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October 27, 2019

MISO Taking Pains to Prepare for Moderate Winter

By Amanda Durish Cook

CARMEL, Ind. — MISO is preparing for emergency conditions this winter despite projecting 40 GW of excess capacity to meet the forecasted peak in January.

“MISO does have adequate resources for the upcoming winter under normal operating conditions,” Executive Director of Energy Operations Rob Benbow told stakeholders during an Oct. 22 winter readiness workshop.

The RTO says it has 143 GW in total available capacity to meet demand. It anticipates a comfortable 37% systemwide reserve margin this winter, more than double the 17% target.

Its latest winter peak forecast is 104 GW, 5 GW below the all-time winter record set Jan. 6, 2014, during the polar vortex. Peak and capacity predictions are similar to last year’s forecasts. (See MISO Foresees Manageable 2018/19 Winter.)

Relying on data from the National Oceanic and Atmospheric Administration, the RTO expects slightly warmer than normal conditions in MISO South and “pockets” of the MISO Central region, Resource Adequacy Coordination Engineer Eric Rodriguez said.

Possibly Hazardous January

But the generous supply only applies if everything goes smoothly, and MISO executives warned that the RTO could once again call wintertime emergencies. Benbow said MISO runs the risk of entering emergency procedures if temperatures dive and outages soar. The risk is most pronounced in January, where a worst-case scenario shows the RTO burning through all its 12.3 GW of load-modifying resources (LMRs) and operating reserves and still coming up almost 9 GW short.

Even in a probable generation scenario with normal load levels, MISO might still have to make an emergency declaration to call up LMRs. The RTO also said it could experience almost 6 GW of stranded capacity this winter.

Benbow said the risk is “not surprising considering the last two Januarys.”

“A combination of both high load and high outages would present challenges in reliably operating through the upcoming winter,” MISO said.

Increasing forced outage rates have been a “major driver” for emergency declarations in recent winters, the RTO said. MISO experienced about 45 GW worth of outages during the January 2019 maximum generation event and about 40 GW during its January 2018 event. (See MISO Details ‘Uncertainty’ Behind Winter Max Gen Event.)

MISO also reported that Midwest natural gas storage levels are at or above the five-year average because of amplified production.

The transmission system is also in relatively good shape to handle winter loads, staff reported. Engineer Benny Relucio said that MISO found no transmission constraints that don’t already have mitigation plans in place. In a thermal transfer analysis, MISO found two areas of concern: the Dumont-to-Wilton Center east-to-west transfer in northwest Illinois, and the Midwest-to-South transfer in either direction. MISO said it could be in violation of the lines’ transfer limits if certain nearby lines go down.

Cold Weather Prep

MISO Senior Adviser Eli Massey also said many generation owners have reported erecting temporary or permanent structures around “cold-weather-susceptible components” and have either improved existing — or added new — heat-tracing capabilities at plants.

But Massey said data from MISO’s annual winterization survey shows “a tipping point” when temperatures drop below -20 degrees F. At such subfreezing temps, all resource types are susceptible to shortages.

ReliabilityFirst engineer Tim Fryfogle, tapped by MISO to give a winter preparedness presentation, shared best practices with stakeholders. Among the most important steps generation owners can take are erecting wind barriers or enclosures and installing heaters to protect certain components, he said. “Keeping wind, snow and cold out of critical components is crucial.”

Fryfogle recommended remote monitoring from the control room of transmitter enclosures and more frequent operator rounds once the temperature dips to a certain point. He also suggested staff meetings to discuss lessons learned from past winters and comprehensive, pre-winterization walk-throughs of entire facilities, as well as assigning “dedicated individuals to monitor critical areas.”

2019 Improvements

Wintertime talk included a look-back at the historic extreme cold that gripped the Upper Midwest last year as January turned to February and the early 2018 arctic blast that nearly sent parts of MISO South into load-shed.

MISO Director of Central Region Operations Ron Arness said the RTO has learned from its past two years of weathering cold snaps. “We did see a need to update our wind forecasting,” he told stakeholders.

Arness said MISO has now added cold-weather cutoffs for wind generation in its forecasting, and it accounts for some voluntary facility closings when temperatures are extremely low. “We’re trying to be more proactive when we forecast events.”

MISO has also been working with its generator operators to make sure expectations are clear for capacity warnings and how to best handle making a public appeal for energy conservation.

“Not too long ago we didn’t have to worry about generation capacity. Now we do,” Arness said.

The RTO so far has termed its short-term resource availability and need fixes a success, reporting that stricter generation outage rules, better LMR availability reporting and annual real power testing for demand response have resulted in 5 to 10 GW of additional availability during times of need.

For the upcoming winter, MISO said it expects to have about 9.5 GW worth of increased availability and that response times should be shorter when it calls on LMRs. This is the first winter in which LMRs will be required to respond to emergencies outside the summer months.

More Winter Procedures to Come?

MISO used the workshop to provide an initial reaction to FERC’s recent recommendation that RTOs adopt a multifaceted cold weather reliability standard. (See FERC Calls for Cold Weather Reliability Standard.)

The RTO said it has so far completed a “preliminary evaluation” of the recommendation and concluded it already follows more than half of the practices FERC advised. Director of Seams Coordination Jeremiah Doner said the RTO believes it already complies with some recommendations on emergency drills, improved reserve deliverability and information sharing with neighbors on expected flows on the regional dispatch limit.

But Doner promised more work and communication with its neighbors on how to best coordinate use of its Midwest-South regional transfer limit with SPP after some stakeholders have criticized MISO for using an overly conservative summer line rating for the constraint in the middle of January.

Doner also promised more work on communication about challenging operating conditions with SPP and the Tennessee Valley Authority, and deeper seasonal assessments with SPP, though he said MISO had already improved communication with its southern neighbors between the January 2018 emergency and last January’s emergency, resulting in smoother coordination.

MISO will also ensure its load forecasting process is as “robust as possible” and is currently researching how its neighbors forecast load, he said.

He told the Organization of MISO States in August that the RTO hadn’t found any recommendations in the FERC report that are “overly burdensome or complex.”

