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March 9, 2020March 12, 2025

Overheard at NECA Renewable Energy Conference 2020

AUBURNDALE, Mass. — If 50 years ago you prophesied that school buses would someday help a utility stabilize the grid, people might have suggested that you had been reading too much Tom Wolfe or drinking the electric Kool-Aid on the bus with Ken Kesey.

Same goes for heat pumps that use bitter cold air to heat New England homes.

Now — in 2020 — these phenomena are the stuff of real life in the energy industry, as 150 people heard Thursday at the Northeast Energy and Commerce Association (NECA) Renewable Energy Conference.

The Northeast Energy and Commerce Association (NECA) hosted its annual Renewable Energy Conference on March 5. | © RTO Insider

Following is some of what we heard at the event.

Regional Outlook

New England needs to update the interconnection processes to reflect the value and unique nature of energy storage, said Jeremy McDiarmid, vice president for policy and government affairs at the Northeast Clean Energy Council.

“We need to figure out how the jurisdictional divide between distribution systems and transmission systems occurs in a way that allows these products to move forward, and perhaps most importantly, we need to figure out how to pay for it all,” McDiarmid said.

Siting is increasingly a challenge as communities are becoming increasingly wary of large solar developments, he said.

“Many of our states have seen the development of relatively robust solar industries over the past decade,” McDiarmid said. “Portfolio standards, net metering and a base of customers ready to adopt clean energy have driven a market that has brought jobs and a significant amount of clean energy to the region.”

Left to right: Abigail Krich, Boreas Renewables; Carol Sedewitz, National Grid; Jason Bobruk, SolarEdge; Jacqueline Ashmore, Boston University; and Michael Goldman, Eversource Energy. | © RTO Insider

The lines between transportation and electricity are getting more blurred every day, and that’s a good thing, he said.

“Nearly 40% of our emissions come from the transportation sector, and it has persistently been a very hard nut to crack,” McDiarmid said. “The Transportation Climate Initiative [TCI] offers the best hope for starting us down what’s going to be a very long path to capping transportation emissions and harnessing market forces to support the lowering of carbon emissions. This necessary transition can’t happen fast enough.”

Mobile Storage

The TCI is a regional collaboration of 12 Northeast and Mid-Atlantic states and D.C. that seek to cut carbon emissions from the transportation sector. Participating states include Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont and Virginia.

The TCI concept is an emissions cap set by the participating jurisdictions, with a program projected to run from 2022 to 2032, explained Staci Rubin, senior attorney with the Conservation Law Foundation. Upstream fuel suppliers would be required to obtain an allowance equal to the amount of pollution that they generate, with the amount available declining over time.

“This would apply to on-road gasoline and diesel fuel, essentially covering 80% of the transportation sector emissions, on average, throughout the region from Maine to Virginia,” Rubin said.

Some of the proceeds from the sale of TCI emissions allowances would go to converting school buses from diesel to battery electric, or trolley electric where possible, she said. Boston’s mass transit operator, the Massachusetts Bay Transportation Authority, has only five electric buses out of more than 1,000 buses, and they are still in the pilot phase.

Left to right: Staci Rubin, CLF; Will Lauwers, Mass. DOER; Michael Hagerty, Brattle Group; and Po-Yu Yuen, Sustainable Energy Advantage. | © RTO Insider

Rubin noted a Dominion Energy project in Virginia as “a great program to use electric school buses as active energy storage systems … a deep and large-scale deployment of these buses and situating them to ensure they can be dispatched to the grid and helping to better connect distributed generation.”

Will Lauwers, director of emerging technology at the Massachusetts Department of Energy Resources (DOER), said that transportation and home heating offer nearly equal opportunities for cutting emissions.

“You’ll reduce your energy requirement by 75% just by going to an electric vehicle,” Lauwers said.

He recommended Northeast Energy Efficiency Partnerships-certified cold climate air-source heat pumps, saying, “You’re looking at reducing annual heating energy needs by at least 60% just by getting a heat pump designed for this climate.”

As to where the sectors converge, he cited a newly released DOER mobile storage study that shows “How mobile storage, in many cases electric vehicles … can benefit the commonwealth in emergency response conditions, and how EVs can operate as long-duration storage to increase reliance on renewables and reduce our peak demand,” Lauwers said.

Michael Hagerty, Brattle Group | © RTO Insider

The study shows that today’s storage capacity of EVs enables them to provide all the energy needs of a household for multiple days, even without efficiency upgrades to the building, he said.

Michael Hagerty, senior associate at The Brattle Group, presented excerpts from a study he co-authored last September on emissions reduction and said that it could be important to develop technologies for seasonal storage.

“Time-of-use rates also have been very effective at shaving peak loads for residential EV charging,” Hagerty said.

Look North

In Maine, the state legislature has seen a wave of “legislation promoting renewable energy and reforming the interconnection rules to facilitate the interconnection of distributed generation,” said Arielle Silver Karsh, senior regulatory counsel for Emera Maine.

The legislature established a commission to look into energy storage and brought in experts to provide information on how to incent storage, to ask whether utilities should be allowed to own it, and whether storage resources could be used for energy efficiency or to reduce the peak, she said.

Arielle Silver Karsh, Emera Maine | © RTO Insider

“A lot of recommendations came out of that report, one of which is the commission recommended that the Public Utilities Commission open up a docket and settle the question of utility ownership,” Silver Karsh said.

“For Emera Maine, there would be hesitation to invest in energy storage without knowing is it possible to rate-base that asset,” she said. “Or how do we integrate that into our system and use it to defer transmission or distribution [upgrades]?”

