridge to future needs, perhaps as stepping stones, and showed an animation of someone jumping from one stone to another before splashing in the water where the stones ran out.
Ken Kimmell, UCS | Raab Associates
“Natural gas is not going to get us to the net-zero world that we need to be in, even though it will make some contribution in that regard,” Kimmell said.
“We hear a lot of arguments about preserving the optionality that gas affords us, and we actually agree with that argument, but sometimes it is transformed into a different argument of, ‘Let’s keep going with our natural gas system being dominant until we figure out and put in place the entire replacement of it.’
Dan Dolan, NEPGA | Raab Associates
“That is an argument that actually ensures the dominance of the natural gas system, which we can’t do if we’re serious about getting to net zero,” Kimmell said.
“We for the last six or seven years have focused on putting a meaningful price on carbon emissions and trying to use that as the enabling, financing, and consumer-driving and investment-driving tool to make this shift within the region,” said Dan Dolan, president of the New England Power Generators Association.
“What we’ve engaged in the last few months is trying to take the next steps for us as an organization and as a group of generators in identifying what that needs, which we’re looking forward to making public in the next few weeks,” Dolan said.
Gas in the Region’s Buildings
In the petition filed with the DPU, the Massachusetts attorney general’s office recognized the state’s findings that the heating sector must cut its use of fossil fuels to achieve the state’s mandate of net-zero GHG emissions by 2050.
Jonathan Raab, Raab Associates | Raab Associates
“In addition to its request to the DPU for detailed gas planning, the Mass. AGO has to rule in July whether to allow [the town of] Brookline’s gas ban law to be enacted, with probably a lot of impact on what other towns and cities do in Massachusetts,” said Jonathan Raab of Raab Associates.
“Do we really need to get much more active in state planning and utility planning on the gas side as we have done with, say, grid modernization on the electricity side?” Raab said.
“I would say it’s similar to some of the conversations we’re having in the transportation sector, in the Transportation Climate Initiative, learning from what led to the success in the electric sector, [which] I think we need to deploy in the building sector,” said Commissioner Patrick Woodcock of the Massachusetts Department of Energy Resources.
“That means from a construct of a renewable portfolio standard or a Regional Greenhouse Gas Initiative, or state caps that decline over time to give predictability,” Woodcock said. “I think we need to have that dialogue this decade, and that’s one of the reasons we initiated the 2050 pathways study.”
For example, at some point, baseline efficiency improvements may preclude some of the state’s electrification rebate and funding programs, Woodcock said.
The utilities are doing their part to reduce natural gas consumption, sometimes in surprising ways, as Eversource Energy’s president of gas operations, Bill Akley, said when describing a program to shave the gas peak, especially in supply-constrained areas.
Zeyneb Magavi, HEET | Raab Associates
Akley said he did not want to steal the thunder from Zeyneb Magavi, co-executive director of Home Energy Efficiency Team (HEET), a Cambridge-based environmental group that designed the networked geothermal concept that Eversource has proposed to pilot in their current rate case.
“My hope is that this pandemic we’re all in teaches us that failure to act is a lost opportunity to have the courage to reimagine, redesign and rebuild our energy system,” Magavi said.
HEET is proposing a new way to heat buildings where old gas pipe is dug up, through the “Geo-Micro-District,” an ambient temperature, shared-water loop connecting many customers for both heating and cooling.
“Some of the gas pipelines in Boston date to the Civil War. … Is this the infrastructure we want for the coming century?” Magavi said.
Sheri Givens, National Grid | Raab Associates
Sheri Givens, vice president for U.S. regulatory affairs and customer strategy at National Grid, shared how her company is “really looking at decarbonizing our gas system.”
“We announced our own internal net-zero goal for 2050 and are already at 70%,” Givens said.
She also described how National Grid is trying to meet the gas demand needs of New Yorkers, as well as the demands from state regulators and Gov. Andrew Cuomo.
More than 130 New Yorkers gathered in an online forum at the end of May to protest the possibility of National Grid increasing the state’s supply of natural gas with additional infrastructure or increased shipping. (See Online Protesters Reject NY Gas Supply Plans.)
MISO said last week it continues to weigh multiple changes to its markets and resource adequacy construct as part of its multiyear resource availability and need (RAN) project.
On the market side, MISO is researching what it would take to implement a forward market process that can guide commitment decisions before the day-ahead market is able.
Speaking during a Market Subcommittee teleconference Thursday, MISO Director of Market Design Kevin Vannoy said the RTO will soon circulate a survey among generation owners that self-commit before the day-ahead market to better understand what drives their decisions. The survey will be sent to 28 market participants that own the 115 coal and natural gas units that comprise 90% of self-committed day-ahead energy.