In the wake of the 2019 cold snap, the state of Michigan asked MISO to improve how it manages the system during extreme weather, after portions of the state only avoided load shedding through utilities asking consumers to turn down thermostats to reduce heating demand.

In a September letter to MISO, Michigan Gov. Gretchen Whitmer and Public Service Commission Chair Sally Talberg called on the RTO to improve its DR process, speed up its generator interconnection queue, evaluate another long-term transmission package, put more focus on distributed resources in the MISO-OMS annual resource adequacy survey and increase transmission import capability between Michigan’s peninsulas.

The state also recommended MISO improve its gas-electric coordination and emergency preparedness.

“The increased reliance on natural gas generation for electricity and the fire at the Ray gas storage facility occurring at the same time as MISO’s declared emergency all highlight the need for improved coordination between electricity and natural gas systems during emergencies,” Whitmer and Talberg wrote.

Michigan’s recommendations were among the 37 recommendations resulting from a statewide energy assessment the PSC undertook following troubles brought on by the extreme cold. (See Mich. PSC Urges Changes After Winter Emergency.)

October 27, 2019

Offshore Wind Leaders: Future is Now in the US

By Michael Kuser

BOSTON — Federal and state officials joined offshore wind developers last week in giving about 60 members of the Environmental Business Council of New England (EBCNE) an upbeat update on the nascent U.S. offshore industry.

The following is some of what we heard Oct. 22 about a burgeoning sector that has about 19 GW of projects in view, more than 80% of today’s total global installed capacity of 23 GW.

Learning the Process

“We couldn’t be more excited to be deploying a real climate change solution that also has these benefits in terms of job creation, economic development and securing a clean energy resource,” Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides said. “Offshore wind also coincides with our winter peak in terms of demand and gets us away from some of the higher-priced, dirtiest resources in our energy mix.”

New England Offshore Wind — Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides speaks on offshore wind energy issues to the Environmental Business Council of New England on Oct. 22 in Boston. | © *RTO Insider*

The state’s strategy focuses on energy efficiency, cleaning up the energy supply and electrifying the transportation and building sectors, she said.

“While it has been a stressful summer in terms of the federal permitting side … we are learning about the permitting process and helping the rest of the industry understand what those steps are going to be,” Theoharides said.

offshore wind — Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides | © *RTO Insider*

New England renewable energy advocates in September expressed skepticism about federal officials’ claims to be acting in the public interest by delaying the final permits for the 800-MW Vineyard Wind project off the coast of Massachusetts. (See Renewable Backers Decry Vineyard Wind Delay.)

The U.S. Bureau of Ocean Management announced in August it would delay issuing the final environmental impact statement for the project in order to conduct an expanded analysis of “cumulative impacts.”

Massachusetts officials in “a couple of weeks” will announce winners of the state’s second solicitation for up to 800 MW in additional offshore wind energy, Theoharides said.

Federal Commitment

James Bennett, program manager for renewable energy at BOEM, highlighted the “massive change” in offshore wind development caused by Equinor’s $42 million lease in the New York Bight in 2016.

“Everybody turned their head and said, ‘Oh my God, this is for real,’” Bennett said, noting that deal was followed by a lease off North Carolina and another off Massachusetts, where three areas auctioned for $135 million apiece last year after being left on the table two years earlier. (See Mass. Offshore Lease Auction Nets Record $405 Million.)

BOEM now has 15 leases up and down the East Coast, he said.

“Do we have steel in the water? No, but next year we’re going to have actual steel in the water off of Virginia and hopefully very soon after that up here in Massachusetts,” Bennett said.

“The next decade is very promising,” he said. “We are looking at additional leasing off of New York … and we’ve been working on our regulatory processes, refining them and streamlining them so we can move as quickly as possible with the lessons that we’re learning over time. And, of course, the state offshore wind procurements are phenomenal in making sure that there’s plenty of support in moving forward, and industry continues to demonstrate its commitment.”

Bennett said that while his agency has been handling offshore wind leases state by state, it nonetheless favored a regional approach. He mentioned that the Gulf of Maine Intergovernmental Renewable Energy Task Force, organized by BOEM with the participation off Maine, Massachusetts and New Hampshire, will hold its first meeting on Dec. 12.

“We’re all committed to getting this right,” Bennett said. “The [permitting delay] is not the first bump in the road, and it’s not going to be the last. We’re going to have more over the next decade with potentially 12 projects being put in place up and down the East Coast. We’re going to run into issues like transmission, like ports, like construction vessels … and we’re going to deal with them.

“At BOEM, we’re going to work through this issue and we’re going to make it work, and we’re going to have the stakeholders and the developers and the government, both federal and state, work together to come up with solutions,” Bennett said.

Robert LaBelle, a retired associate director at BOEM, is now helping his home state of New Hampshire prepare for the three-state panel organized by the agency to pursue development of offshore wind in the Gulf of Maine.

“I spent a lot of years doing ocean planning, and now that I’m just a free citizen of New Hampshire, I’d like to see some ocean doing, so I’m recommending that all you folks who are in a position to make a difference reconsider your commitment to working collaboratively,” LaBelle said.

‘Great Expectations’

“I’m driven by fundamental trends [and] am concerned on behalf of my children about climate change and global warming and what it will do,” Vineyard Wind CEO Lars Pedersen said. “I have seen this industry transform from a technology-driven niche … into a big business.”

Lars Pedersen, Vineyard Wind | © *RTO Insider*

Pedersen recalled planning bids in Europe in 2012 when someone proposed aiming for 100 euros/MWh as a goal for 2020.

“We were way off: It happened much, much quicker than we thought, and it’s because the fundamentals are really good for this industry,” Pedersen said. “And, also, the fundamentals are really strong here in the Northeast. You have high winds offshore, shallow water, good seabed, a lot of people living on the coastline, and you’re transforming your energy system away from fossil and nuclear plants into renewable energies.”

Bloomberg New Energy Finance projects offshore wind costs of 64 euros/MWh by 2020 and 60 euros/MWh by 2025.