Another important question is how does the state or the PUC incent energy storage, she said.

“Is it a question of combining energy storage with a renewable energy generating unit, or is it sufficient to just have storage alone?” Silver Karsh said.

Emera doesn’t want to reinvent the wheel, she said, so the company has reached out to National Grid and Eversource Energy to ask how they have worked on these various integration projects with developers, the states and other stakeholders.

The storage commission recommended setting a target of 100 MW by 2025, Silver Karsh said.

Electric load in Maine is “lumpy, with a fish farm popping up with 12 MW in an isolated place, so you need to react fairly quickly to that,” she said. “But Northern Maine is not directly electrically connected to ISO New England — but is connected to New Brunswick and indirectly to Hydro-Québec.”

Northern Maine has very low population density, which is great for wind farms, but if the generation exceeds the local load, “energy storage could be a great way to balance that out,” Silver Karsh said. “We’re still working with stakeholders to determine whether that energy could be exported to New Brunswick and Hydro-Québec.”

Abigail Krich, Boreas Renewables, (left) and Carol Sedewitz, National Grid | © RTO Insider

Up until the middle of 2019, there was approximately 3,000 MW of wind from Northern Maine in the interconnection queue at ISO-NE, said Abigail Krich, president of Boreas Renewables.

“We could still build that out, but we would need pretty significant transmission upgrades to the system,” Krich said. “Now I think there’s about 780 MW of wind left in the queue in that area because of those transmission constraints.”

To interconnect about 350 to 550 MW of generation in that area would require spending about $780 million, which would have to be paid by the interconnecting generators and result in an added energy cost of $23 to $36/MWh over a 20-year project span. That cost could be reduced if the capacity factor were increased by adding solar, for example, but it is “a large hurdle” to add to any new project, Krich said.

– Michael Kuser

March 9, 2020

Overheard at Transmission Summit East 2020

ARLINGTON, Va. — Despite growing fears about the spread of the COVID-19 coronavirus, Infocast’s annual Transmission Summit East once again drew about 100 industry professionals last week to the top floor of the Key Bridge Marriott, with its grand view of D.C. from across the Potomac River.

There were only a handful of cancellations because of health concerns, including a few that led to the scuttling of a panel. Aside from some awkward elbow bumps instead of handshakes, there were few signs that the virus was a source of stress for attendees.

Rather, the chit-chat between panels indicated there was more concern about the direction of FERC than a potential pandemic. The consensus among both panelists and attendees was that FERC — and the U.S. in general — lack a clear vision of what the grid of the future should look like and, therefore, how to plan for it.

Larry Gasteiger, WIRES | © *RTO Insider*

As is always discussed at any conference when transmission is a subject, the difficulty developing interregional transmission and the ineffectiveness of Order 1000 — even as demand for renewable power increases — was top of mind for many speakers. But as Congress discusses several energy policy bills, and Election Day draws closer, many speakers seemed to be in wait-and-see mode; unlike last year, no one suggested any ideas or proposals for how to solve the problem. (See “Hoecker, Demarest Propose Interstate Tx Siting Bill,” Overheard at Transmission Summit East 2019.)

“One of the key things is that FERC needs to adopt a clear and consistent policy of supporting needed transmission,” Larry Gasteiger, former FERC chief of staff and now executive director of WIRES, said in a keynote address opening the summit. “It needs to get off the bench; it needs to get into the game and become a loud, vocal, consistent promoter of getting transmission built. … Frankly, in the last decade or so, FERC’s gotten wobbly on transmission. … There’s a very inconsistent track record of their decisions.”

‘What are we truly planning for?’

Gasteiger concluded his remarks by saying that FERC shouldn’t roll back return on equity adders established to incent transmission investment.

Hudson Gilmer, LineVision | © *RTO Insider*

That naturally set up the topic of the first panel of the summit: the commission’s inquiry into whether it should continue to grant adders based on transmission projects’ risks and challenges or their benefits (PL19-3, PL19-4). (See Stakeholders Spar in FERC Tx Incentives Docket.)

But panelists generally agreed the current incentive structure was fine; it’s transmission planning processes that need to be updated to match the changing resource mix, they said.

“To date there’s only been one way of building transmission, and it really hasn’t changed over the last 75 years,” said Hudson Gilmer, CEO of LineVision, which provides transmission line monitoring equipment. “It’s either building new towers and wires, or upgrading and reconductoring existing lines. … The traditional way is out of step with the variability and dynamism of our grid given the new generation profile we see. …

“Right now, we have perverse incentives that really almost put the transmission owners in a regulatory straitjacket that says in order to serve their shareholders, they have to deploy capital and [build] major projects.”

“The issue is, in PJM at least, it’s … very contentious. It is also very litigious at this point, with lots of lawsuits being filed at each other,” said Mike Kormos, senior vice president for wholesale markets and transmission policy at Exelon, and former PJM COO. “And therefore, it really has put the planning process in a bind.”

Advanced technology cannot compete because of its costs, he said. “It’s very hard in a competitive process [to choose] a project that is more expensive than something else simply for the fact that it’s neat, [unless] we get clearer direction from FERC about how the RTOs should value those technologies.” He gave the example of a more expensive battery solution versus the traditional solution of reconductoring.

“Everybody wants transmission, but they want someone else to pay for it,” Kormos said later in the discussion. “Everybody’s fine with what comes out of the planning process as long as they’re not footing the bill for it. So I think that’s where we need to get more certainty: What are we truly planning for? How are we valuing it?”

