Page 1031 – RTO Insider

October 15, 2020

FERC Sides with PSCo in Co-op Dispute

A set of longstanding agreements do not obligate Xcel Energy’s Colorado utility subsidiary to provide an electric cooperative with priority firm transmission service to deliver energy from two third-party suppliers, FERC affirmed Thursday (EL20-14-001).

The commission’s ruling on rehearing stemmed from a dispute between Xcel’s Public Service Company of Colorado (PSCo) subsidiary and Glenwood Springs-based Holy Cross Electric Association, a co-op that serves about 55,000 customers in Eagle, Pitkin, Garfield, Mesa and Gunnison counties.

Holy Cross entered into two power purchase agreements with the Arriba (wind) and Hunter (solar) projects and asked PSCo to provide it with firm transmission service to deliver the contracted energy under a grandfathered transmission agreement between the companies — and not under PSCo’s Open Access Transmission Tariff.

In December 2019, PSCo asked FERC to rule that Holy Cross’ requests are not permitted under the companies’ power supply agreement, transmission integration and equalization (TIE) agreement, or operating agreement for economy — or non-firm — energy purchased by the co-op.

The power supply agreement stipulates that Holy Cross will purchase its full requirements from PSCo but that it may purchase economy energy from third-party suppliers. The TIE agreement lays out the terms under which PSCo and Holy Cross have agreed to operate their respective transmission networks as one system, with PSCo serving as the operator. The operating agreement sets out the procedures for scheduling and accounting for economy energy purchased by Holy Cross.

On March 31, FERC ruled that Holy Cross was not entitled to firm transmission service from PSCo under the agreements, concluding that the co-op’s capacity on the integrated system is limited to its load ratio share and that the additional firm service would exceed that share. The commission also pointed out that PSCo is not obligated to treat economy energy purchases as firm deliveries entitled to NERC’s highest curtailment priority.

PSCo dispute — Holy Cross Electric serves 55,000 customers in western Colorado. | *Holy Cross Electric*

On April 30, Holy Cross filed a request for rehearing and a conditional request for clarification of the March order. The co-op contended that the TIE agreement is governed by Colorado law, which holds that “written contracts that are complete and free from ambiguity will be found to express the intention of the parties and will be enforced according to their plain language.” Holy Cross added that Colorado legal precedent holds that, in contract disputes, parol evidence (that is, oral evidence from outside the actual contract) is only permitted when a contract is ambiguous, and that “a contract’s silence does not necessarily invite the introduction of parol evidence to clarify intent.”

Holy Cross contended that FERC’s March order provided no evidence that the TIE agreement is ambiguous, and it challenged the commission for using the power supply and operating agreements as parol evidence to interpret the TIE agreement, which it argued is separate from the other two agreements.

The co-op also contended “that the load ratio share capacity entitlement under the TIE agreement cannot reasonably be construed as limited to Holy Cross’ purchases from PSCo because the ‘detailed and unambiguous wording’ of the TIE agreement shows that Holy Cross’ ‘load ratio share capacity rights are a function of its native load and not any specific Holy Cross resource, including the power supply agreement,’” FERC noted.

‘Untenable’

The commission brushed aside that argument, calling it “untenable.” The issue at hand, the commission said, “is whether Holy Cross is entitled to firm transmission service for certain third-party purchases, which requires an analysis of the TIE agreement, power supply agreement and the operating agreement.” The commission had properly considered the rights of both parties under the three agreements without resorting to use of parol evidence, it said.

“In interpreting the term ‘load ratio share’ under the TIE agreement, the commission appropriately cited the definition in section 1.9 of that agreement, which references the method for calculating load ratio share in Appendix A, provision 6, to conclude that Holy Cross’ load ratio share is based on its requirements demands,” FERC wrote. “The commission did not look to any agreement other than the TIE agreement in interpreting the term ‘load ratio share’; nor did the commission look outside the TIE agreement to determine Holy Cross’ transmission capacity entitlement under the TIE agreement.”

While the TIE agreement lays out Holy Cross’ transmission entitlement, it does not address the question of whether the co-op’s request for additional firm service fits within that entitlement, the commission said. To make that determination, FERC examined the power supply agreement, which requires Holy Cross to purchase its full requirements from PSCo with exceptions made for economy energy.

“That Holy Cross is currently required to purchase its full requirements from PSCo is based on Holy Cross’ obligations under the power supply agreement and is not, as Holy Cross contends, an interpretation of the term ‘load ratio share’ under the TIE agreement,” FERC said. “Rather, given that Holy Cross’ load ratio share of the integrated transmission system is based on its requirements demands, and it is currently required by the power supply agreement to purchase its full requirements from PSCo, it necessarily follows that Holy Cross’ firm transmission capacity entitlement is being used to serve the full requirements of Holy Cross’ load, and that ‘for Holy Cross to obtain firm transmission service to receive power from the Arriba and Hunter projects, Holy Cross would require transmission capacity that is in excess of its load ratio share of the capacity of the integrated system.”

The commission additionally rebuffed Holy Cross’ contention that the March order prevents the co-op from using its rights under the TIE agreement on a basis comparable to PSCo. Holy Cross argued that the TIE agreement embodies FERC’s “golden rule” of comparability, which prohibits either party from making “adverse distinctions” about the other party’s use of an integrated transmission network.