“We’re looking for those drivers and reasons behind self-commitments,” Vannoy said. “The day-ahead market was obviously designed years ago … where there were limited algorithms and optimization. I think we’re still living in that world a bit.”
Senior Market Engineer Chuck Hansen also said MISO could expand its multiday operating margin forecasts as part of a forward market.
MISO late last year began publishing a first edition of its multiday operating margins, which predicts supply conditions six days in advance. The multiday forecast is for informational purposes only and does not serve a multiday financial market.
“It’s designed to be built upon. You don’t have to scrap the whole thing to make a change,” Hansen said of the forecast’s design.
MISO estimates that the forecast — meant for resources that self-commit — is downloaded about 20 to 30 times a day.
A multiday — or forward — market mechanism along with better scarcity pricing are market-side improvements being considered in MISO’s multifaceted RAN effort. Resource adequacy changes under discussion include establishing new reliability requirements, re-examining capacity resource accreditation and migrating the capacity auction from an annual basis to a seasonal or sub-annual basis. (See MISO Stakeholders Split on Seasonal RA Measures.)
A sub-annual RA format remains unpopular among MISO stakeholders, with some skeptical the RTO will be able to demonstrate a wintertime loss-of-load risk that could drive the seasonal changes. MISO staff have repeatedly said that its current, summer-focused loss-of-load expectation (LOLE) analysis ignores an emerging wintertime risk.
Using 2018 data, MISO found a moderate loss-of-load risk for several hours in January and September; however, MISO said the high risk remains confined to July only. The non-summer loss-of-load risk will only worsen with the continued fleet shift toward renewables, the RTO warned. It said inputting data from 20-year futures scenarios used in the annual transmission expansion plan yields loss-of-load risk in February and December in addition to January and September.
“The summer risk is just one element of risk to the system,” Jessica Harrison, MISO director of research and development, said at a Resource Adequacy Subcommittee teleconference Wednesday.
The Brattle Group’s Johannes Pfeifenberger suggested that MISO, in addition to an LOLE analysis, establish an expected unserved energy (EUE) standard, which measures system capability to continuously serve all loads to all delivery points while meeting planning criteria. Pfeifenberger said EUE standards aren’t commonly used in U.S. RTOs.
MISO is currently drafting a white paper on the problem statement behind the next round of proposed RAN fixes. The RTO plans to hold a virtual workshop late this month to go over the white paper.
“There won’t be new things that no one has ever seen or heard,” RASC liaison Scott Wright said of the white paper.
Like last month, multiple stakeholders expressed apprehension about MISO presenting a finalized white paper that doesn’t include stakeholders contributions. Several said MISO could reach conclusions in the white paper with which they don’t agree.
“That would be a problematic foundation to start talking about solutions with,” WPPI Energy’s Steve Leovy said.
But Consumers Energy’s Kevin Van Oirschot said the “new world order” in the footprint means MISO shouldn’t wait any longer to make market and resource adequacy changes. “I think we’re in a world where expediency is what we need,” he said.
New England’s total wholesale costs of electricity last year fell 19% to $9.8 billion, driven mostly by lower energy costs, according to the ISO-NE Internal Market Monitor’s 2019 Annual Markets Report.
Energy and capacity costs collectively composed about 93% of the overall decrease, as shown by highlights from the report presented by IMM Director Jeffrey McDonald to the New England Power Pool Markets Committee last week.
Energy costs fell primarily on lower natural gas prices and lower loads, totaling about $4.1 billion and down about 33% from 2018.
The 2019 energy market cost decrease in New England was driven by lower energy prices resulting from lower natural gas prices. | ISO-NE
Last year contrasted with a 2018 that saw both an extended winter cold snap and a hot and humid summer, which elevated natural gas prices in winter and boosted electricity prices in both seasons. Natural gas prices declined 34% last year to an average of $3.26/MMBtu.
Electricity demand in the third quarter of the year decreased by 6%, or by 1,011 MW per hour, on average, and drove a 4% decrease in annual demand. On a weather-normalized basis, demand was down slightly, continuing a longer-term downward trend because of the increase in utility-backed energy efficiency programs and behind-the-meter photovoltaic generation, McDonald said.
Ancillary service costs in New England were 25% lower in 2019 from the previous year. | ISO-NE
ISO-NE also reported that the Forward Capacity Auction procured surplus capacity for the sixth consecutive year as clearing prices continued a downward trend. FCA 14 in February cleared at an all-time low price of $2/kW-month. (See ISO-NE Capacity Prices Hit Record Low.)
FCA 14’s surplus was almost 1,500 MW, or 5%, above the installed capacity requirement, despite a significant amount of capacity (more than 2,500 MW) exiting the capacity market, mostly for a one-year period, in response to low prices, according to the report.