Some of these sentiments were echoed later in a panel on reforms to regional and interregional planning processes.

Transmission Summit East — Nathan Benedict, ITC | © *RTO Insider*

“What ends up happening is sort of this lowest-common-denominator approach, where stakeholders agree on near-term issues that have the least amount of uncertainty,” said Nathan Benedict, manager of regulatory strategy for ITC Holdings. “We’re not looking for a holistic, proactive approach to planning that’s needed to cost-effectively address these new challenges on the system.”

He pointed to MISO’s and SPP’s massive generation interconnection queues. “Now granted, a lot of this is speculative generation that will not come to pass, but then the question becomes, how do you cost-effectively interconnect this generation in a way that makes sense for customers? Right now what’s happening are piecemeal interconnections with generators bearing substantial costs to get this generation interconnected.”

No Need for Interregional Projects?

On a panel of RTO representatives, Craig Glazer, PJM vice president of federal government policy, acknowledged complaints about the lack of interregional projects. “But a lot of things have happened” since FERC issued Order 1000, he said. “No. 1 is congestion on the system is way down. No. 2 is we’ve had significant buildouts on the MISO system [and] … on the PJM system. As a result of that, we don’t see the need for big interregional projects across our respective footprints.”

Glazer also rebutted the common argument that long interstate lines are needed to move power from renewable-saturated regions of the U.S. — wind in the Midwest and solar in California, for example — to load centers where states and municipalities have set ambitious emission-reduction goals.

“In our footprint, where we’ve got a lot of load, people don’t want it,” he said. Governors in coastal states want to develop their own in-state renewable resources, especially offshore wind, “even though it might be cheaper to import from MISO or SPP. … Until we figure out that issue, some of that wind is going to stay bottled up in SPP.”

Challenges of Interconnecting Offshore Wind

One panel discussed the need for more transmission specifically to interconnect the coming influx of offshore wind generation.

Kirsty Townsend, Ørsted | © *RTO Insider*

“If the U.S. follows the trend in Europe, we’re going to have so much wind; there is so much capacity and potential here, both for fixed-bottom and floating, that it would be ill-informed of us as an industry to not want to consider a coordinated, planned approach in the future,” said Kirsty Townsend, head of special projects in the U.S. for Ørsted. “I would encourage all relevant bodies within the states to initiate that process now.”

A native of the U.K., Townsend was able to provide the lessons learned from the European offshore wind industry. “This is not just a flash in the pan,” she said. “The whole of Europe is talking about connecting countries with wind farms to expand into the European grid, something that wasn’t even on the radar. So if this industry is going to be as big as we need it to be for our climate goals, then we need to start thinking now about how to deliver that massive-scale vision.

Fellow panelist Joshua Gange, renewable energy program transmission specialist for the U.S. Bureau of Ocean Energy Management, asked Townsend to compare working across RTOs to working across countries.

“I think it’s easier to work across countries in Europe,” she replied, prompting laughter from the audience. Not only do countries work more closely together, European ratepayers do not subsidize transmission projects as occurs in the U.S. “How can you ensure that the advantages of connecting a grid between New York and New Jersey is equally shared across PJM and NYISO? You can’t. But that’s the issue you’re going to have to face that Europe doesn’t have to.”

– Michael Brooks

March 9, 2020

PG&E Tries to Put Bankruptcy Plan in Layman’s Terms

By Hudson Sangree

The bankruptcy of Pacific Gas and Electric could reach another milestone this week as the utility tries to explain its Chapter 11 reorganization proposal in plain English to fire victims and other affected parties.

That reorganization plan is now estimated to cost almost $60 billion, according to recent testimony by PG&E executives before the California Public Utilities Commission.

In a hearing that starts Tuesday, lawyers will debate what’s known in bankruptcy court as a disclosure statement. Once finalized, the statement will be sent out to parties to the bankruptcy who will then get to vote on the plan. (See What Spring Could Bring for PG&E.)

Objections to PG&E’s disclosure statement have been filed by government agencies, fire victims, creditors and others who take issue with aspects of its Chapter 11 plan.

Wildfire victims, represented by the official Tort Claimants Committee, say the revised terms of PG&E’s exit financing could leave a proposed $13.5 billion victims’ trust holding company stock with diminished value.

The U.S. Trustee appointed to the case says the disclosure statement lacks supporting financial information necessary for parties to determine the merits of PG&E’s bankruptcy plan.

Both want U.S. Bankruptcy Judge Dennis Montali to help correct the purported problems.

Surprisingly, however, PG&E’s fiercest critic in recent months, Gov. Gavin Newsom, said he doesn’t want to stand in the way of the disclosure statement being mailed out, even though not all his demands for change have been met by the utility.

Newsom has threatened a state takeover of the company if it doesn’t replace its entire board of directors and make other wholesale changes. But the utility is trying to exit bankruptcy by June 30 so it can participate in a $21 billion wildfire insurance fund created by Assembly Bill 1054, passed last July, the governor’s lawyers noted in court papers filed Friday. (See Newsom Budget Reiterates PG&E Takeover Threat.)

The CPUC must rule on whether PG&E has met the terms of AB 1054 — including whether it can provide safe, reliable service going forward and fairly compensate victims of past fires, such the November 2018 Camp Fire that killed 86 people in the town of Paradise.

Newsom’s lawyers acknowledged PG&E’s Chapter 11 plan, as detailed in its draft disclosure statement, doesn’t fulfill the requirements of AB 1054, but they said it should be allowed to move forward toward a vote anyway.