“This argument … incorrectly presumes that the TIE agreement is the equivalent of an open access transmission tariff, which it is not,” the commission said. “As PSCo explained in its petition, the TIE agreement is a grandfathered transmission service agreement that predates Order No. 888.”

October 15, 2020

FERC Approves WECC Contingency Reserve Standard

FERC on Thursday gave NERC and WECC the go-ahead to introduce regional reliability standard BAL-002-WECC-3, but it also ordered the organizations to return in 2023 with a progress report on its effects on the bulk power system (RM19-20).

The new standard takes the place of BAL-002-WECC-2 a, approved by FERC in January 2017 as the regional equivalent of the continent-wide BAL-002-3 (Contingency reserve for recovery from a balancing contingency event) and successor to the original regional standard BAL-002-WECC-2. The standards specify the “quantity and types of contingency reserve required to ensure reliability under normal and abnormal conditions.”

The WECC standard includes a more stringent deadline for entities to restore contingency reserves following a disturbance recovery period: 60 minutes compared to 90 for the NERC equivalent. In addition, the WECC-mandated method for calculating minimum contingency reserves is more stringent than that given in the NERC standard because it requires “minimum contingency reserve levels that will be at least equal to the reliability standard minimum … and more often will be greater.”

Regional Requirement to be Removed

NERC and WECC originally submitted the new regional standard to FERC last September, arguing that some aspects of BAL-002-WECC-2a had been made redundant by the BAL-003-1 standard introduced in 2014.

WECC Contingency Reserve Standard — | *WECC*

In particular, the organizations claimed that requirement R2 of the regional standard — mandating that balancing authorities and reserve sharing groups in the WECC region maintain at least half the minimum contingency reserves as operating reserves — was no longer necessary. Requirement R1 of BAL-003-1 “addresses the same frequency response components … but in a results-based manner” because of its requirement that BAs “achieve an annual frequency response measure that is equal to or more negative than its frequency response obligation.”

To address any potential concerns about reliability impacts from retiring the 50% spinning reserve requirement, WECC performed a field test from May 2017 to April 2018 in which it obtained data from each BA and reserve sharing group on disturbance control standard (DCS) performance and frequency response in the Western Interconnection. In their petition to FERC, NERC and WECC said that “all 66 DCS events occurring during the field test period had a 100% pass rate, showing no degradation to DCS performance.”

Not satisfied with the submission, FERC issued a data request in February 2020 to the organizations seeking further data from May 2018 to September 2019, along with NERC’s frequency response records for the Western Interconnection from May 2017 to September 2019. The updated information was submitted in May 2020.

Standard Approved; Monitoring to Continue

With the expanded data set continuing to support NERC and WECC’s assertion, FERC gave its approval to the standard as “just, reasonable … and in the public interest.” However, the commission indicated it still holds reservations about “unique aspects of contingency reserves in the Western Interconnection [that] raise concerns about deliverability of contingency reserves within reserve sharing groups.”

Specifically, FERC noted that both the Northwest Power Pool and the Southwest Reserve Sharing Group contain BAs that have hydroelectric resources, which “represent a significant share of … contingency reserves.” The commission expressed concern that transmission constraints or limits on the hydroelectric system may constrain the ability of member BAs to access these resources.

As a result, FERC ordered that NERC and WECC submit an additional informational filing 27 months after the implementation of BAL-002-WECC-3, covering the same categories of data from the February 2020 data request for the 24 months following implementation. The commission also mandated that the organizations inform it immediately of “any adverse impacts resulting from the retirement of requirement R2” that are observed during the reporting period, along with any corrective actions that are taken or considered.

October 15, 2020

CAISO Fund Distributions Cleared by FERC

FERC on Thursday approved CAISO’s procedure for distributing more than $2 million in penalty proceeds and nonrefundable interconnection study deposits to its members (ER20-2604).

CAISO’s Tariff requires it to collect penalties for violations of its rules of conduct and deposit them in an interest-bearing trust account. At the end of each calendar year, CAISO distributes the proceeds, with accrued interest, to eligible market participants based on a formula that factors in the pro rata share of the grid management charge paid to the ISO by each participant. The Tariff also requires CAISO to seek FERC’s approval for any disbursements of penalty proceeds, which totaled $622,500 in 2019.

CAISO Fund Distributions — CAISO headquarters in Folsom, Calif. | © *RTO Insider*

“The methodology in CAISO’s proposal is consistent with relevant provisions in its Tariff for allocating and distributing penalty proceeds to scheduling coordinators,” FERC found.

CAISO had also petitioned FERC for permission to distribute $1,452,574.98 in nonrefundable interconnection study funds for projects interconnecting to Southern California Edison’s distribution system. The ISO noted the funds would be allocated to market participants without accounting for whether a participant had been assessed a financial penalty over the course of the year.

FERC determined that the methodologies in CAISO’s proposal were consistent with its Tariff. The commission concluded that “our decision to grant the petition is consistent with the commission’s disposition of prior CAISO filings where it proposed to distribute forfeited interconnection study funds with interest … without accounting for whether or not a scheduling coordinator had been assessed a financial penalty under section 37 or Tariff during the relevant calendar year.”

October 15, 2020

MISO Outlines Early Long-term Tx Plan Details

MISO Readying Intensive Transmission Planning.)

“First and foremost, I would call this a transmission planning study. … What we’re looking for are transmission needs to facilitate the efficient use of new resources,” Senior Manager of System Planning Coordination Jarred Miland told stakeholders during a Planning Advisory Committee meeting Wednesday.