Exempting EE from Pay-for-Performance
Mark Spencer of LS Power led discussion of a Jericho Power proposal to exempt EE resources from Pay-for-Performance (PfP) in order to eliminate up to $19 million in credit support costs for all capacity resources.
ISO-NE rolled out PfP in June 2018 to ensure fuel security under severe winter conditions. Under the program, all resources with capacity supply obligations (CSOs) are assessed a charge — based on their gross FCA payments — when a “measurable” real-time operating reserve (RTOR) deficiency triggers a capacity scarcity condition (CSC). The RTO then redistributes the money collected from that charge as payments to CSO resources based on their performance during the RTOR event.
Critics contend that the current PfP arrangement has the potential to overcompensate the performance of EE resources during CSC events, which could be remedied by altogether removing those resources from PfP because their RTOR deficiencies are not technically measurable.
A Sept. 3, 2018, CSC event used as an example showed that “EE received a charge of $551,000” while “non-EE capacity supply obligation holders shared in the pool charge to the tune of $7.3 million,” Spencer said.
Spencer posed a hypothetical circumstance of when EE can be overcompensated: “We’re now on the cusp, with FCA 15, of moving from the $2,000 [CSC charge] rate that was in effect during the September 2018 event, to … $5,455/MWh; EE’s charge would have been $1.5 million, [and] non‐EE CSO holders would have been charged $20 million” if the new rate was applied to the 2018 event, Spencer said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
“If applying on-peak rules to that hypothetical case, then EE’s net payment would have been $10.3 million, so just toggling the same event between off-peak and on-peak, it goes from $1.5 million to a net payment of $10.3 million,” he said.
This increase in net payments to EE as system load decreases is in “direct contradiction to the evidentiary record” of EE performance, LS Power contended. Under the proposal, net charges or net payments to EE in any hour of any CSC would be zero.
ISO-NE has estimated that for the 2019/20 capacity commitment period, the face value of credit support required because of EE’s participation in PfP was $11 million to $19 million, and the cost of providing this support is higher for smaller, nonpublic companies that may have lower credit ratings.
“If EE did not participate in PfP, this requirement, and its associated cost, would be eliminated,” Spencer said.
The proposal would retain EE’s base capacity payments, remove EE from the PfP settlement including the “insurance pool” and eliminate EE’s requirement to provide credit support for the FCM Delivery Financial Assurance.
Backers of the proposal will continue to develop it before the MC this summer before seeking a vote on the Market Rule 1 and Financial Assurance Policy changes at the September PC meeting.
FRM Sunset by 2025
ISO-NE Market Development Analyst Jonathan Lowell led discussion of the RTO’s proposal to sunset the Forward Reserve Market on June 1, 2025.
The FRM awards obligations to deliver 10-minute non-spinning reserves and 30-minute operating reserves in real time.
The FRM sunset proposal is not linked to FERC approval of the RTO’s Energy Security Improvements filing or to development of seasonal forward market for ESI energy options, according to meeting materials.
However, the RTO is following the suggestion of the External Market Monitor, which in its annual report published June 3 reiterated what it has been recommending since 2014. The EMM said that the FRM is no longer necessary, and that the settlement rules by themselves don’t create incentives for resources to be available in real time, forcing reliance on administrative penalty provisions.
Markets have evolved in other ways to reward resource flexibility and better performance, and transmission investment has addressed many locational constraints, the Monitor showed.
“The weaknesses are manifest, and FRM weaknesses outweigh any negligible remaining benefits,” the RTO’s materials said.
The RTO wants to establish a sunset date of June 1, 2025; otherwise, the assumptions used in FCA 16 for cost of new entry (CONE) and other parameters would not properly reflect expected ancillary service market revenues, according to the proposal.
The updated FRM sunset stakeholder schedule now anticipates an MC vote in October and a Participants Committee vote in November.
Rethinking Net CONE for FCA 16
In a matter related to the FRM sunset proposal, ISO-NE is proposing to update the CONE and net CONE calculations, and to recalculate existing — and establish new — offer review trigger prices (ORTPs) using updated data for FCA 16, to be held in 2022 to cover the 2025/26 capacity commitment period.
CONE estimates the cost to build a new resource in New England, while net CONE indicates the net revenue needed by the resource to be economically viable. ORTPs are low-end estimates of net CONE for specific — and less common — technologies.
Engaged by the RTO to support the updates, Concentric Energy Advisors’ Danielle Powers and her colleagues presented analysis with preliminary technology costs for the calculations, determination of ORTP technologies and indicative FRM revenue-offset component values.
ISO-NE aims to make its estimates consistent with FERC’s 2017 order directing that net CONE should be high enough to attract new entry, but not so high as to introduce unnecessary costs (ER17-795). The RTO proposes to file any calculation changes with FERC by Dec. 1.