“Under normal circumstances, it may be prudent for the debtors to delay solicitation until the plan can be further refined to meet AB 1054,” the governor’s attorneys said. “The governor’s office, however, is cognizant that the June 30, 2020, deadline codified in AB 1054 creates unusual tension in these Chapter 11 cases [so that delays could endanger] … the debtors’ ability to ultimately obtain the benefit of the provisions of AB 1054.”

Those financial benefits, insuring the state’s investor-owned utilities against future wildfire liabilities, are necessary for PG&E to remain financially stable going forward, the utility and governor agree.

“Modifications to the plan to resolve the concerns of the governor’s office should not jeopardize the confirmation process, as the governor believes those changes would create a stronger and better managed utility and inure to the benefit of all of the debtors’ constituents,” Newsom’s lawyers said.

The governor’s office has been working with PG&E to address Newsom’s concerns. The parties have engaged in court-ordered mediation and met together in the State Capitol.

A mediation session held Monday in San Francisco “to resolve all outstanding issues between the parties” could bring PG&E, fire victims and state officials closer together, shortening Tuesday’s hearing.

The disclosure hearing is scheduled to start at 10 a.m. before Montali in the U.S. Bankruptcy Court in San Francisco. It could continue into Wednesday if necessary, court papers indicate.

March 9, 2020

Dominion: FERC MOPR Rulings Inconsistent on Self-supply

By Rich Heidorn Jr.

Dominion Energy asked FERC on Friday to reconsider its conclusion that self-supply resources suppress PJM capacity prices, contending the commission’s position is inconsistent with an exemption it granted similar resources in NYISO.

Dominion asked to supplement its Jan. 21 request for rehearing of the commission’s December order requiring PJM to apply the minimum offer price rule (MOPR) to all state-subsidized resources (EL16-49, EL18-178). (See PJM MOPR Rehearing Requests Pour into FERC.)

PJM had asked FERC to approve its previous exemption for self-supply resources owned by public power entities (cooperative or municipal utilities), vertically integrated utilities subject to traditional bundled rate regulation and load-serving entities that serve retail customers. In 2013, the commission ruled that “a self-supply LSE that owns or contracts for a large proportion of the capacity needed to meet its load has no reason to finance uneconomic entry given that such a strategy would not be profitable.” (See Is Self-supply Suppressing Prices?)

Dominion MOPR — Dominion’s 1,661-MW Possum Point Power Station in Dumfries, Va., can burn natural gas and oil. | *Dominion Energy*

But FERC’s Dec. 19 order found that self-supply resources were subsidized because the energy and capacity they produce are purchased through state-directed procurements.

Dominion said in its rehearing request that the commission failed to justify making self-supply capacity subject to MOPR and ignored evidence that self-supply does not suppress prices.

In the Feb. 20 NYISO order, however, the commission accepted a self-supply exemption proposed by NYISO on terms similar to PJM’s proposal, Dominion said (EL16-92, ER17-996). (See FERC Narrows NYISO Mitigation Exemptions.)

“In the 2020 NYISO order, the commission accepted in part, subject to condition, the NYISO’s proposed self-supply exemption, the NYISO’s proposed net short and net long threshold criteria for the self-supply exemption, and generally all other aspects of the NYISO’s proposed self-supply exemption. … Yet, the commission made no effort to distinguish between its findings regarding the NYISO’s proposal and its nearly opposite findings in this proceeding made just two months prior,” Dominion said.

“If the NYISO’s proposal is adequate and the commission continues to find that self-supply entities do not possess the incentive to artificially suppress pricing in the NYISO market, the commission should likewise find that, with well defined guardrails, self-supply entities in PJM also continue to lack the incentive to artificially suppress prices in PJM capacity markets. Moreover, the commission should permit the self-supply exemption in substantially the same form originally proposed by PJM in this case,” Dominion said. “The commission is obligated to provide its reasoning when departing from existing policy or precedent.”

A Dominion official told an energy conference last week that growing vertically integrated utilities such as Dominion may need to leave the capacity market if the ruling is not changed. (See related story, “A Maryland Capacity Auction? Dominion Going FRR?” Overheard at ACORE Policy Forum 2020.)

Dominion Energy Virginia, which owns 27,100 MW of generation, is planning to build 2.6 GW of wind generation off the coast of Virginia and is about halfway through a plan to add 3,000 MW of solar generation.

March 9, 2020

Newsom Reappoints 2 CAISO Governors

By Hudson Sangree

SACRAMENTO, Calif. — Gov. Gavin Newsom on Thursday reappointed Ashutosh Bhagwat and Angelina Galiteva to their fourth three-year terms on the CAISO Board of Governors.

Bhagwat is a law professor at the University of California, Davis, where he holds an endowed chair in freedom and equality. He has written about the California electricity crisis of 2000/2001 and lectures on constitutional law.

Galiteva is president of NEOptions, a renewable energy design and development firm. She was executive director of the Los Angeles Department of Water and Power and head of its green energy initiative from 1997 to 2003. Galiteva is an attorney with an advanced degree in energy law.

Both have served on the ISO’s board since 2011, when then-Gov. Jerry Brown first appointed them.

Newsom CAISO Governors — Gov. Gavin Newsom reappointed CAISO Governors Angelina Galiteva, second from left, and Ashutosh Bhagwat, far right. | © *RTO Insider*

In the last nine years, CAISO integrated large amounts of renewable resources, established the Western Energy Imbalance Market and, starting last year, became the reliability coordinator for much of the West.