Miland said MISO faces “significant grid and stability issues” if it doesn’t seek out transmission investments. With more inverter-based generation, the grid operator expects more erratic dispatch patterns and regional energy transfers to increase and become less predictable.

He said MISO will investigate long-term project contenders’ reliability, economic and resource adequacy benefits across multiple annual cycles of its Transmission Expansion Plan (MTEP).

MISO transmission plan — Jarred Miland, MISO | © *RTO Insider*

“We’re looking at everything holistically,” Miland said.

Staff intends to present “robust business cases” for every project it advances for approval, Miland said. He added that previous findings under MISO’s R esource A vailability and N eed initiative, ongoing Renewable Integration Impact Assessments and new planning futures will feed into the long-range study.

Some stakeholders said transmission buildouts under a long-range plan would allow renewable generation to connect at lower costs. They asked if MISO was courting a chicken-or-egg scenario where transmission projects encourage renewable generation investment over other generation types.

“I think transmission is agnostic. We are looking at what the world is telling us. Look at the generation interconnection queue [and] state targets,” Miland said. “The grid is not evolving 30 years from now. It’s evolving now.”

Some stakeholders argued that MISO needs to draft Tariff language or business practices that lay out a long-range transmission study process.

“I don’t know if I see the need to put this in our Tariff. It’s our charge to do transmission planning,” Miland said.

Mississippi Public Service Commission counsel David Carr disagreed, saying that MISO has established manuals on subregional planning and generator interconnection studies.

Miland pointed out that the RTO’s market-congestion planning studies aren’t laid out in the Tariff or business practice manuals. But he added that MISO could consider some revisions.

“MISO has full authority to do planning, and we need them to do planning for the grid of the future,” the Sustainable FERC Project’s Lauren Azar said.

“FERC expects MISO and other RTOs to do this kind of planning,” agreed Clean Grid Alliance’s Natalie McIntire.

“It takes 10 years to build a transmission project, so we don’t want to be looking five years out … and then miss the boat,” Miland said. “If we are nearsighted, and we keep looking five years out, we have the potential to wind up with a system that’s not as efficient as it could be.”

Stakeholders also pressed staff on the projects’ names. Projects in the grid operator’s last long-term planning package in 2011 were called Multi-Value Projects.

Miland said the projects’ cost allocation could lend them their names. “That cost-allocation effort may very well produce a new category.”

The first MTEP 21 long-range projects are possible at the end of next year. “If that happens, we may very well be looking at our existing Tariff for cost allocation,” Miland said. “Cost allocation takes a significant amount of time to develop and get FERC approval.”

Miland said he expects the first cost allocation discussions with stakeholders to begin by the end of this year.

While the long-term plan’s goal is to move away from “just-in-time projects,” Miland said, any projects uncovered during the course of MTEP 21 would probably only focus on 10 to 20 years into the future. Longer-term projects would most likely arrive in later MTEPs under a different cost allocation, he said.

“This long-range transmission plan is a big apple. We can’t bite it all at once,” Miland said.

MISO will initially focus its efforts geographically, Miland said, paying special attention first to needs in its West and Central regions and the Midwest-to-South interface.

McIntire asked that the first project approvals lay out a “cost-effective foundation” for other long-term project approvals to build on.

“We’re on the same wavelength,” Miland said.

October 15, 2020

FERC Walks Back Part of Affected-system Order

FERC has reconsidered an aspect of recent orders calling for more transparency into how RTOs analyze each other’s systems during interconnection studies.

The commission on Thursday walked back a portion of an earlier ruling, saying MISO, SPP and PJM don’t have to rely on one another’s dispatch assumptions to carry out an affected-system study (ER20-942-001, ER20-938-002).

FERC ruled last September that the RTOs’ joint operating agreements do not provide enough clarity on how they handle generator interconnection studies along their seams. The commission in June ordered joint compliance filings to provide clearer descriptions of affected-system studies carried out for interconnecting generation. (See FERC Orders More Detail in Affected Systems Compliance.)

The commission in June found that an affected-system study using different dispatch assumptions than a project’s host RTO may result in unjust and unreasonable rates through network upgrade cost assignments.

But on Thursday, FERC said it was too hasty in directing the use of another RTO’s dispatch assumptions in affected-system studies. It even flipped its stance and said that if the RTOs were to use one another’s fuel-based dispatch assumptions in study modeling, the results might produce unreasonable rates.

“Upon reconsideration, we are persuaded by the arguments raised on rehearing that the commission should not have directed the affected-system RTO to use the dispatch assumptions of the host RTO when it conducts affected-system studies,” FERC said.

It agreed with MISO, SPP and PJM that an RTO’s study process is too complicated to simply cut and paste dispatch assumptions.

“Each RTO’s fuel-based dispatch assumptions are an integrated component of their larger interconnection and planning models, and more specifically, their corresponding base cases, which are different for each RTO, and in some cases use different load assumptions. We agree with [MISO, SPP and PJM] that these fuel-based dispatch assumptions are not logically severable from the framework in which they were developed, and in many cases, are not compatible with the affected-system RTO’s processes,” the commission said.

October 15, 2020

Differences Aside, West Coast OSW Can Learn from East

West Coast offshore wind developers can draw on environmental lessons from projects in the Atlantic Ocean, but they must still prepare for challenges unique to the Pacific, a panel of experts said Tuesday.