CEA will continue its evaluation and analysis of technologies for CONE and ORTP calculations and provide initial assumptions for the financial model.
At the July MC meeting, the consultants will provide energy and ancillary services offsets, including a detailed approach, inputs, dispatch models and preliminary results for CONE and ORTP.
A webinar last week to discuss strategies for meeting Maine’s renewable portfolio standards and emission-reduction targets presented a stark reminder of just how challenging decarbonizing the entire power sector and curtailing global climate change will be.
The Environmental & Energy Technology Council of Maine (E2Tech) on Wednesday invited four panelists to present their own strategy for meeting Maine’s ambitious goals: a 45% greenhouse gas emissions reduction below 1990 levels by 2030, and at least 80% by 2050; and 80% renewable energy by 2030 and 100% by 2050.
Though each speaker emphasized different methods, all would involve an unprecedented buildout in solar and wind energy and a paradigm shift in how electricity is valued on the wholesale and retail markets. It would also involve massive electrification of all sectors of the state’s economy.
“One of the things that became clear as we prepared [for the webinar] is that we are overlapping quite a bit in our findings,” said Jürgen Weiss, a principal with The Brattle Group. “I think that by itself is an interesting observation. We’ll quibble about the last 5% or maybe the last 10% in the details here and there, but the overall conclusions that we come to are strikingly similar actually.”
Richard Silkman, CEO of advising firm Competitive Energy Services, said that converting all end uses of energy to electricity in the state would more than triple the 12 TWh used annually to about 40 TWh, while peak demand would go from about 2 GW to about 10 GW.
Weiss used a previous Brattle study that analyzed New England’s trajectory to obtaining 80% renewables by 2050 to present a comparison to Silkman’s projections. The study showed that the region would need about 200 GW of total capacity, over six times more than it has currently.
“The current pace of adding wind, solar, etc. falls far short of what is needed to build the needed renewable portfolio of 200 GW by 2050, but a steady growth rate of 10% or less per year would do it!” according to Brattle’s Jürgen Weiss. | The Brattle Group
“So if I want to scare anybody about how hard it will be to do it, I’ll frame it this way: We took 100 years to build the current electric system of something like 30 GW. Now we have 30 years to build an entirely new system of 200 GW,” Weiss said. “So that’s pretty scary.”
One of the biggest challenges for Maine and the rest of New England is that solar does not have as large a capacity factor as it does in other, sunnier parts of the U.S. New England’s demand also peaks in winter, when sunlight is less productive. That means the state will have to build an extraordinary amount of solar facilities to replace the large, retiring fossil fuel plants in the region, panelists said.
That presents its own challenges, said Richard Perez, senior research associate at the University of Albany’s Atmospheric Sciences Research Center. He focused his presentation on “ultra-high penetration PV,” as he said solar has the highest potential to meet global demand. “When we think of a ‘mix’ of solutions, for me the mix is solar,” he said. “Most of the other energy sources are byproducts of solar.”
Solar has the highest potential capacity of all generating resources, the University of Albany’s Richard Perez said. | E2Tech
The main challenge is converting solar from being a seasonal, intermittent resource to a firm, dispatchable one: “something that’s available 24/7/365, without downtime,” Perez said. A massive buildout of storage is one solution, he said, but “extremely expensive … even assuming very low future costs for storage.” Perez’s idea is to build more solar than is actually needed and purposefully curtail it, a model he calls “implicit storage.”
The problem is “nobody pays you to curtail,” making his solution “not dependent on technology; it’s more dependent on the policy and the rules of remuneration.”
The state will also have to evolve from its customer-driven model of renewable procurement. Perez related his own experience with making his New York home a net zero energy consumer: rooftop solar panels, an in-home battery and an electric vehicle. “None of those millions of customers [in his home city of Albany] could do what I did; they don’t have the space or maybe the financial position to do it. And the big industrial customers can not do that either.
“So if I [can] solve my problem and be proud about it, it’s far from solving what we need to do for [the] climate,” he said.
Another challenge is that Maine residents are also very protective of their state’s heavily forested land and scenic mountain views. Under Silkman’s analysis, onshore wind would also have to significantly increase, though not as much as solar, from 1 GW currently to 2.5 GW. That’s “problematic in Maine, I understand, given people’s love for mountaintops,” he said.
Perez noted grassroots, environmental opposition to PV development on the grounds of protecting land and trees. He said it would take 8,500 square miles to power the U.S. with 55% solar under his model of overbuilding. “So, it looks gigantic … until you put it in perspective and look at the ground distribution in the U.S.” That 8,500 square miles represents about 1% of farmland in the contiguous U.S., he said.