“The executive leadership team is looking forward to working with the newly reappointed board members, and the entire Board of Governors, as we continue to refine and showcase our vision of a clean, low-carbon power grid,” CAISO CEO Steve Berberich said in a statement. “We appreciate Gov. Newsom’s engagement in the board appointment process and his confidence in our team and our mission.”

The State Senate must confirm the appointments, but Bhagwat and Galiteva will continue to serve, effective immediately. Their terms expire Dec. 31, 2022.

The five-member CAISO board also includes Chair David Olsen, who was first appointed in 2012 and reappointed in January 2019. For the decade prior to his appointment, Olsen was managing director of Western Grid Group, an organization of former state energy officials advocating for grid modernization and clean energy. He was CEO of outdoor clothing manufacturer Patagonia in the late 1990s.

Last year, Newsom appointed University of California, Berkeley business professor Severin Borenstein and business promoter Mary Leslie to the board.

Borenstein is faculty director of the Energy Institute at Berkeley’s Haas School of Business. Leslie was president of the Los Angeles Business Council since 2001 and deputy mayor of Los Angeles under Mayor Richard Riordan in the 1990s. (See Newsom Names New CAISO Governors.)

March 9, 2020

FERC Rejects ISO-NE Fuel Security Tariff Revisions

By Michael Kuser

FERC on Friday rejected Tariff revisions filed jointly by ISO-NE and the New England Power Pool to clarify that resources retained for fuel security reasons will not be retained for other reasons once the fuel security retention period ends (ER20-89).

“While we favor limiting the scope and length of out-of-market actions, we seek to balance that objective against the ability to address reliability concerns,” the commission said. “The proposal here would remove ISO-NE’s ability to retain a fuel security resource to address potential future transmission reliability issues that may arise simply because the resource in question had been retained previously for fuel security.”

The proposed Tariff revisions prompted a protest from Exelon, which owns Mystic 8 and 9, the planned retirement of which prompted the RTO and NEPOOL to seek to retain resources for regional fuel security in the first place.

Exelon argued that the proposal “unduly discriminates” against fuel security resources in general and the Mystic units in particular. The company contended that “the proposal results in different treatment for transmission security resources based on whether the resource has previously provided fuel security service, despite the fact that transmission security and fuel security resources are similarly situated for purposes of retirement,” FERC noted.

ISO-NE Fuel Security — Mystic Generating Station, on the Mystic River in Everett, Mass.

The company further argued that if ISO-NE had requested to retain the Mystic units for transmission security rather than fuel security, the Tariff would allow for possible cost-of-service compensation until the transmission reliability need was addressed. However, the fuel security agreement restricted Mystic’s options in a way not faced by other resources, effectively penalizing it for entering into an agreement for fuel security instead of transmission security.

Exelon also pointed to delays in the completion of ISO-NE’s Energy Security Improvements (ESI) initiative. FERC last August granted the RTO a second extension to file the plan, until April 15. The NEPOOL Participants Committee expects to vote on the new fuel security market design at its April 2 meeting.

The RTO’s aspirations to develop a long-term market-based fuel security solution and competitively develop transmission solutions for the Boston area do not constitute substantial evidence that it is just and reasonable to eliminate a reliability safeguard, Exelon said.

In rejecting the revisions, the commission found that “instead of retaining such a resource for transmission security (as it would any other resource that was not previously retained for fuel security), ISO-NE would need to address this issue through either real-time operating procedures, such as shedding load, or through the use of a gap [request for proposals] solicitation.”

FERC said it remains open to ISO-NE and NEPOOL “proposing to revise the relevant reliability review timeline to ensure that resources are not unnecessarily retained when transmission solutions will be in place in time to address identified reliability needs.”

However, the commission did not find just and reasonable “the proposal to make a resource retained for fuel security ineligible to be further retained for transmission reliability purposes.”

FERC last month rejected a related request to roll back the sunset date for a Tariff provision that allows the RTO to retain a resource for fuel security reasons (ER20-645). (See FERC Rejects ISO-NE Fuel Security Sunset Rollback.)

March 9, 2020

MISO Market Subcommittee Briefs: March 5, 2020

CARMEL, Ind. — MISO might revise and refile a failed proposal designed to set penalties for non-capacity resources that exercise market power through physical withholding.

FERC Rejects MISO Expansion of Market Mitigation.)

“We’ve reached out to the IMM to get their view of things,” Executive Director of Market Operations Shawn McFarlane said at the Market Subcommittee’s meeting Thursday. “It seemed like FERC was colloquially ‘not on board.’”

McFarlane said the commission thought the proposal placed too much burden on generators to prove when their operations would be uneconomic. “We’d have to address that issue before a refile,” he said.

Dustin Grethen, MISO market design adviser, said the RTO has observed congestion and binding constraints that could be relieved by non-capacity resources.

MISO will continue to monitor those instances over the upcoming months while it considers the possibility of a future proposal, Grethen said.

MISO counsel Daniel Malabonga characterized the filing’s aims as “uphill in the first place.” He said the RTO will have to find new “middle ground” should it choose to refile.

Potential Dollar Limit on Some Resettlements

MISO’s settlements team is considering subjecting the issuance of certain market resettlements to a dollar value minimum.

Director of Settlements Laura Rauch said the costs of accounting for resettlements as a result of a continuing error (defined as a long-running error that’s not easily discovered) can exceed the cost of the resettlements themselves. For instance, she said a $5,000 resettlement can be entirely eaten up by the “accounting costs of tracking the resettlement charges for all other impacted parties.”