Developers should also work among themselves and with independent researchers to collect and standardize as much ocean wildlife data as possible well before construction planning, as well as create “adaptive management strategies” to mitigate risks to species after turbines are in place, the experts advised.

“While wildlife risk assessment and the tools developed on the East Coast can inform development on the West Coast, the unique aspects of the West Coast must be identified and associated risks appropriately assessed and addressed,” Adam Stern, executive director of Offshore Wind California, said as he kicked off the panel discussion at the American Wind Energy Association’s Offshore Windpower Virtual Summit.

Stern noted that 14 developers responded to U.S. Bureau of Ocean Energy Management’s 2018 call for information and nominations to develop offshore wind facilities off the coast of California. Interest is also building to develop off the Oregon coast as well, he added.

Sarah Courbis, marine protected species and regulatory specialist at Advisian Worley Group, provided a rundown of the myriad ecological differences between the West and East coasts.

The East Coast has a large, relatively shallow ocean shelf, with a warm Gulf Stream current that comes up year-round. In contrast, the West Coast has a very narrow shelf with a steep drop-off close to shore, characterized by changing currents over the course of the year and significant upwelling near shore, Courbis explained.

“As a result, there are differences in the wildlife and the habitats and what types of areas they use,” she said.

While both oceans are home to endangered right whales, Courbis said the southern resident killer whale would likely be a bigger concern on the West Coast.

The West Coast also has more pinniped species, such as seals, than East Coast, she said, and those species range offshore differently in the Pacific.

She also noted the many differences between bird species on the two coasts — and that species listed as endangered and threatened or “species of concern” will also be different.

Courbis advised developers to integrate environmental considerations into the process used to optimize turbine configurations for producing the most power cost-effectively.

That process “needs to consider what’s optimal for environmental impacts and permitting purposes,” she said. “If it doesn’t, you can have some very suboptimal situations that cause delays or problems with getting your authorizations, and your schedules may be thrown off.”

“We’re having this conversation early, and we have an opportunity that perhaps the East Coast didn’t have to really get ahead of development and start talking about regional data collection and standardization,” said Brita Woeck, manager of permitting and environmental affairs at Deepwater Wind.

The earlier start will give the industry a “broadscale” view of the West Coast environment, instead of leaving those details to be addressed repeatedly within the limited scope of individual wind projects, Woeck said.

“We really need to hone in on the species and specific uncertainties on the West Coast, focus our efforts now on getting those data gaps filled and look to the East Coast where we can to draw experience,” she said.

Woeck said East Coast projects will be the first to implement best practices and conduct post-construction monitoring for marine mammals, fish and birds.

“They serve as a real useful jumping-off point for taking some of those learnings and tailoring the practices to the species and habitats that are specific to the West Coast,” she said.

For the Birds

“Is offshore wind good for birds? I would say ‘yes,’” said Garry George, clean energy director at the National Audubon Society.

George cited a study by his group’s own climate scientists that found 389 species of birds worldwide would be threatened with extinction if the earth’s average temperature increases by 3 degrees Celsius over pre-industrial levels.

Garry George, National Audubon Society | *AWEA*

“The good news is, if we can hold warming down to 1.5 degrees Celsius, then we can actually help 75% of these birds,” George said. “Climate change is the biggest threat to birds.”

That’s why Audubon advocates for a policy of 100% clean energy and net-zero emissions by 2050, he said.

Seabird populations have already declined by about 70% since the 1950s, George said, before turning to a slide in his presentation that showed “the sum of what we pretty much know about the interaction” of floating turbines and seabirds off the California coast: “0.”

George noted that the slower progress in California OSW development has provided researchers and developers more time to gather data on the issue.

“I don’t want us to think we have to do everything now, but we have to have adaptive management plans in place” to mitigate potential detrimental outcomes from turbines, George said. As an example, he suggested improving onshore habitats and breeding grounds for seabirds.

Streamline, Standardize

Mari Smultea, CEO of Smultea Sciences, said developers on both coasts have access to numerous and extensive wildlife databases. But she advocated for streamlining that data to foster more efficient planning in the West.

“One thing I suggest for the West Coast as we develop this is that we come up with one database where we all contribute the data to the same source, because sometimes these things are spread out across different data sources,” Smultea said.

She advised that developers come together in the “preplanning” phase to review existing data and standardize collection.

Smultea said “adaptive monitoring” of species should begin once an OSW facility has commenced operations, “where we can get feedback on what’s worked and what hasn’t worked so well in the field and how we can improve that.”

OSW siting on the East Coast has become more regionalized, while the West Coast — with its larger state coastlines — remains state-focused with separate task forces managing the California, Oregon and Hawaii processes, according to Desray Reeb, a marine biologist with the U.S. Bureau of Ocean Energy Management.

Reeb said BOEM has tried to be “proactive about stakeholder requests” and use its experience in analyzing OSW survey, site assessment and construction plans to compile “updated regulatory guidance” for developers.

“Although all these lessons are not necessarily directly transferable to the West Coast because of the environmental differences, some actually are,” she said. “I think we really are trying to take whatever we can from the East Coast experience and make the best of it on the West Coast without reinventing the wheel.”

October 15, 2020March 11, 2025

Coordinated OSW Tx a ‘Perishable’ Chance for US

A discussion at the American Wind Energy Association Offshore Windpower Virtual Summit on Tuesday reinforced the argument that a planned transmission network for offshore wind would be more beneficial than the current every-project-for-itself approach.