A joint venture between Avangrid Renewables and Copenhagen Infrastructure Partners, Vineyard Wind in August bid for the second Massachusetts solicitation by offering several options on up to 800 MW of additional offshore wind.

The state leaders have done their job, as has the team at BOEM, but now it’s up to the industry to develop offshore wind, said Matthew Morrissey, head of New England markets for Ørsted US Offshore Wind, which also bid in the second solicitation.

Matthew Morrissey, Ørsted US | © *RTO Insider*

“There are great opportunities that come from a new industry in America. There are great expectations,” Morrissey said. “Offshore presents a very compelling case for the development of clean energy at scale to deal with the problem we have now replacing fossil generation coming offline,” and also reinvents the old maritime ports along the Eastern seaboard, he said.

Stephen Pike, CEO of the Massachusetts Clean Energy Center, recounted a day in 2014 when it became apparent that the Cape Wind project would not be moving forward, and a couple state officials thought the failure set the industry back at least 10 years.

“To think that we would be standing on the statehouse lawn less than two years later watching the governor sign that first-in-the-nation path to market legislation was really remarkable,” Pike said. “Never mind that the law set up an actual solicitation that less than two years after that ended up with a project whose pricing was way below what anyone could have imagined even six months prior to that.” (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)

The agency is now focused on developing the supply chain and workforce training, Pike said.

Fast Enough?

Curtis Spalding, Brown University | © *RTO Insider*

“Two degrees is in the rearview mirror,” said H. Curtis Spalding of the Institute at Brown for Environment and Society. The former EPA regional administrator for New England during the Obama administration was referring to the temperature increase threshold (equivalent to about 3.6 F) to reaching irreversible climate change.

“There’s too much to do and too short a time to stop the temperature from rising 2 degrees,” Spalding said. “What does that mean? That means climate change is going to affect and cascade so many parts of our community going forward.”

Seth Kaplan, Mayflower Wind | © *RTO Insider*

After two major flooding events, the threat from climate change is felt more in Houston than it is in New England, he said. “The context is going to shift.”

Seth Kaplan, director of permitting and development for Mayflower Wind, came to the joint venture between Shell New Energies and EDP Renewables after working five years at the latter firm planning onshore wind and solar and before that, 16 years at the Conservation Law Foundation.

“It’s hard to avoid the conclusion that the renewable energy industry isn’t aggressive enough,” Kaplan said. “If you look at the world through a climate frame, we need to build so much so quickly in order to meet our climate goals, that the strictures and barriers that are just the normal stuff of business are annoying if you’re trying to meet those goals.”

October 27, 2019

OMS Panel Debates Merits of MISO-SPP Seams Projects

By Amanda Durish Cook

NEW ORLEANS — At the Organization of MISO States’ annual meeting last week, where MISO-SPP seams needs took center stage, North Dakota Public Service Commissioner Julie Fedorchak set the tone by opening a panel with a pun.

“We’re bursting at the seams,” she said, then drummed a “ba-dum-tsh” beat on the podium.

American Wind Energy Association and Advanced Power Alliance’s Steve Gaw commended state regulators for bringing attention to the seam this year. He said the discussion has earned FERC’s attention and is stimulating action at the federal level.

“It’s immensely helpful to understanding the future and where we’re going,” he said during the Thursday meeting. “The bottom line is, if you don’t do robust planning, you won’t have the idea of where the needs are.”

“We’re not seeing the interregional planning process as effective as we’d like,” Clean Grid Alliance’s Natalie McIntire added.

MISO has never recommended an interregional project with SPP, while it’s close to embarking on its first major interregional transmission project with MISO, PJM Poised for 1st Major Interregional Project.)

OMS — Natalie McIntire, Clean Grid Alliance | © *RTO Insider*

But Entergy’s Charles Long said too little is known about future transmission use patterns to build a major MISO-SPP interregional project. He urged the RTOs to develop market-to-market efficiencies first.

“What really concerns me about the seams is the thinking that we need to build our way out of it. … Our big concern is that we would fund transmission that in five or 10 years won’t be useful,” Long said. “To make the assumption that every problem can be fixed by transmission is the wrong assumption. We’re getting to the point of diminishing returns on transmission.”

Long also argued that if electric vehicle adoption takes off, the distribution system will need upgrades and buildouts “far before” the transmission system will.

OMS — Charles Long, Entergy | © *RTO Insider*

Long’s arguments reiterated those his company recently made in response to the MISO and SPP market monitors’ solicitation of stakeholder feedback on the interregional processes. (See related story, “Entergy Comment on Seams ‘Raises Eyebrows,’” MISO, SPP States Ponder Look at Interregional Planning.)

His arguments found traction with other panelists.

“You should eat your peas before you have dessert,” agreed NRG Energy’s Travis Kavulla. He encouraged RTOs and utilities to first make software upgrades and create “closer automation between two systems” before moving to “fancy new capital assets.”

Kavulla said the country’s regulatory framework is generally bad at forcing utilities to leverage their existing capital assets for more efficiencies.

But McIntire said the future is clear: more renewable generation.

“MISO says its greatest asset is its footprint diversity. And if that’s true, footprint diversity should extend to the seams to have this sort of mutual aid society,” McIntire said.

OMS MISO SPP seams — Travis Kavulla, NRG | © *RTO Insider*

Long said it’s worth remembering that MISO and SPP have completed a lot of analysis already on possible seams projects.

“If you want the yardstick to be how many seams wires to go into the air, then you could say it’s slow. But I think you have to be careful in how you measure success. You need to measure twice and cut once,” Long said.

Gaw disagreed, saying the RTOs are moving too slowly, and with a flawed planning process that assumes some transmission projects will be ticked off through needed upgrades in their generation interconnection queues.

“You end up with something that generators have to pay for that benefits load. And because it’s so expensive, it doesn’t get built at all. Is that the kind of outcome we want?” Gaw asked.

Market Study Results Soon

OMS Executive Director Marcus Hawkins acknowledged “several” members of the RSC and thanked them for their attendance.