The yellow dot in the southwestern corner of the map represents the space necessary to generate 55% of Maine’s electricity with solar power. | E2Tech
In Maine, assuming the same proportion of solar in the generation mix, facilities would only take up 37 square km — compared to the state’s nearly 56,000 square km of forest. “There’s so much space, in fact, you could even foresee doing away with wind” and using 100% solar, he said.
‘Fall Far Short’
The panelists’ projections and strategies made it clear that Maine and New England are behind on achieving their goals.
“At the current rates of deployment of renewables that are now on the horizon for the next decade, we’re going to fall far short of building these large capacities of renewable resources by 2050,” Weiss said. “We have to roughly increase the annual average deployment rate [by] four to eight times … about [3,000] to 6,000 MW per year” between now and 2050. “So that’s scary.”
Regarding emissions reductions, Silkman said that the state’s 2050 goal is still possible if it significantly ramps up its electrification and renewable buildout. “But it’s not going to happen in the 2020s, no matter what we do,” he said. “This decade’s gone. But we can start to see some serious reductions in the 2030s and 2040s.”
Kurt Adams, CEO of Summit Utilities, concluded his remarks by encouraging attendees. “Stay humble and work hard,” he said. “We’re changing the status quo. It’s very, very difficult. And it’s very difficult for a lot of reasons. So it just takes a lot of work and a lot of checking yourself and thinking about how you’re moving things forward, rejecting your ideas if they’re not being successful and picking the next one up and driving forward.”
Two of Texas’ largest power companies say they are in no hurry to return employees to their offices, an indication of the electric industry’s caution around the coronavirus pandemic and its importance to the economy and everyday life.
Vistra Energy CEO Curt Morgan and Oncor CEO Allen Nye both said during a recent Gulf Coast Power Association video panel discussion that they are taking great care in returning their staff to the workplace.
Oncor CEO Allen Nye details COVID-19’s impact on the company. | GCPA
“We’ll probably be one of the last to go back to the workplace. We have no intention of bringing anyone back until we’re certain we can do so in a healthy manner,” Nye said during the June 4 discussion. “We recognize the critical nature of the service we provide. It’s been made abundantly clear to me that we have to keep the lights on. We have productivity in the company and the lights are on.”
“How, as the CEO of a company, can you bring people back if you can get the same productivity from people at home but you’re adding incremental risk to your people?” Morgan said. “It’s a very simply equation for us. Our people don’t want to do it. They’re afraid. Some have kids and don’t want to bring anything home. We’re not coming back until we have a vaccine or a therapeutic that works.”
It’s not just electric utilities taking a go-slow approach. MISO has gone so far as to call off all in-person meetings until next year. (See Wary of Contagion, MISO Bars Visitors for 2020.) CAISO has shut down in-person meetings until mid-September. PJM’s companywide telecommuting posture is likely to extend well into the fall.
SPP said last week it has postponed by two months its plan for returning staff to its facilities in Little Rock, Ark. — until Sept. 8, at the earliest. The RTO had originally planned a July 6 phased return, but the state has experienced a rise of confirmed cases, with hospitalizations up 88% and active cases nearly doubling since Memorial Day.
In an email to stakeholders, CEO Barbara Sugg said SPP “will always put [employees’] health and safety first” when deciding to return them to the office. The grid operator has hired an epidemiologist to tour its corporate headquarters and review the controls it has put in place.
“We are also examining internal policies and resources to support a longer-term transition” that also allows for continued telecommuting, Sugg said.
The RTOs and utilities have discovered that the office environment is actually conducive in spreading the coronavirus. Elevators, coffee machines and office kitchens, once taken for granted, now present dangers in a COVID-19 world.
“I’ve found from other [companies] sending people back that the restroom is the issue,” Morgan said, pointing to social-distancing requirements that would force employees to wait in lines. “It’s going to be really difficult to be productive when you have to stand in line to go to the bathroom.”
Vistra has organized a “planning-ahead” team to determine how best to bring back about 1,000 employees to its large open office space. Morgan said the team is working on more than 100 tasks to ready the office. The company also has an in-house doctor and is trying to get access to testing.
“I’m anxious to get back. Employees are asking us when we’ll return,” Morgan said. “Safety is bigger than anything else. Health is bigger than anything else.”
Cultural Shift
Vistra shut down its offices very early, Morgan said. He said the company has a “number of folks” from China, including some from Wuhan, where the coronavirus originated. As early as mid-February, Morgan said, Vistra started getting reports “that there was something terribly wrong in China.”
Vistra CEO Curt Morgan participates in a GCPA panel discussion. | GCPA
The company’s early focus was on Luminant, its competitive generation business. The company began testing employees, primarily at power plants, and discovered “a number” of people with high temperatures. “That made people think, ‘This is really serious,’” Morgan said.