But it also brought urgency to the issue. The benefits of an offshore network decreases with each project that interconnects by itself, said James Cotter, Shell general manager of U.S. offshore wind. And “an individual project that has a route to market or has its permits in hand doesn’t want to be held up by waiting for the bigger, better solution, so it will run itself.”

State and federal planning regulators are in the process of choosing between developers building their own generator lead lines — the radial system — or independent transmission construction and ownership, the network system. “If they’re all radial connections at AC … for 2 GW or 4 GW, you might end up with a difference of six to 12 cables routing through, whereas if you could use HVDC in a coordinated way, you only have two to three cables coming in,” Cotter said. “Once you’ve laid a cable, in some of the approaches, it makes it very hard, if not impossible, to lay another project’s set of cables in proximity to that; it’s a very constrained area.”

Clockwise from top left: Kate McKeever, RWE; Christopher Hayes, DNV GL; James Cotter, Shell; and Zach Smith, NYISO | AWEA

The U.S. has an “amazing, perishable opportunity of saying, ‘How do we optimize transmission across the RTOs and ISOs, across the states, to enable cost-effective volume that will bring the industry here?’” Cotter said.

Zach Smith, NYISO vice president for system and resource planning, said transmission planning takes time, as planners must consider all options and at the same time.

“We do not do top-down planning; we don’t dictate solutions. We turn to our market and what the market wants to do,” Smith said. “One alternative is we turn to the state … and what public policies do they see as driving the need for transmission. If they declare there is a transmission need driven by public policy, then we act on that.”

New York hosted a technical conference on transmission for renewable resources on Oct. 9, where Smith told state officials that without coordinated planning, transmission congestion around New York City could increase after the first 6,000 MW of offshore wind is interconnected. (See OSW Growth to Test New York’s Transmission Grid.)

In terms of interregional planning, a Northeastern planning protocol was “beefed up” after Order 1000 to improve coordination among ISO-NE, NYISO and PJM, Smith said. The Inter-Regional Planning Stakeholder Advisory Committee (IPSAC) meets regularly to explore opportunities for joint transmission development, but “thus far, nothing has come up in terms of some definitive project.”

Zach Smith, NYISO | AWEA

Massachusetts hosted a technical conference in March before officials decided they should not this year solicit proposals for a transmission network for offshore wind generation. Developers have proposed interconnecting up to 1,200 MW at various points along the southern New England coast, from Barnstable and Brayton Point in Massachusetts, to Kingston, R.I., and Montville, Conn. (See Mass. DOER Explores Transmission for OSW.)

Moderator Kate McKeever, director of government and regulatory affairs for U.S. offshore wind at German utility RWE, asked what constraints offshore wind would cause for onshore transmission.

Given that offshore wind will be injecting directly to load centers in New York City and Long Island, Smith said it will alleviate some of the transmission constraints upstate, “but there are going to be plenty of times a year when the amount of power coming in from offshore greatly exceeds whatever amount of load is in that local area, and you’re going to need transmission facilities to get that power either off Long Island or out of the New York City area.”

“We already were seeing constraints within the New York City and Long Island area,” he said. “It’s just natural that the power will want to flow out … and up into the rest of New York and then across the Eastern Interconnection, so you’ll need transmission investment in those areas to unbottle the constrained renewable resources.”

Such investment would obviously help ratepayers in New York, he said, but “it ultimately turns into an East Coast issue where everyone could benefit, and no matter what, you have to overcome those transmission constraints from a legacy grid that was not designed to deliver that kind of power.”

October 15, 2020

MISO Winds down MTEP 20 Planning, Focuses on 2021

MISO is wrapping up its 2020 Transmission Expansion Plan (MTEP 20) with an eye on next year’s planning cycle that contains more aggressive renewable energy predictions.

MTEP 20 includes 514 projects costing slightly more than $4 billion. The most expensive project remains Ameren’s new Massac substation in Southern Illinois and the conversion of the nearby Joppa station from 230 kV to 345 kV, at an estimated cost of $112.4 million.

“At this time of the year, we’re ending MTEP 20 and starting MTEP 21,” planning engineer Scott Goodwin told stakeholders during a Planning Subcommittee meeting Tuesday.

MISO has closed the request deadline for special targeted study requests to be conducted under MTEP 21.

The Environmental Groups sector has requested the grid operator conduct two studies examining footprint changes if either LG&E and KU Energy or Memphis Light, Gas and Water join MISO within the next five years.

Transmission owners oppose the request. “We didn’t think MTEP is the place to evaluate new members. It’s about evaluating transmission projects,” Entergy’s Yarrow Etheredge said.

Goodwin said MISO will begin scheduling MTEP 21 subregional planning meetings to discuss project needs. The RTO will also soon release MTEP 21 economic models that draw on its new, 20-year futures scenarios, economic planner Nickolas Przybilla added.

MISO continues to establish resource expansion location estimates under the three 20-year MTEP 21 futures. (See MISO Foresees Massive Shift to Renewables by 2040.)

The grid operator is relying on a combination of integrated resource plans and utilities’ public carbon-reduction commitments to predict resource siting under the new planning futures.