After performing corrective resettlements, MISO has redistributed amounts to impacted market participants ranging from $20 to $1 million, with a median of less than $50,000. In some cases, MISO collects the resettlement amounts from redistribution from up to 220 market participants.

Rauch said the dollar minimum would not apply to most of MISO’s settlement adjustments — which are resolved quickly with corrections settlement statements — or to stakeholder disputes over settlements submitted within the 120-day deadline from the trade date. MISO will also continue to pursue FERC-required resettlements, she said.

Rauch asked stakeholders to suggest a reasonable dollar threshold for resettlements resulting from continuing errors. She said she would likely return to the subcommittee for its April meeting with a proposal.

Spinning Reserves May Get Embedded Deployment Cost Recovery

MISO may give its spinning reserves a simpler means of recouping costs for providing energy, stakeholders heard at the meeting.

The current clearing process for selecting spin service resources doesn’t incorporate costs the resources incur when deployed as contingency reserves, including the shutdown costs for demand response participants. Resources cleared and deployed for spin service “may have real deployment costs that are not recovered under MISO’s current Tariff provisions,” the RTO said.

MISO adviser Michael Robinson said the current selection process is “inefficient, creating uplifts and distorting price signals.” The RTO could include expected deployment costs when it selects spinning reserves, he told stakeholders.

Spinning reserves are resources that remain online and synched to the grid, meant to be available within 10 minutes. MISO has not included energy deployment costs for spinning reserves since it began its ancillary services market in 2009. Spinning reserves committed by MISO are guaranteed to be made whole to their production costs; however, assets committed outside of the RTO’s market don’t have the same make-whole guarantee.

“In some cases, we make the units whole through uplift, and that’s not good. In other cases, we don’t make the resources whole, and that’s not good from the owner’s perspective. … We’d like to sort this out and get all that embedded in a market price,” Robinson said.

He said the gap hasn’t been burdensome so far but could become an issue as more varied types resources offer spinning reserves.

Customized Energy Solutions’ Ted Kuhn said MISO may not currently be selecting the best prices in spin service because it cannot see which assets have high deployment costs. Robinson agreed and said higher deployment costs have become more prevalent in recent years.

MISO stakeholders are requested to provide their opinions on the best means of embedding production costs. The topic will be taken up again at next month’s MSC.

— Amanda Durish Cook

March 9, 2020

Tx Developers Want to Send Wind to California

By Hudson Sangree

TEMPE, Ariz. — Developers of transmission projects that would send wind power from rural Wyoming and New Mexico to cities in California and Arizona made their cases at this year’s Western Planning Regions Annual Interregional Coordination Meeting on Feb. 27.

The venue for this year’s forum was the Salt River Project’s sleek new LEED-certified meeting-and-classroom facility at its PERA Club, an employee recreation area. The building remains under construction, backed by the red rock formations and popular hiking trails of Phoenix’s Papago Park. High-voltage lines cross the area, juxtaposing transmission towers with distinctly Western scenery.

California wind — This year’s Western Interregional Coordination Meeting for transmission planning took place inside the Salt River Project’s new LEED-certified pavilion at PERA, its employee country club. | © *RTO Insider*

In a similar way, three transmission projects presented at the meeting would string nearly 1,500 miles of transmission lines, total, across the deserts and mountains of Arizona, Nevada, New Mexico and Utah if developers realize their plans.

The proposed projects include the long-sought Sunzia Southwest Transmission Project, which would link Pattern Development’s Corona Wind Projects, potentially one of the largest wind farms in the Western Hemisphere, to load centers in the Desert Southwest and Southern California via the Palo Verde Hub west of Phoenix.

The $2 billion project would consist of two bidirectional 500-kV lines with a total rating of 3,000 MW. A consortium of developers and utilities are behind the project including Southwestern Power Group, Shell WindEnergy and Tucson Electric Power.

Another project talked up at the meeting was TransCanyon’s Cross-Tie Project, which would traverse 213 miles through central Utah and Eastern Nevada at a projected cost of $667 million. TransCanyon is a joint venture between Berkshire Hathaway Energy and Pinnacle West Capital, the parent company of Arizona Public Service.

The third project presented at this year’s planning session was the TransWest Express, a $3 billion effort by The Anschutz Corp. to connect the company’s massive wind farms in eastern and central Wyoming with Southern California’s 24 million residents. It would run 730 miles, crossing Colorado and Utah, to the Marketplace Hub near Las Vegas.

Cost allocation remains a big question. The projects are merchant-driven and haven’t been fully embraced by Wyoming Wind Power Revs up, but is it too much?)

“There’s been very little planning activity on these because of the absence of regional need seen through these projects, but we’re hopeful that’s changing now as folks are seeing more penetration of renewables and the advantages of Wyoming wind,” said Dave Smith, director of engineering and operations with TransWest.

Bob Smith, a transmission planning consultant with TransCanyon, pointed out that load-serving entities in California, including two of the state’s large community choice aggregators, have signed power purchase agreements to buy Corona wind power, even though the SunZia lines to get it to the state don’t exist yet.

Powerful winds in central New Mexico blow before California’s solar arrays ramp up in the morning and after they go offline at night, potentially mitigating California’s reliability concerns going forward, according to a presentation delivered at a recent WestConnect stakeholder meeting, also at the PERA Club. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)

Developers are hoping construction will start in 2021 or 2022 and that the first line will be in operation by 2024 or 2025.