The first round of the groups’ seams studies focuses on rate pancaking and unreserved transmission use charges, the market-to-market process and the RTOs’ lack of joint dispatch in energy markets — all elements that might frustrate market efficiencies between the RTOs.

Both monitors have so far found limited benefits.

Last month, MISO Independent Market Monitor David Patton said he was encountering “a snag” preventing him from securing offer data from SPP in order to complete his side of the analysis. At Thursday’s meeting, Patton said he was still having “data issues.”

Another issue arose when the IMM requested confidential market participant information that, according to the SPP Tariff, can only be shared with permission of affected market participants. Patton since revised the data request to more limited information. SPP said it’s willing to perform an analysis of its own data under the direction of the IMM, if necessary.

SPP Market Monitor Unit Executive Director Keith Collins said he is examining rate pancaking and unreserved transmission use charges essentially functioning as taxes.

“Are the imposition of costs acting like taxes that are barriers, or are they acting like taxes that provide a societal good?” he said.

But so far, the costs seem too low to bother with.

Collins said MISO and SPP’s rate pancaking issues are moot because both RTOs offer heavily discounted, “near-zero-cost” spot-in transmission service for imports.

“The reality is that most of the rate pancaking has been addressed by market import spot-in service,” Collins said. “Because most non-firm import transactions are already exempt from transmission charges, there is little to no market efficiency to be gained by the further removal of the additional transmission service charges across all import transactions.”

Collins said there have been no unreserved use charges levied against MISO members by SPP in the past two-and-a-half years and only “minimal” charges from MISO to SPP in 2017 and 2018. He also said he’s aware the RTOs’ transmission customers take “cost-avoidance measures” so they aren’t charged for unreserved use.

Patton said a joint dispatch stands to drastically increase power imports from SPP to MISO with only “modest” production cost savings on both sides of the seam.

“These are initial results that are subject to be iterated and improved,” Patton caution. He also noted that the production cost models he uses represent a “highly idealized” version of the RTOs that doesn’t take into account all transmission constraints, “lumpy” outage planning and other operating realities.

Patton also welcomed more ideas on what the monitors should study. “If there are participants or states here that think there are issues that haven’t been looked at, please let us know,” he said.

McIntire said that while there might be few market efficiencies to be gained by their removal, pancaked rates present “a real barrier” to moving low-cost renewable energy across the seams. She also asked that the Monitors not rely solely on a 2018 model to conduct the study but make future assumptions.

October 27, 2019

PJM MC/MRC Preview: Oct. 31, 2019

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Consent Agenda (9:10-9:15)

PJM will ask for endorsement of:

B. Revisions to Manual 14D: Generator Operational Requirements, including a periodic cover-to-cover review and proposed language changes regarding compliance with FERC Order 841 for energy storage participation.

C. Changes to Manual 36: System Restoration and Manual 40: Training and Certification Requirements regarding Order 841.

D. The 2019 Reserve Requirement Study results, including updated values for the installed reserve margin and forecast pool requirement, which will reset key parameters for the RTO’s upcoming capacity auctions. (See “2019 Installed Reserve Margin Study Results,” PJM PC/TEAC Briefs: Oct. 17, 2019.) If approved, the Members Committee will also be asked to endorse the same day.

1. Load Management Testing Requirements (9:15-9:30)

PJM will seek approval of a modified proposal to update load management testing requirements.

The RTO, which said it wants testing procedures to more closely mimic reality, is proposing a three-step notification system that gives resources first notice two weeks ahead, with additional alerts the day before and the morning before. Resources that fail would be retested within 46 days. There will be one test per year when there is no event, with half of resources tested in winter and the other half in summer.

At last month’s MRC meeting, stakeholders advised the RTO to find a compromise with Enel X, the sponsor of a competing package. (See “Stakeholders Urge Consensus on Load Management Testing Requirements,” PJM MRC/MC Briefs: Sept. 30, 2019.)

Stakeholders expressed concerns about how PJM would fit retests into the same season, as well as the usefulness of a month-ahead notification. Enel X had suggested instead a week-ahead alert to capacity resources. (See PJM Stakeholders Support More Realistic DR Testing.)

The current rules, developed when demand response availability was limited to just six hours a day over the summer, require one test during the summer. They give resources a two-day warning — down to the exact hour — and provides unlimited retesting. Enel X had contended that PJM’s original month-ahead notice provided little useful information to resource owners who operate on a week-ahead timeline. It was also uncertain how PJM would manage retests.

– Christen Smith

October 27, 2019

AEP Beats Expectations with Strong Q3

American Electric Power’s third-quarter figures beat expectations with earnings of $734 million ($1.49/share), up from $578 million ($1.17/share) over the same period in 2018. Operating income was $722 million ($1.46/share), against Zacks’ consensus estimate of $1.33/share.

The company said the difference between GAAP and operating earnings was driven primarily by the mark-to-market impact of economic hedging activities.

CEO Nick Akins told financial analysts Thursday that the company’s overall load is “making a comeback.” Industrial sales, driven by oil and gas production in Oklahoma, were up 3.4% during the quarter, and the footprint’s GDP grew at a 2.4% rate, ahead of the 2.1% national average, AEP said.

“I think you’re seeing some resiliency from an industrial and manufacturing standpoint. You’re starting to see it pick up,” Akins said. “We’ve got the oil and gas activity going gangbusters. … There’s no question people have more money in their pockets and people have more jobs. That’s reflected in what we see.”

The Ohio-based company increased and narrowed its 2019 operating earnings guidance range to $4.14 to $4.24/share, up from $4 to $4.20/share and reaffirmed its long-term growth rate of 5 to 7%. AEP’s share price is up 26.4% since the year began, beating the S&P 500’s 19.9% pace.

Wall Street greeted the news by driving the share price up 75 cents to $95.74 in after-hours trading.

— Tom Kleckner

October 27, 2019

Clashing Visions of the Grid on Display at OMS Meeting

By Amanda Durish Cook

NEW ORLEANS — MISO executives and some of its state regulators last week provided sharply contrasting visions of the grid’s move away from fossil fuels and toward renewables.