“It’s both the media and IRPs,” MISO Planning Manager Tony Hunziker said during a Planning Advisory Committee conference call Wednesday. “It’s recognizing that sometimes a press release precedes plans and also recognizing that not all utilities have to file integrated resource plans.”

Hunziker said MISO is drawing on the National Renewable Energy Laboratory’s Annual Technology Baselines to help predict when generation technologies are increasingly adopted.

MISO’s Future I expects solar expansion on par with the footprint’s current amount of wind generation. In Future II, the RTO foresees energy storage and electrification beginning to join solar on center stage. By Future III, electrification and storage take a consequential role in supply and demand, while wind and natural gas generation each taking a 30% share of the energy mix. Future III also assumes 50% renewable energy use.

Some stakeholders said MISO should not simply take utilities’ target announcements at face value and should rely on something more concrete to make future generation assumptions.

“I just don’t think we have evidence that utilities waffle a lot. I don’t think we have a record like that,” Clean Grid Alliance’s Natalie McIntire said. “When utilities make announcements, they tend to be well thought out.”

States, cities and utilities in the MISO footprint are fast piling up carbon-reduction goals.

Michigan is the latest state to announce a carbon-neutrality goal. Gov. Gretchen Whitmer late last month said the state will meet a net-zero emissions goal by 2050, if not sooner. The announcement late last month will likely cause utilities to rethink their IRPs.

Ameren and Entergy have also committed to carbon neutrality by 2050.

Queue Timeline Cutbacks Still in the Works

To reach those targets, MISO must make headway on the 106 GW of mostly renewable generation in its generator interconnection queue’s 705 projects.

The mammoth queue is down from a record 756 projects, totaling 113 GW, in August. MISO said about 20 interconnection customers in its South and West planning regions failed to provide proof of site control and were forced to withdraw projects.

To speed up queue processing, the grid operator plans to whittle down the three-part definitive planning phase and generation interconnection agreement negotiations from more than 500 days to a calendar year. (See Record Number of Entrants Line up for MISO Queue.)

MISO engineer Miles Larson said the RTO plans to cut about 140 total days from queue processing so it can catch up on projects and bring the four planning regions’ studies into the same queue-cycle year. MISO is currently processing queue cycles dating back to 2017.

“We continue to see an overwhelming support for reducing the [generation interconnection process] timeline,” Larson said during an Interconnection Process Working Group conference call Monday.

MISO wants GIA negotiations and execution pared from about 150 day to 100 days. That means some negotiations will simultaneously occur as staff wrap up final network upgrade studies.

Larson said MISO wants to arrive at a “repeatable and sustainable” process to keep the queue humming.

“The closer we can get our process to 365 days, the closer we get to aligning the DPP study process with the MTEP study process,” he said, referencing MISO’s plan to better match MTEP planning with network upgrades necessary for interconnections.

Larson said that for the cutbacks to stick, interconnection customers need to ready their generation projects as much as possible before entering the queue.

“MISO alone cannot reach the reduction goal,” he said. “In order to succeed in this effort, every entity needs to identify internal efficiency opportunities.”

October 15, 2020

EBA: Public-private Engagement Crucial on Cyber Threats

This year’s official actions on supply chain risk management are only the beginning of the collective changes needed to grapple with foreign cyber threats to the utility sector, industry insiders at the Energy Bar Association’s Fall Conference said Tuesday.

Those actions included President Trump’s declaration of emergency in May; information requests from the Department of Energy, NERC and FERC; and the new CIP-013-1 reliability standard that took effect earlier this month.

NERC Cyber Threats — Robert Kang, Southern California Edison | *Energy Bar Association*

“Utilities are now at the cyber front lines of protecting national security,” said Robert Kang, a senior attorney for Southern California Edison, citing the intelligence community’s most recent Worldwide Threat Assessment that accused China, Russia and other countries of “using cyber operations … to disrupt critical infrastructure.”

“That means we, along with the government, have to step up our engaging. … In terms of presentations that I give to the C-suite or to the board of directors, I think that’s actually key,” he added.

Kang said government engagement with utilities has been accelerating in recent years in several key areas. The first is in support of efforts by utilities to reverse engineer grid equipment in search of components made by suppliers suspected of assisting with online espionage — for example, China’s Huawei and ZTE, which have both come under increased scrutiny from regulators and lawmakers. (See FERC, NERC Offer Cyber Supply Chain Guidance.)

Utilities are often prevented from performing such examinations themselves by supplier contracts that prohibit reverse engineering, but Congress provided a potential workaround for the issue in the National Defense Authorization Act of 2020, which authorized DOE to form a task force to examine critical equipment for suspect components with the help of the National Laboratories. Kang said that “a number of utilities … are really looking forward to seeing [the] task force get stood up.”

Communication Within Entities Essential

Kang said the government’s ability to issue binding edicts — not just laws, but also NERC’s reliability standards — can be another powerful form of assistance for utilities, as such requirements can force entities to make needed improvements they might otherwise be reluctant to perform because of cost or convenience issues.

Picking up this thread, Howard Gugel, NERC’s vice president of engineering and standards, admitted that while the organization had moved quickly to implement requirements for cybersecurity risk management, there is still a lot of work to make the topic central to the conversation.

“When we planned the system, we didn’t really think about what the cyber impacts … were, and also the [information technology] folks didn’t really think about [how] the stuff that they installed … could potentially impact the bulk electric system,” Gugel said. “[We’re starting] a conversation between the two groups to say [that] as we’re planning the system, we need to … understand what the cyber impacts could be, and also when we’re planning to do cyber installations, what could be the impact on the bulk electric system.”