Concerned employees were allowed to stay home without taking paid time off. That created a cultural shift for power plant staff and others, Morgan said.
“Power plant employees want to go to work. They want to be at the plant,” he said.
Luminant added portable washing stations at its plants and tried to socially distance as much as possible. Contractors helping with spring maintenance outages stayed in local hotels and were required to undergo temperature checks before entering the plants’ front gates.
“Those types of things were important to also get contractors to have that same mindset [as staff],” Morgan said. “We got a little pushback, but we told them they would not step on site if they didn’t do the things the way we did.”
Through it all, a staff of 3,000 or so Luminant employees and contractors completed 86 outages without a single plant-related infection.
“I don’t think it’s a coincidence,” Morgan said. He did note a couple of employees tested positive for COVID-19, “but that was because of contact tracing.”
Closer Through Distancing
Oncor took similar early action, dusting off its 13-year-old pandemic plan and implementing it in early January. By March 16, the company reached the highest of four levels and sent everyone home.
Everyone, that is, except the 1,200 or so service staff, line workers and other field employees. Each employee was assigned a vehicle that could be taken home at night and sanitized. Because it moved early, Oncor was able to lease enough additional vehicles and secure personal protection equipment for those in the field.
The company has adapted its processes to the new normal. Safety meetings are now conducted virtually. Employees are no longer shared with other teams, and they have to make appointments at their shops to pick up tools. Backup facilities are used so that as one group finishes its 12-hour shifts, that facility is cleaned during the next 12 hours while employees work out of the primary facility. Catered food is brought to the field, where employees can eat in their trucks.
Nye said only two employees have tested positive for COVID-19 and both have recovered. “That indicates the plan is working very well.
“I had my doubts when we started this,” said Nye, who participated in the panel after an earlier video call with 800 employees. “It’s an entirely different world. We’ve never gone this remote, this virtual, but I’m very pleased with how the technology has held up. We’re all working longer and harder, but overall, I’ve been very encouraged and very relieved that it’s worked out as well as it has.”
Like Nye, Morgan said communications with a virtual staff had held up well. Vistra is attracting as many as 3,000 employees to its weekly live streams, and executives are answering as many as 400 comments after each event. A recent request for pictures of staff’s home offices and their helpers drew hundreds of photos.
“It’s interesting how many people have pets,” Morgan said. “I think our company today is closer than we were prior to this. I like being in the same room with people, but we try to do the best we can with what we have.”
MISO’s margins are tighter and the footprint could face a generation shortfall as early as 2022, but interconnection projects could save the day, according to the annual capacity projection by the Organization of MISO States and the RTO.
The OMS-MISO resource adequacy survey released Friday forecasts 0.8 GW in excess firm capacity beyond the planning reserve margin for 2021. All other years in the five-year outlook contain the potential of a capacity shortfall.
However, the survey still shows greater potential for surpluses larger than any possible deficit through 2025. In addition to the nearly 1 GW near-certain excess in 2021, there’s also potential for a surplus as high as 7.2 GW. And while 2022 could hold a 0.4-GW shortfall, it would see a 11.2-GW surplus if all proposed resources in the interconnection queue were realized.
The best of times, worst of times picture gets starker over the next three years:
2023 could bring a 3.5-GW deficit or 12.5-GW in excess capacity;
2024 could hold a 5.6-GW shortfall or an 11.1-GW surplus; and
2025 might contain a 6.8-GW deficit or a 10-GW surplus.
The survey paints a less rosy supply picture than last year’s assessment. MISO attributed the greater possibility for near-term shortages to a steadily climbing planning reserve margin — upped from nearly 16% in 2017 to about 18% today — and “modest” load growth. Last year’s survey predicted adequate reserves through 2022 and showed MISO’s footprint could experience anything from a 6.8-GW surplus to a 2.3-GW shortfall by 2024. (See Supply Future Brighter, OMS-MISO Survey Shows.)
2020 OMS-MISO survey results | MISO
Speaking at a special conference call to review the results Friday, MISO Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said that since the last survey, some generation completed MISO’s interconnection queue, reducing possible risks, though some zones remain vulnerable. This year’s assessment singled out Lower Michigan’s Zone 7, Southern Illinois’ Zone 4, Wisconsin and Upper Michigan’s Zone 2, and Indiana and western Kentucky’s Zone 6 for the greatest resource adequacy risks. The 2019 survey also called out Zone 7, Zone 4 and Zone 6 for supply risks.
McFarlane also said MISO’s projected annual demand growth rate rose from 0.2% in 2019 to 0.3% this year. He added that the survey also does not contemplate the long-term effects of the coronavirus pandemic.