No Interregional Needs

The planning meeting brought together stakeholders and representatives of CAISO, ColumbiaGrid, Northern Tier Transmission Group and WestConnect to discuss interregional coordination under CAISO Seeks More Transfers with Pacific Northwest.)

Each of the West’s four planning regions detailed its own transmission planning process, identifying regional needs based on reliability, economics and public policy per Order 1000’s requirements. But no interregional needs were identified in the current planning cycle that could streamline transmission in the Western Interconnection.

The impending merger of two of the four planning regions, ColumbiaGrid and Northern Tier, could give rise to new needs, planners said. FERC ruled on Dec. 27 that the proposed merger fell short of Order 1000’s goals of promoting competition and cost savings. It gave the filing entities — seven member utilities of ColumbiaGrid and Northern Tier — time to correct their application’s deficiencies. (See FERC: NorthernGrid Merger Needs More Work.)

NorthernGrid’s members would include Bonneville Power Administration, PacifiCorp, and publicly and investor-owned utilities in California, Idaho, Montana, Oregon, Utah, Washington and Wyoming. Dave Angell, vice president of regional transmission for Northwest Power Pool, one would-be member of NorthernGrid, said at the interregional coordination meeting that the utilities are planning to refile their plan with FERC soon.

March 8, 2020

ISO-NE Study to Chart Transition to Future Grid

By Rich Heidorn Jr.

ISO-NE and New England Power Pool stakeholders are collaborating to study market and reliability issues the region will face as it seeks to decarbonize power, transportation and heating over the next three decades.

NEPOOL members discussed the outlines of the study — which was prompted by requests last year from the New England States Committee on Electricity (NESCOE), New England Power Generators Association (NEPGA) and other stakeholders — at the Participants Committee meeting Thursday.

ISO-NE Future Grid — ISO-NE CEO Gordon van Welie | © *RTO Insider*

“People are generally very supportive of doing a study,” ISO-NE CEO Gordon van Welie said Friday at a news briefing on the RTO’s 2020 Regional Electricity Outlook, which noted states’ “goals to achieve up to 100% renewable resources” and asked “How do we get there from here?”

“I think the general consensus in the room … is it’s a good thing to go off and study the future power system because that’s going to give us a lot of information to then inform the other discussions that people want to have, which is the market design conversation, and ultimately transmission,” added van Welie, who said electrification will transition the region from a summer- to a winter-peaking electric system.

“There was less clarity around what the scope and objective of the study should be. The discussion yesterday was mostly about process and not scope. And that conversation [about scope] will be coming in due course in the next month or two.”

Work on the study will begin in earnest after the RTO’s NEPOOL Markets Committee Briefs: Feb. 11-13, 2020.)

The PC meeting materials included a graphic depicting the study as four bubbles: the objective (assessing the power system needed to meet state energy and environmental policies); study process (identify the resource mix and operational and reliability needs); a gap analysis (to determine whether the current markets plus ESI provide resources and ISO-NE what they need to continue reliable operations); and a discussion of potential market approaches to address any gaps.

Van Welie said that the study’s time frame will be the subject of future stakeholder discussions, but that he expects it to be longer than the next 10 years, when he said electric demand from decarbonization of transportation and heating is projected to increase only slightly.

“When I look at that and the long-term decarbonization goals in the region, I think there will be a hockey stick [rise in demand]. We’re going to have to accelerate — dramatically accelerate — decarbonization of the other sectors, so there will be a steep growth in electric demand over that period,” he said. “It’s important, if we’re going to study the future, that we study that hockey stick because there’s nothing really interesting to study in the next 10 years. The demand’s pretty flat.”

A Brattle Group study released in September predicted that meeting the states’ goals for reducing greenhouse gas emissions by 80% by 2050 will result in a doubling of electricity demand, even with substantial energy efficiency gains.

“I don’t know that we should lock onto specific numbers and multiples at this time,” van Welie said. More important, he said, is how the system will add renewable capacity: through the markets that have served the region for the last two decades, or through long-term power purchase agreements, which would put investment risk back on consumers.

ISO-NE sought to develop a market-based path for renewables to supplant carbon-emitting resources through the substitution auction in the Competitive Auctions for Sponsored Policy Resources (CASPR) program, which allows resources nearing retirement to trade their capacity supply obligations with new state-sponsored resources that did not clear in the primary auction.

The RTO has held two auctions under CASPR. Vineyard Wind, a planned 800-MW offshore wind farm, took over a 54-MW obligation from a retiring resource in Forward Capacity Auction 13 last year. There were no trades this year in FCA 14.

“As we said when we filed CASPR, it’s intended to work over time,” said Anne George, the RTO’s vice president of external affairs and corporate communications. “We still feel like with only two auctions of experience, we need a little more time to see how CASPR works.”

“I think it’s going to take time for those economic pressures to build up” to persuade incumbent generators to retire, van Welie added. “So, we have been very clear about this: We think carbon pricing is a much better solution … which is why you hear us advocating for it.” (See ISO-NE: States Must Lead on Carbon Pricing.)

At a conference in D.C. last week, speakers expressed some doubts about carbon pricing, saying it won’t solve the climate crisis by itself or persuade states to abandon their own clean energy policies. (See related story, Carbon Pricing Gains Popularity — and Doubts.)

“I think it’s going to take time for people to get comfortable with [carbon pricing]. It may take a long time for us to get comfortable with it,” van Welie acknowledged. “Developers are going to be very cautious about trusting the regulatory system around carbon pricing until they see that it’s stable and has longevity.”