Both Gugel and Kang encouraged listeners to expand their knowledge beyond their job descriptions — for example, lawyers to talk with technology specialists and vice versa. These conversations can not only build rapport between different parts of an organization but can also help both sides develop useful insights to help the entity overall.

Recovery Systems also Under Threat

From the government’s perspective, Patricia Hoffman, principal deputy assistant secretary in DOE’s Office of Electricity, said the department has seen promising signs that the industry is taking the cyber threat seriously. She warned utilities that maintaining a strong defense against state-backed attackers with considerable resources at their disposal will require thinking several moves ahead.

“They want to gain access and persistence. Then they want to be able to prepare the battle space … to put malware on your system, and then be able to … not only execute [an attack], but prevent your ability to recover,” Hoffman said. “So, we want to keep that in mind as you move forward, and think about [your] opportunities and responsibilities … as an entity in this sector.”

October 15, 2020March 11, 2025

FERC: Send Us Your Carbon Pricing Plans

FERC on Thursday proposed a policy statement inviting states to introduce carbon pricing in wholesale electricity markets but said it had no authority to initiate such programs itself (AD20-14).

Chairman Neil Chatterjee, a Republican, called the proposal — coming just two weeks after the commission’s technical conference on carbon pricing — a “landmark action.”

But Democratic Commissioner Richard Glick said that although the proposal is a “positive step forward,” the commission “consistently turns a blind eye” to climate change by refusing to assess whether new natural gas pipeline projects it has approved have a significant impact on greenhouse gas emissions. He noted that he was dissenting on several pipeline certificate orders Thursday, saying the commission’s position ignores a D.C. Circuit Court of Appeals order requiring such assessments.

Ravenswood Generating Station, a 2,480-MW fossil fuel plant in New York City

“I wouldn’t describe this draft policy statement as groundbreaking, but if it is finalized, it does provide the states some confidence that the commission will accommodate state carbon pricing decisions,” Glick said in remarks during the commission’s virtual open meeting. “There is an obvious opportunity for consensus here, but we can’t move forward if the commission continues to treat climate change differently than all other environmental impacts.”

Republican Commissioner James Danly dissented in part on the proposal, calling it “unnecessary and unwise.”

Jurisdiction

The statement would assert that the commission has jurisdiction over organized wholesale electric market rules that incorporate a state-determined carbon price and “also seeks to encourage regional electric market operators to explore and consider the benefits of establishing such rules,” FERC said in a press release.

Michael Borgatti of Gabel Associates moderates a 2019 panel discussing carbon pricing possibilities in PJM. | © RTO Insider

The commission said the Sept. 30 technical conference highlighted the potential benefits of carbon pricing, including “technology-neutral, transparent price signals … and providing market certainty to support investment.” (See FERC Urged to Embrace Carbon Pricing.)

“As states actively seek to reduce greenhouse gas emissions within their regions, carbon pricing has emerged as an important, market-based tool that has wide support from across sectors,” Chatterjee said in a statement. “The commission is not an environmental regulator, but we may be called upon to review proposals that incorporate a state-determined state carbon price into these regional markets. These rules could improve the efficiency and transparency of the organized wholesale markets by providing a market-based method to reduce GHG emissions.”

In a teleconference with reporters, Chatterjee rejected the notion that the proposal represented an evolution in his thinking on climate change, saying he has been consistent since he joined the commission: that it is a real and existential threat and human-caused, and that “decarbonization should occur through market-driven” solutions.

FERC defined carbon pricing to include both “price-based” methods that directly establish a price on GHG emissions as well as “quantity-based” approaches under a cap-and-trade system.

The commission noted that 11 states — California and the 10 New England and Mid-Atlantic states in the Regional Greenhouse Gas Initiative — use a form of carbon pricing. PJM, NYISO and ISO-NE are also investigating it.

FERC said regional market rules incorporating a state-determined carbon price are within the commission’s jurisdiction over wholesale rates under Federal Power Act Section 205. “Whether the rules proposed in any particular FPA Section 205 filing do, in fact, fall under commission jurisdiction is a determination we will make based on the facts and circumstances in any such proceeding.”

The Analysis Group’s study concluded that New England needs a carbon price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet New England states’ carbon emissions goals. | Analysis Group

The statement noted that FERC “has long permitted generating resources to recover through wholesale rates the costs of complying with environmental regulations, including the costs of emissions pricing regimes,” citing its approval of the CAISO Energy Imbalance Market’s incorporation of a carbon charge on EIM imports into California.

The commission also cited the Supreme Court’s EPSA decision, which said the commission has jurisdiction over practices that “directly affect” wholesale rates as long as it doesn’t cover matters the FPA reserves for exclusive state jurisdiction. The court ruled that FERC’s actions under Order 745, which covers demand response compensation, “meet that standard with room to spare.”

“Because the decision about the carbon price would be determined by the state — which could select a price of zero, should it choose — state authority would be unaffected, further removing any doubt that rules that incorporate such a state-determined carbon price would comply,” the commission continued.

“Incorporating a state-determined carbon price into RTO/ISO markets could represent another example of the type of ‘program of cooperative federalism’ that the court noted with approval in EPSA,” FERC said.

Comments Sought

The commission will accept comments on the proposed policy statement until Nov. 16 with reply comments due Dec. 1.