MISO President of Market Development Strategy Richard Doying arrived at the Organization of MISO States’ annual meeting in the Big Easy to discuss the RTO’s 2019 Forward Report, which concluded that market changes are necessary as the RTO footprint experiences demarginalization, decentralization and digitalization. (See New MISO Report Starting Point for Major Grid Change.)

MISO grid OMS — Richard Doying, MISO | © *RTO Insider*

The RTO had only about 400 MW of wind in 2007, CEO John Bear said. Doying noted it is now nearing 20 GW of wind generation in its mix, which can have zero marginal costs.

“That is the right economic price, but it’s terrible for baseload generation,” Doying said.

MISO’s generation interconnection queue currently contains 59 GW of solar projects and 27 GW of wind projects.

But 15 years ago, coal was king in the footprint, holding more than 75% of the generation mix; now MISO predicts that share will drop to less than 25% by 2030.

But Kentucky Public Service Commissioner Talina Mathews offered a starkly different picture. She said her state, with its continuing flat loads and lack of a renewable portfolio standard, still seems perfectly happy with 94% of its energy needs being supplied by coal and natural gas.

Kentucky doesn’t yet see a need to add renewable generation, Mathews said. For customers that do want renewable energy, she pointed out that western Kentucky, as a MISO member, can access other states’ renewable generation.

“We’re seeing change come more slowly,” she said. And as far as those “green kilowatt-hours? We’re going to sit back and let that come to us.”

“Would some people say my head is in the sand?” she mused. “Maybe.”

But many of Kentucky’s residents simply can’t afford to think about clean energy, Mathews said. To them it doesn’t matter “what color the kilowatt-hours are” as long as they come cheap.

“When your home is a pre-1970s trailer with resistance strip heating, you can’t respond to [energy] market signals,” she said, adding that many in Kentucky’s formerly booming coal country are barely scraping by.

“We have counties that are at 12% [unemployment],” Mathews said. “We have counties that are taking the hit for other people’s energy decisions. And that’s fine. That’s how economies move.”

Minnesota Public Utilities Commissioner Matt Schuerger offered yet another view. He said while renewable adoption was stimulated in the beginning by state renewable targets, they’re no longer a catalyst in 2019.

“We’ve moved beyond that several years ago. In fact, most utilities met these goal several years early,” Schuerger said.

Arkansas Public Service Commission Chairman Ted Thomas argued that energy innovation isn’t a one-step process and markets are best positioned to encourage and accommodate the series of steps — not a federal rule.

“Imagine if we still had the Clean Power Plan. You would have state policy in response to federal mandates clashing with” FERC rules, he said. Storage remains the most potentially disruptive technology that is close to mass deployment, he said. Consumer-oriented demand response is a close second.

Thomas said he agreed with Supreme Court Justice Oliver Wendell Holmes Jr.’s position that laws should be written with the “bad guy” in mind, or the one person that will try to exploit the law for personal gain. He said that advice should be carefully considered when states target certain levels of fuel mix diversity.

“There’s going to be some ‘slick’ that is going to free-ride. That’s human nature,” Thomas said.

He also said the manner in which decentralized generation is adopted remains debatable: “There’s a lot of talk that we’re going to be decentralized, but the question is how — decentralized at scale or decentralized on rooftops?”

Doying took notes during the exchange; MISO plans to release an updated version of its Forward Report in 2020.

October 27, 2019February 12, 2025

Carbon Pricing Vital to NY Goals, Study Author says

By Michael Kuser

TROY, N.Y. — The state must put a price on carbon in its wholesale electricity market if it hopes to meet the aggressive timelines of the decarbonization goals set out in a new law, the co-author of NYISO’s carbon pricing study told stakeholders last week.

“If New York does not do this in the electric-sector engine that the law hopes to rely upon to decarbonize the economy, it’s tying two hands behind the state’s back,” Analysis Group’s Sue Tierney said on Oct. 22 in delivering a summary of the study to NYISO’s Installed Capacity and Market Issues Working Group (ICAP/MIWG). “You will not get the efficiency, or timing, or depth, or pace of change without having this electric system engine on acceleration to get it.”

Delivery of the long-awaited study was delayed a couple months to perform additional analysis on the impacts of the Climate Leadership and Community Protection Act (CLCPA), signed into law in July by Gov. Andrew Cuomo. Among other provisions, the law requires 70% of the state’s electricity to be generated by renewable resources by 2030 and the whole economy to be carbon-neutral by 2040. (See NYISO Study: Carbon Charge to Help NY Climate Goals.)

“It’s going to be really hard to meet the new goals in the CLCPA, even with a carbon price. It’s going to be really hard, so the state should be relying on every tool it can to get the job done,” Tierney said.

Implications of the CLCPA for entry of renewables and zero-carbon resources in New York | Analysis Group

NYISO stakeholders took a fine-tooth comb to the final version of the carbon pricing study at the ICAP/MIWG meeting, posing dozens of questions to Tierney.

“Is there a threshold size of the [decarbonization] solution that needs to come from carbon pricing, or is it linear, like you can have as little as 1% of it being accomplished through carbon pricing, or 99%?” asked Aaron Breidenbaugh, representing Consumer Power Advocates.

“I don’t think there’s an engineering or an economic answer to that because we’re going to be surprised, happily surprised, by a market solution,” Tierney said. “Introducing a carbon price will create a dynamic effect, which in turn will produce results later on, and the results will affect things that happen after that.”

Market Efficiencies

The report said the literature on organized wholesale markets indicates carbon pricing will produce a 1 to 3% efficiency improvement in the overall capital and operating costs of the wholesale electric system.

“Applying that range of market efficiency benefits to the above-market cost analysis, we estimate a benefit to New York consumers in the range of $280 [million] to $850 million, net present value, for a baseline scenario running from 2022 to 2036,” Tierney said. The baseline refers to the NYISO Gold Book forecast of baseline demand, she said.