“Even with the supply risk, we do have a healthy queue, and it looks like zones will be able to firm up resources in the coming years,” McFarlane said. “The range that we have here is a reflection that resource planning is an ongoing process. … In fact, one of the purposes of the survey is to have utilities and regulators react to the risk and plan accordingly.”
Clean Grid Alliance’s Natalie McIntire asked if MISO is considering that it also needs a transmission buildout, especially in the Upper Midwest, to facilitate the generation in the interconnection queue that the RTO is betting will cover deficit risks. “Not only do we need generation in the queue, we need transmission to deliver it,” she said.
Customized Energy Solutions’ David Sapper also asked about the “mass exodus” in the queue last year, when several planned projects were canceled because of high network upgrade costs. MISO had about 100 GW in the queue last year; that has since dropped to about 80 GW.
“I’m not trying to imply that, ‘Everything’s great; we can relax.’ I’m saying there’s enough generation with a high degree of certainty in the queue that can help with risks in these coming years,” McFarlane said. “Certainly, looking out to 2025, there’s some ground to plow in terms of getting to a comfort level in resource adequacy. … The queue does have several projects in advanced stages that could turn potential capacity into committed.”
OMS President Matt Schuerger said the survey is more important than ever as the generation mix changes. This year, MISO said more than 94% of load-serving entities responded to the survey.
MISO will again review survey results with stakeholders during the Resource Adequacy Subcommittee’s July 8 conference call.
MISO confirmed last week that a new rule prohibiting resources on extended outages from offering capacity contributed to the historic spike in Lower Michigan prices in April’s Planning Resource Auction (PRA).
Zone 7 cleared at the cost of new entry (CONE) price of $257.53/MW-day for the 2020/21 planning year that began June 1, while all other zones cleared under $7/MW-day. Zone 7 fell 123 MW short of its nearly 22-GW local clearing requirement and had to turn to other zones for capacity procurement, activating the CONE price. (See Michigan Prices Soar in 8th MISO Capacity Auction.)
MISO’s Zone 7 | MISO
MISO now restricts extended planned outages to a cumulative 90 days in the first 120 days of the planning year — June 1 to Sept. 30 — which it deems the most critical months for demand and loss-of-load risk. Resources that will be unavailable for more than 90 days are disqualified from PRA participation.
MISO Manager of Capacity Market Administration Eric Thoms told the Resource Adequacy Subcommittee on Wednesday that if the long-term outage policy had also been in effect for the 2019/20 PRA, Zone 7 would have fallen short of its local clearing requirement then as well.
Zone 7 also would have come up short by nearly 222 MW, Thoms said. Last year, Zone 7 had a 21.8-GW local clearing requirement and received slightly more than 22 GW from capacity offers and utilities’ fixed resource adequacy plans. However, about 474 MW of capacity wouldn’t have qualified for the auction based on planned outage schedules.
Under the new outage rule, MISO analysis showed a loss of load in Zone 7 occurring one day in six years in 2019. If the zone had not imported capacity this year to meet its local clearing requirement, the risk would have been one day in eight years. MISO adheres to a one-day-in-10-years standard.
MISO adopted the rule after the Independent Market Monitor last year criticized the RTO for allowing a large generator in Michigan to clear the PRA even though it was slated to be on outage the entire planning year. (See Emergencies Prompt MISO to Re-examine LMR Protocols.) Had MISO disqualified the generator from the auction, prices in Zone 7 might have hit $243.37/MW-day instead of the $24.30/MW-day clearing price in 2019, the Monitor said.
Coalition of Midwest Transmission Customers attorney Jim Dauphinais said MISO’s analysis shows the importance of the new rule.
Without a viable alternative on the horizon, MISO will likely extend its settlement agreement for flows on the Midwest-South subregional transmission constraint through early 2023.
“Until there’s a longer-term solution in place … the recommendation is to extend that settlement agreement until Jan. 31, 2023,” MISO Director of Seams Coordination Jeremiah Doner told stakeholders during a Market Subcommittee teleconference Thursday.
Doner said discussions with SPP and the other parties to the agreements on its future are in the early stages.
Parties to the settlement agreement for MISO’s Midwest-South subregional transmission constraint | MISO
Starting Jan. 31, 2021, the settlement may be terminated by any party with a year’s notice. Without a replacement settlement, flows would be limited to MISO’s original 1,000-MW contract path in either direction. The settlement limits MISO to 3,000 MW of flows in the north-to-south direction and 2,500 MW of flows in the other.
Earlier this year, the parties signed a memorandum of understanding that they wouldn’t propose changes to the settlement until Feb. 1, 2022. Doner said an extension until 2023 will buy time for them to explore eventually changing the terms of the agreement.
Stakeholders asked if MISO would consider negotiating an increase in its transfer capability.