FERC said it seeks comment on what information it should consider when reviewing such a filing, including:

How do market design considerations change based on how the state or states determine the carbon price? How will that price be updated?
How does the proposal ensure price transparency and enhance price formation?
How will the carbon price or prices be reflected in LMPs?
How will the incorporation of the carbon price affect generation dispatch? Will it affect how the market co-optimizes energy and ancillary services?
Does the proposal result in economic or environmental “leakage,” allowing production to shift to more costly generators in other states, without regard to their carbon emissions? How does the proposal address such leakage?

A Marker

Chatterjee said the proposal is a “marker signaling that this commission encourages efforts” to introduce carbon pricing in RTO/ISO markets.

“When it comes to our markets, fuel-neutral carbon pricing stands in stark contrast to other state policy tools, like subsidies, which can amount to hidden costs that degrade market efficiency and skew price signals, ultimately hurting the consumer,” he said. Glick and the chairman have battled over the commission’s orders setting price floors on capacity resources that receive subsidies, including over PJM’s expanded minimum offer price rule (MOPR), which was the subject of a compliance order Thursday. (See related story, FERC Acts on PJM MOPR Filing.)

“If states continue to pursue carbon pricing … they should have confidence that those proposals will be not be a dead letter on our doorstep, confidence that we recognize the benefits that such proposals, if properly designed, could bring to our markets, and confidence that we will bring our pragmatic, market-based lens to this conversation,” Chatterjee continued.

He cautioned that FERC would not take proactive action to set a carbon price, however. “I’ll say it again: The FPA does not give us authority to act as an environmental regulator. We have neither the expertise nor the authority to drive emissions policy in this space. So that is not the objective here today.”

The chairman praised Glick for working with him “to find common ground. It enabled this commission to provide bipartisan leadership and bring clarity to a difficult issue. That’s so crucial here where a broad set of voices have called on us to do just that.”

Danly: ‘Better to Wait’

“It’s better to wait to be in receipt of a plan rather than to issue this kind of a policy statement when we haven’t actually seen the kinds of programs that could be developed or proposed,” Danly said. “It’s certainly premature to opine on jurisdictional questions when we are denied the benefit of actually seeing details of what might be proposed.”

He said he concurred in part “because the substance of the policy statement really boils down to little more than an affirmation that utilities still enjoy the rights to file under Section 205 to propose tariff provisions.”

Danly noted that he also dissented on Order 2222 over similar concerns. “There I questioned the commission’s seizure of authority at the expense of the states and advocated that ‘we should allow the RTOs and ISOs … to develop their own DER programs in the first instance.’ Then the question of the commission’s jurisdiction will be ripe.” (See FERC Opens RTO Markets to DER Aggregation.)

“Without seeing a proposal,” Danly wrote, “the commission predetermines that any such proposal will be within the commission’s jurisdiction and ‘would not in any way diminish state authority.’ That may well turn out to be true, but I would have waited until we had an actual 205 filing before us rather than prejudging the issue based on unstated assumptions about how such programs might work. It is easy to imagine any number of RTO/ISO carbon-pricing proposals that would violate the Federal Power Act by impermissibly invading the authorities reserved to the states. This policy statement is not, as the majority’s order characterizes it ‘another example of the type of “program of cooperative federalism” that the court noted with approval in EPSA.’ There is no program. This is instead a nonbinding, blanket dismissal of potential jurisdictional concerns.”

Chatterjee and Glick rejected that characterization. “We are proposing a framework for applying our jurisdiction, not ‘prejudging’ particular matters or pre-emptively ‘dismiss[ing] … potential jurisdictional concerns.’”

Reaction

The American Wind Energy Association and the Electric Power Supply Association — two of the organizations that urged the commission in April to hold the technical conference — were quick to applaud the commission’s action. (See IPPs, Renewable Groups Seek FERC Carbon Pricing Conference.)

“An overwhelming consensus emerged at the [FERC technical] conference that carbon pricing in markets is a powerful and cost-effective tool to drive down emissions and achieve state policy goals while preserving the benefits of competition. The policy statement reflects this consensus,” said Amy Farrell, AWEA’s senior vice president for government and public affairs.

“We are pleased to see that FERC is continuing to dig into the challenging but important issue of carbon pricing and seeking to meaningfully advance the conversation,” said EPSA CEO Todd Snitchler. “EPSA supports market-based tools including an economy-wide or regional price on carbon that would allow all power providers to compete to reduce emissions at the least cost to consumers while meeting reliability needs.”

“This is a constructive signal but has no immediate applicability since it was not adopted as official policy,” said the American Council on Renewable Energy, which was also among the groups seeking the conference. “Unfortunately, however, FERC acted with more force with regard to a compliance filing from wholesale power market operator PJM Interconnection on FERC’s minimum offer price rule order, which imposes new costs on ratepayers to subsidize fossil generation at the expense of more cost-effective renewable power.”

“While we’ll need to see future orders on compliance to determine the precise severity of this action, renewable energy investment decisions in the Mid-Atlantic region are already impacted by the MOPR, and preferential treatment for fossil fuel generators will only grow in subsequent auctions as costs for renewable power continue to decline,” added ACORE CEO Gregory Wetstone. “These policies take us in the wrong direction from where we need to be to address our climate imperatives and grow the renewable energy economy, and are being challenged in court by ACORE and allied groups.”