The Regional Greenhouse Gas Initiative, which includes all six New England states, “never produced a material carbon price in terms of driving the clean energy transition,” van Welie said. RGGI’s most recent auction in December cleared at only $5.61/ton.

Van Welie contrasted RGGI with Europe, where carbon emissions were trading last week at about 25 Euros/ton ($28), high enough that Royal Dutch Shell, BP and others are willing to build offshore wind on their own balance sheets without long-term PPAs, he said.

Transmission RFP

On an unrelated issue, van Welie said the RTO was “very pleased” with the response to its first-ever competitive transmission solicitation, which resulted in 36 project proposals by the March 4 deadline. (See ISO-NE Issues First Competitive Tx RFP.)

ISO-NE issued the solicitation in December to prepare the transmission system in the Boston area for the retirement of the Mystic Generating Station in Everett, Mass. The proposals will seek to address transmission facility overloads under peak load conditions, as well as system restoration concerns with the underground cable system. ISO-NE hopes to select the finalists for the work by the end of the year.

“We’ve got a lot of work ahead of us,” said van Welie, adding that the RTO will be releasing more details on the responses shortly.

New Member

In addition to its discussion on the futures study, the PC voted Thursday to admit trade group Advanced Energy Economy as a NEPOOL member. AEE, whose members provide energy efficiency, demand response, energy storage and natural gas, renewable and nuclear generation, was admitted as a Fuels Industry Participant.

Operating, Planning Procedure Revisions Approved

Members also approved revisions to the following operating and planning procedures:

OP-18 (Metering and Telemetering Criteria): adds a requirement to telemeter station frequency; identifies equipment requirements; specifies which requirements apply to existing and new equipment; and revises Section I (Purpose) to reflect current practice.
OP-23, Appendix I (Resource Auditing): clarifies the asset ID entry for certain reactive resources without an RTO-assigned asset ID.
OP-3 (Transmission Outage Scheduling): extends the maximum duration for an “opportunity outage” from 96 hours to 108 hours. An opportunity outage is one that fails to satisfy the minimum advance notice time required for planned short-term transmission outage processing and is submitted for RTO approval as a result of an unexpected opportunity to accomplish work that would otherwise require another outage at a less opportune time.
PP-3 (Reliability Standards for the New England Area Pool Transmission Facilities): replaces the term “governance participant” with the terms “market participant” and/or “transmission owner.”

March 8, 2020

CapX2050 Calls for More Tx, Dispatchability in Midwest

By Amanda Durish Cook

The Upper Midwest needs more transmission, more technology and preservation of some dispatchable generation for the sake of reliability, the CapX2050 study concluded last week.

The 10 Minnesota utilities behind the effort drew three major takeaways from the study:

More transmission infrastructure will be necessary in the Upper Midwest to accommodate resource transition.
Non-dispatchable resources alone can’t meet all energy requirements, so some traditional power plants will still be necessary.
Real-time operational demands will become trickier to manage and will require new procedures.

Building on the CapX2020 transmission effort focused on 2020 reliability needs, the CapX2050 study addresses how the grid can handle widescale reductions in carbon emissions by 2050. (See Minnesota Utilities Reunite for CapX2050 Study.) Like the 2020 effort, the 2050 study concentrated on the transmission system that serves Minnesota, eastern South Dakota and North Dakota, western Wisconsin and the surrounding areas.

The study’s report said grid support in the form of ancillary services will be needed in areas where large, dispatchable generation is retired. New transmission technology and storage resources will be required to deliver ancillary services.

MISO CapX2050 — The Brookings County-to-Hampton project, part of CapX2020 | *CapX2020*

The group said its findings track with conclusions from MISO Renewable Study Shows More Tx, Tech Needed.)

“The variability of the output of non-dispatchable resources, even within a single day, could lead to several thousands of [megawatts] being transferred across the transmission system, with reversals in direction of flow occurring in an equal but opposite magnitude during the same day,” the report warned. “Operating techniques, transmission infrastructure and analysis tools will need to become more sophisticated to more accurately identify and adjust in real-time to deal with these changes.”

The utilities said that simply adding more non-dispatchable resources cannot solve the problem of sometimes deficient energy supply.

“Abrupt changes in weather, including prolonged extreme weather conditions, sudden changes in consumer demand, or disturbances on the transmission system (i.e., outages) will increasingly challenge the ability of the electric grid to provide a continuous supply of energy as more non-dispatchable resources are added,” the report said. It added that maintaining some dispatchable resources and adding energy storage can keep the transmission system reliable.

In what should be déjà vu for MISO planners, the CapX2050 report also called for a “long-term comprehensive regional transmission plan.” The Organization of MISO States has been pressing the RTO for two years to develop a long-term transmission package to accommodate growth of policy-driven generation resources. (See MISO Cracks Door on Long-term Tx Planning.) The report reminded MISO that “transmission expansion has been shown to be cost-effective when considered as part of a larger market.”

At this point, the CapX2050 utilities aren’t calling for any specific transmission projects. CapX2020 culminated in an 800-mile, grid expansion in the Upper Midwest, including four 345-kV transmission lines in Minnesota, North Dakota, South Dakota and Wisconsin and a 230-kV line in northern Minnesota.

Great River Energy spokesperson Jenny Mattson said that while future studies under CapX2050 aren’t being ruled out, none are planned so far.

“Though there is no time frame for additional studies, we’ll continue to evaluate the system in partnership with other utilities and stakeholders, including legislators, regulators, communities and MISO,” Mattson said in an email to RTO Insider.

The utilities also said they’re “ready to engage with public and stakeholders” on planning for new transmission.