“I think it’s fair to say everything is on the table at this point,” Doner said, adding that MISO hasn’t ruled out a transmission project to increase transfer capability between its South and Midwest regions. After completing a special study, MISO last month said it wouldn’t recommend any upgrade to secure more transfer capability to its Board of Directors this year. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)
Doner said that while some aspects of the settlement discussions are confidential, MISO will share what it can with stakeholders in upcoming public meetings.
A two-year extension would keep in place MISO’s current cost allocation for transmission above 1,000-MW flows. MISO’s payments to the other parties for such flows are recovered from market participants through a combination of load ratio calculations and flow-based beneficiary allocations.
The load-based share declined every year since 2016 as the flow-based portion increased. From Feb. 1, 2016, to Jan. 31, 2017, the allocation was 45% load-based and 55% flow-based. From Feb. 1, 2020, to Jan. 31, 2021, the mix is 10% load-based and 90% flow-based. Doner said MISO would keep the current allocation under the extension.
Because of the declining importance of the load-based allocation, some stakeholders said MISO’s next logical step would be to use a 100% flow-based allocation through early 2023.
Doner took no position on the suggestion but noted MISO would have to win FERC approval for a Tariff revision to either change the cost allocation or pursue an extension of the current rate schedule.
“If all of the parties are good with the terms of the agreement, that settlement agreement can continue in perpetuity, essentially,” Donner said. He said the settlement also contemplates an extension of the original terms, with 2% annual cost escalations written in for use of the regional directional transfer.
However, if any changes to the settlement agreement are made before the Jan. 31, 2023, extension is up, it would trigger a requirement to also review the existing rate schedule.
Doner asked for written stakeholder comments on the extension by July 2.
MISO last week said it will file a one-time waiver with FERC to make sure market participants can replace load-modifying resources (LMRs) impacted by the coronavirus pandemic.
Some LMRs that cleared in the Planning Resource Auction in April “may be unable to perform at their full accredited value as a result of COVID-19-related temporary — or, in some cases, permanent — closure of businesses that constitute their LMR assets,” MISO Manager of Capacity Market Administration Eric Thoms said during a Resource Adequacy Subcommittee teleconference Wednesday.
Thoms said market participants that manage a cleared LMR that is directly impacted by the pandemic must attest via email that the asset can no longer fulfill capacity obligations.
If FERC accepts MISO’s filing, those market participants will have the opportunity to use new LMRs with MISO to “bolster their portfolio,” Thoms said.
The waiver won’t allow members to change existing LMR registration records, Thoms said. Instead, market participants must make a replacement registration in MISO’s capacity tracking tool. That way, the RTO will have an “audit trail of replaced LMR resources and modified underlying assets,” Thoms said.
MISO plans to make the filing this month and will ask the commission for a July 1 effective date. From there, market participants will have 90 days through September to register replacement LMRs.
Usually, MISO market participants must register existing LMRs by Feb. 1, new LMRs for use in fixed resource adequacy plans by Feb. 15 and new LMRs not used in fixed resource adequacy plans by March 1 for the upcoming planning year.
“We’ll have an ability to reassess the effects of the pandemic after 90 days,” Thoms said, adding that MISO will have the “option to request a renewal of the waiver” if the pandemic is still affecting LMRs’ ability to respond.
But stakeholders argue that MISO isn’t considering the full gamut of difficulties wrought by the pandemic.
Xcel Energy’s Kari Hassler asked how the waiver could help a large LMR that permanently closes, taking with it both load and some measure to control it.
Thoms said MISO isn’t currently considering any reductions in planning reserve margins from load losses caused by the pandemic.
Multiple stakeholders argued that reserve margins should also be lowered because the load that needed to be curtailed no longer exists.
“I agree that there’s a mismatch here,” Customized Energy Solutions’ Ted Kuhn said.
Thoms said MISO does not yet know what LMR closures might be temporary or permanent.
“We have a financially binding construct that is already settled,” he explained. He also said impacted market participants are not obligated to use the waiver and can instead notify the RTO through the MISO Communications System that their LMRs are less available. LMRs are required to respond to at least five emergency events per year.
Alliant Energy’s Mitch Myhre said his utility has had difficulties even performing the MISO-required LMR testing, as some large commercial and industrial customers haven’t been operating as usual. Other stakeholders said they were experiencing similar testing difficulties.
This is MISO’s second filing for a waiver of Tariff requirements in response to the pandemic. FERC granted the RTO’s request for a 60-day extension of its June 25 site control demonstration deadline late last month as the pandemic slowed construction and shuttered government offices (ER20-1794). (See “Queue Waiver Request Before FERC,” Wary of Contagion, MISO Bars Visitors for 2020.)