“What is the 1 to 3% supposed to be capturing?” asked Howard Fromer, director of market policy for PSEG Power New York. “In a world that had the social cost of carbon reflected in LMPs, one would expect LMPs to trend higher to capture that cost in a marginal unit, to the extent that fossil is that marginal unit. I would expect that as that percolated through the electric system … you would see people doing things differently, being more active in efficiency opportunities as prices were higher. I assume some elasticities. … Is this 1 to 3% capturing that kind of benefit?”

Tierney provided an example: “If one did a long-term renewable energy credit procurement as the only approach to meeting the requirements of the CLCPA, then an owner of a fossil unit … might decide that the next dollars it might consider spending on operations and maintenance to keep that plant the most efficient one are not worth spending. The market would be telling that owner that it would be stupid to invest in such efficiency. This [1 to 3%] is meant to capture the other things going on.”

Mark Reeder, representing the Alliance for Clean Energy New York, said he assumed that carbon pricing would have negligible effects on energy efficiency, as residential retail prices would go down.

“There is no increase in energy conservation in homes from a program that results show the prices are in fact going down,” Reeder said. “Maybe you could have done an offset to your $280 million and go down another 15 [million dollars] and say it’s $265 million, but we keep forgetting the result … is customer prices go down. The customer impacts are quite near zero, but on net, the prices go down.”

Reeder questioned the premise of getting the 1 to 3% coming from the dispatch: “Most of the literature about going to deregulation was that it would increase efficiencies in terms of people’s investment decisions, in terms of their maintenance decisions. I would think the bulk of the 1 to 3% is in the investment decision to extend the life of your plant, to make your gas plant more efficient. None of those are dispatch efficiencies.”

Tierney disagreed. “There will be also dispatch efficiencies, along with the other types of efficiencies,” such as investments to make individual plants more efficient and others that reflect a shift of risk from consumers to owners of generation and transmission, she said. “So the dispatch efficiencies will be reflected in the new portfolio of resources [that] results from the new investment signals, including locationally in New York. Our 1 to 3% is meant to cover all of those types of things.”

Transmission Differentials

“We include in the value proposition that the carbon price would send signals for transmission as a result of a differential in LMPs, upstate and downstate,” Tierney said. “We also said that part of the value proposition here would be more direct signaling about the value of adding demand and supply resources in downstate New York, where most of the load occurs and where the prices would be higher.”

One of the benefits listed in the report has to do with transmission buildout, which NYISO has already documented as essential to New York meeting its aggressive goals, Fromer said.

“There is simply no way we’re going to make a dramatic dent in carbon reduction unless more transmission is built in the state,” Fromer said. “To what extent does the 1 to 3% benefit capture the difference of a likelihood of transmission buildout in a world where you’re moving $30 power to a $35 market, versus $30 power to a $55 market? How do you get the public to accept spending a billion dollars for a line that’s saving hardly any money?

“What is the logic that you get more transmission built from upstate to downstate unless you’re reflecting the carbon benefit of that transmission in the price — and is any of that in the 1 to 3%?”

Tierney said she didn’t think so. “Based on the literature review, that has not been called out as a specific issue. I think that is a powerful advantage of the NYISO’s carbon-pricing proposal, putting a price signal on transmission.”

Fromer said that raised the issue of whether the state would get more carbon reductions by just relying on REC contracts.

“One of the concerns with the [CLCPA] is … you might not get carbon reduction from some of the renewable additions upstate because the load being reduced would have been using renewables anyway, and you don’t have the lines to move the surplus power downstate,” Fromer said. “Even though you’re spending a lot of money, you’re displacing other pre-existing carbon-free energy.”

“I agree. … When we did our buildout scenarios and estimated the above-market costs that one might expect as a result of the CLCPA, which was the lump of money from which we said that you could expect to get 1 to 3% in efficiency savings, we included no transmission investment in that,” Tierney said. “We did include one scenario [that] assumed that all of the offshore wind dumped into New York City, so that higher cost is reflected in part in there.

“In order to actually get the carbon reductions, there has to be a demand forecast that reflects electrification of buildings and vehicles, including in downstate New York, where most of the state’s demand is located, and that has to include getting the power to where people live,” she said.

October 27, 2019

ISO-NE Planning Advisory Committee Briefs: Oct. 24, 2019

ISO-NE will add five buses to the bulk power system list and remove seven others for various reasons, the Planning Advisory Committee learned on Thursday.

Dan Schwarting, lead engineer for transmission planning, presented the BPS list updates to the PAC and said reasons for the additions include planned transmission upgrades, changes to protection schemes, and a reduction in inertia in Nova Scotia and New Brunswick.

Two of the additional buses were previously identified as BPS in the proposed plan application (PPA) for the Southeast Massachusetts/Rhode Island (SEMA/RI) transmission upgrades, and all five were identified in the 2019 BPS assessment report.

Reasons for the seven bus removals include generation retirements, dynamic model changes and other system changes since 2016, Schwarting said.

Four buses were previously identified as new BPS in the PPA study but will not be added to the BPS list. All seven buses were identified in the 2019 BPS assessment report.

The Northeast Power Coordinating Council requires the identification of buses that are part of the BPS, with some NPCC criteria applying only to BPS buses or BPS elements, including Directory 1: Design and Operation of the BPS and Directory 4: System Protection Criteria.

BPS classifications are determined through a performance-based test, as described in NPCC Document A-10.

RSP Transmission Projects and Asset Conditions

New England saw cost increases of nearly $200 million on 11 transmission projects between June and October 2019, according to Brent Oberlin, the RTO’s director of transmission planning, who presented on Regional System Plan transmission projects and asset conditions.

Eight of the projects were in the Greater Boston area and had a combined cost increase of $157 million, which Eversource Energy attributed to “actual construction bids coming in higher than estimated costs, lengthy and extensive permitting, and restrictive permitting conditions,” Oberlin said.

Investment of New England transmission reliability projects by status through 2023 | *ISO-NE*

The other three projects all were in the Seacoast New Hampshire Solution, in the Madbury-Portsmouth area, and experienced a combined cost increase of $40 million, which Eversource also attributed to actual construction bids coming in higher than estimated costs, lengthy and extensive permitting, and restrictive permitting conditions.

“This can’t keep happening; the estimates have to get more accurate,” said Dorothy Capra, director of regulatory services at the New England States Committee on Electricity. “You don’t want to keep upsetting state regulators.”

Eversource representatives at the meeting said they would be prepared to answer questions on the cost overruns in more detail at the PAC meeting in November.

There were no new projects since the June 2019 update, but three upgrades on the project list have been placed in-service, including two in Greater Boston and one in Greater Hartford and Central Connecticut, Oberlin said.

Eversource 1355 115-kV Line Rebuild

Eversource’s John Case presented the utility’s plans for an estimated $7.45 million line rebuild in Connecticut (+50% to -25%), with an estimated in-service date of May 2020.

Eversource proposes to rebuild the 115-kV 1355 transmission line from the Colony substation to Schwab Junction in Wallingford, Conn., replacing 14 aged and degraded structures with new steel structures.

The original 1927 steel lattice towers on the line have bent members, corrosion and tower legs located in standing water. The conductor and shield wire in this section are original to the line, thus 92 years old, and no longer standard Eversource transmission conductors, Case said.

The utility will reconfigure the circuit arrangement and right of way to reduce the structures and conductors required, eliminating seven structures and approximately three-quarters circuit-miles of conductor. The aged and degraded copperweld conductor and shield wires will be replaced with new standard conductors and optical ground wire.

Wood structures in this section date from 1966 and suffer from various degrees of woodpecker damage, rot, cracks and deteriorated steel mechanical connections.

Tx Owner Local System Plans

The PAC meeting was followed by a meeting of the Transmission Owner Planning Advisory Committee, a transmission owner-led forum. The TOs each provided brief introductions of their local system plans or those of their subsidiaries, including upcoming transmission projects within their areas.

Presenting plans were Avangrid, Emera Maine, Eversource, National Grid, New Hampshire Transmission and Vermont Electric Power Co.

– Michael Kuser

October 27, 2019March 12, 2025

NEPOOL Reliability Committee Briefs: Oct. 23, 2019

The New England Power Pool Reliability Committee (RC) on Wednesday reversed its September rejection of ISO-NE’s proposed installed capacity requirement (ICR) calculations for Forward Capacity Auction 14 (2023/24) and three annual reconfiguration auctions (ARAs) to be conducted in 2020.

A restored End User sector quorum and a break in the ranks of universal opposition from the Generation sector proved the tipping point. Needing a 60% majority to recommend the ICR values to the Participants Committee, the RC voted by roll call and passed the motion with 63.49% in favor. The RC approved net ICRs of 32,205 MW for 2020/21 ARA 3, 32,230 MW of 2021/22 ARA 2 and 32,465 MW for 2022/23 ARA 1.

The Generation sector voted 4.2% in favor and 12.59% opposed, with one abstention. The Transmission and Publicly Owned Entity sectors remained unanimous in favor, Alternative Resources remained approximately split, and the End User sector was recorded unanimously in favor with one abstention.

Capacity commitment period 2020/21 ARA 3 systemwide capacity demand curve | ISO-NE

The End User sector lacked a quorum in September’s vote and was reported 0.98% in favor and 0% opposed. (See Supply Side not Buying ISO-NE’s ICR Numbers.)

The committee also approved a 940-MW value for the Hydro-Québec interconnection capability credit (HQICC) for FCA 14’s ARA 3, with the value rising to 958 MW for ARA 2 and 969 MW for ARA 1.

Peter Wong, ISO-NE manager of resource studies and assessments, and Senior Engineer Manasa Kotha presented the ICR values and tie benefits.

Pending PC approval on Nov. 1, the RTO plans to file the ICR-related values with FERC by Nov. 5.

$46 Million PTF Cost Allocation

The RC voted to recommend that ISO-NE approve pool-supported pool transmission facility (PTF) costs of $46.39 million for the Baird 115-kV line rebuild project in Connecticut, per the revised cost allocation submitted by Avangrid/United Illuminating.

The committee found the costs consistent with the criteria set forth in Section 12C of ISO-NE’s Tariff for receiving regional support and inclusion in pool-supported PTF rates, and that none of the costs associated with the upgrade are considered localized costs.

The project involves rebuilds of the 88006A and 89006B lines between Baird substation, Barnum substation and the Devon Tie switching yard tying into the Housatonic River Crossing project, for a total distance of approximately 2.4 miles, and includes installing new galvanized steel transmission poles supporting new aluminum conductor steel-supported cable and optical ground wire.

Based on a show of hands, the motion passed with none opposed and no abstentions.

Other Action

The RC on Wednesday also approved a number of projects, including recommending that ISO-NE approve implementation of the Scitico substation circuit breaker and transformer addition project by Eversource Energy in Connecticut, as well as the 15-MW Davenport Solar Generation project by NextEra Energy Resources in Vermont.

The committee also recommended that ISO-NE approve implementation of Eversource’s Andrew Square-to-Dewar Street Station 115-kV cable installation project in Boston; New England Power’s 40-plus-MW Iron Mine Hill Road solar generation and transmission project in Rhode Island; and the latter’s King Solar 1 and 2 generation project.

It also approved revisions to Operating Procedure 16J to modify the timing for initiating the annual certification of transmission equipment dynamics data; and revisions to Operating Procedure 2A, to modify the table of itemized equipment maintenance of communications, computers, metering and building services.

— Michael Kuser

October 24, 2019

UPDATED: Attorneys Clash over PG&E Reorg, Blackouts Resume

By Robert Mullin

Attorneys in the Pacific Gas and Electric bankruptcy case sparred Wednesday over the merits of their competing reorganization proposals, taking potshots at each other’s plans but not scoring any obvious points with the judge overseeing the proceeding.

The hearing was the first since U.S. Bankruptcy Court Judge Dennis Montali ended the utility’s exclusive right to submit a restructuring plan. The decision allowed the company’s unsecured bondholders to submit their own proposal, which has won the support of a group representing wildfire victims, the court-appointed Tort Claimants Committee (TCC). (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)

The hearing also coincided with PG&E’s announcement that it would cut power to customers in 17 Northern California counties in the second series of public safety power shutoffs (PSPS) orchestrated this month to prevent wildfires. The blackouts commenced Wednesday morning and continued into Thursday.

The bondholders’ attorney, Michael Stamer, came out swinging early in the hearing. He disparaged the feasibility of PG&E’s reorganization plan and urged Montali to schedule a confirmation vote for the bondholder proposal as soon as possible — a move that would effectively prioritize the plan over the utility’s.

“We think the most efficient way to get to the end zone — which is confirmation [of a plan and] satisfaction of AB 1054 — is to allow our plan to go first,” Stamer said, referring to the new California law that allows PG&E to draw on a $21 billion fund to cover wildfire damages if it wraps up its reorganization by June 30, 2020. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)

PCG Equity Holders — PG&E headquarters on Beale Street in San Francisco | © *RTO Insider*

Stamer said the bondholder plan would also accelerate a separate state court proceeding convened by Judge James Donato to settle wildfire victims’ claims against PG&E over the October 2017 Tubbs Fire, which killed 22 people and leveled a section of Santa Rosa. (See PG&E Bankruptcy Split into Three Parts.) He contended the plan would “remove the burden” from Donato to estimate damages because bondholders have already negotiated a settlement with the TCC to cover claims of up to $13.5 billion for that fire. The PG&E plan caps the claim amount at $6.9 billion.

Montali was skeptical of Stamer’s argument.

“There’s a whole group of lawyers on the other side who think the burden is not gone — it’s still there. It’s called evaluation,” Montali said, questioning whether the bondholder’s plan might “overpay” tort claimants at the expense of other parties.

Montali added that the bondholder plan might be “DOA” if Donato “puts a larger number” on the claim.

“Our plan is DOA if he puts a very small number on them,” Stamer retorted. Nevertheless, the parties supporting either plan would have to “scramble” if the settlement lands between $6.9 billion and $13.5 billion, he said.

“They’ll scramble to come up, and we’ll scramble to come down,” he said.

Stamer said the “biggest difference” between the two plans is that PG&E’s financing is contingent on the $6.9 billion top-end estimate for potential Tubbs Fire claims.

“Unequivocally, they have to get Judge Donato to say that there is less than $6.9 billion of tort claims, or their financing disappears,” he said.

Montali pointed out that PG&E has said it will come up with additional financing if needed.

“We actually refer to that as the ‘stroke of the pen’ argument,” Stamer replied. “The debtors are of the view that if they get a different view from Judge Donato, with the stroke of a pen, what we will do is we will raise more money.

“So, here’s one of the fundamental problems — the world doesn’t work that way. No. 2 is the bulk of their money coming from equity holders. Setting aside the $30 billion of bridge loans, it has to come from equity holders.”

“You might say that doesn’t happen in the real world, and I might agree with you. That’s why you schedule a hearing — to prove the feasibility,” Montali said.

The judge firmly rebuffed the notion that he could shelve PG&E’s plan in favor of the bondholders.

“I have to do what the [bankruptcy] code says … and I don’t think it says I can dump a debtor’s plan because another plan is confirmable,” Montali said.

No Altruists

PG&E attorney Stephen Karotkin complained that Montali’s decision to terminate PG&E’s exclusivity “has not worked to promote a consensus” in settling on a reorganization plan.

“As we told you, the [Ad Hoc Committee of Unsecure Bondholders] and the TCC have become polarized entirely and now want to move forward with their own plan. That’s not the way it should work,” Karotkin said.

“At the exclusivity hearing, your honor, the TCC made very clear to you that they would only engage in mediation if you agreed to terminate exclusivity,” he said. “Having done that, we say to your honor, now is the time to promptly appoint a mediator. That is the way to move these cases forward, and let’s see if the TCC will live up to its word and its commitment to this court to mediate.”

Karotkin contested the bondholders’ contention that financing for the PG&E plan would fall apart if the Tubbs Fire claims exceed $6.9 billion, saying there is “ample capacity in both the debt and equity markets to fund the plan and meet the requirements of AB 1054. The debtor’s plan does not vaporize.”

He said Stamer was promoting the misconception that PG&E’s financing must come from the existing equity holders. “It doesn’t. There’s no requirement that it comes from the existing equity holders,” he said.

“The ad hoc bondholders are not a group of altruistic investors willing to put up money on favorable terms in an effort to save the state of California,” Karotkin said. “Any number of financial institutions have advised the debtors that there is adequate capital necessary … and on substantially better terms than the terms that are being provided by the ad hoc bondholders.”

Montali assured Karotkin that PG&E’s plan was still a contender.

“I may have disappointed you because I ended exclusivity, but I didn’t say your plan was out of the running,” Montali said.

“Neither one is perfect yet, and neither one is confirmable yet. But both are potentially confirmable,” he said.

Montali declined to rule on scheduling the confirmation of either restructuring plan. Hearings in the proceeding are slated to continue at least into early next year.

Shutoffs Resume

By Thursday morning, PG&E’s latest round of shutoffs covered nearly 183,000 customers — or about 540,000 people — in the Sierra Foothills and North Bay regions, where a “Diablo” wind event was bringing peak gusts of 65 miles per hour in conditions of extremely low humidity.

“Once the high winds subside, PG&E will inspect the de-energized lines to ensure they were not damaged during the wind event, and then restore power,” the utility said in a statement. “PG&E will safely restore power in stages as quickly as possible, with the goal of restoring the vast majority of customers within 48 hours after the weather has passed.”

PG&E tweeted that customers currently impacted would be restored in advance of any further PSPS initiated this weekend. The company said it forecasts indicated “elevated” risk of additional blackouts on Sunday and Monday.

PG&E’s incited a backlash from California regulators and Gov. Gavin Newsom over its decision to shut power to more than 2 million residents earlier this month. The company has defended its decision and last week signaled it will continue the PSPS policy for years until it hardens its system against wildfire danger. (See PG&E Says Blackouts Will Continue.)