MISO and SPP state regulators appear intent on completing their work to improve the RTOs’ interregional coordination before 2021 arrives.
The Seams Liaison Committee (SLC), comprising regulators from the Organization of MISO States and SPP’s Regional State Committee, met virtually and briefly Monday, deciding to develop a decision matrix to help them prioritize the various recommendations offered up for their consideration.
Admitting he may have had “reckless optimism about wrapping up at the end of the year,” Arkansas’ Ted Thomas, SLC co-chair along with Texas’ DeAnn Walker, said the matrix should “do good,” given the difficulty of holding in-depth discussions over the internet.
“The joy of virtual meetings,” he said.
Thomas, Walker and OMS Executive Director Marcus Hawkins will work together on the decision matrix. They hope to have a workable format that they can discuss with the full RSC and OMS on Oct. 26 and 29, respectively.
Walker said she wanted to have an “orderly way” to step through the recommendations made by the RTOs’ market monitors. That came into clearer focus, she said, as Hawkins went through a list of recommendations and the grid operators’ responses. (See MISO, SPP Respond to Monitors’ Studies.)
SPP responded to recommendations for coordinated transaction scheduling, interface pricing and the MISO Independent Market Monitor’s report on market-to-market (M2M) coordination. Staff added clarifying remarks and noted which recommendations are included in SPP’s 2020 Market Roadmap.
MISO detailed its responses to the same recommendations, noting whether they have been included in its Integrated Roadmap or the IMM’s 2019 State of the Market report.
NERC’s Reliability and Security Technical Committee (RSTC) held a special meeting Wednesday to wrap up unfinished agenda items from its last meeting in September, when it ran out of time because of an extended debate over a plan for taking over the work of the disbanded Planning, Operating and Critical Infrastructure Protection committees. (See NERC RSTC Briefs: Sept. 15, 2020.)
SITES Revisions Underway
The issue that caused the most contention at the September meeting was the scope document for the Security Integration and Technology Enablement Subcommittee (SITES), intended to recommend “practices for incorporating cyber and physical security aspects” into utilities’ business activities. Several participants expressed surprise at the focus on cybersecurity at the expense of transformative business applications, which they had understood to be the goal of the subcommittee. The document was tabled for further discussion.
RSTC Vice Chair David Zwergel, of MISO, asked for volunteers to help revise the document, with the goal of bringing it back to the committee for approval at its next meeting in December. Kayla Messamore of Evergy, ERCOT’s Christine Hasha and Carl Turner of Florida Municipal Power Agency agreed to take part in the revision process.
Consent Agenda Items Approved After Debates
The RSTC’s business for this meeting primarily consisted of items from the previous meeting’s consent agenda that were pulled for further discussion because of a motion by Brian Evans-Mongeon of Utility Services Inc.:
Standard authorization request (SAR) for MOD-025-2 — Unit verification and modeling.
SAR for revisions to PRC-023-4 — Transmission relay loadability.
Reliability guideline: Gas and electrical operational coordination considerations — posting for 45-day comment period.
Reliability guideline: Distributed energy resource verification — posting for 45-day comment period.
White paper on assessment of DER impacts on NERC reliability standard TPL-001.
All items passed, with the exception of the reliability guideline on gas-electric coordination. The guideline was remanded to the Operating Reliability Subcommittee on a motion by Evans-Mongeon, who argued that NERC’s Electric-Gas Working Group deserved a chance to provide input into the resolution before it was passed.
Another dispute emerged during the discussion on the SAR for MOD-025-2, when Duke Energy’s Greg Stone moved that a provision in the document’s scope section calling for data to be “analyzed and used properly by transmission planners and planning coordinators” be removed, on the grounds that the language was not clear. However, his motion was defeated, with several members arguing that editing a SAR is not the committee’s purpose and that if the wording was vague, then it could be addressed by stakeholder comments.
Evans-Mongeon also questioned the white paper on assessment of DER impacts to TPL-001, calling it premature in light of the fact that the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group is working on another white paper covering DER impacts to the rest of NERC’s standards that could be released as early as December. He moved for the paper to be held so that a more thorough evaluation of DER impacts to all reliability standards can be completed.
In response, SPIDER Chair Kun Zhu, of MISO, explained that the group had already done “thorough homework” on TPL-001 and felt there was no reason to delay its analysis until work on the other standards was completed, when releasing the results earlier might help achieve a more reliable system. This view was supported by most other members, and the white paper was endorsed by the committee.
Committee Feels Growing Pains
Part of Wednesday’s meeting was taken up with complaints about procedural quirks of the new committee. Several members expressed surprise upon learning that approval of motions required a two-thirds majority of all members present, as opposed to all members voting. Turner and Evans-Mongeon raised questions about whether votes at previous meetings had been recorded properly, as they had assumed that approval only required a simple majority.
Several members also said the procedure currently used for initiating debate on a proposal, which requires a motion and a second in favor of the proposal, is unnecessarily confusing as members may not be aware that the motion is opening debate rather than beginning a vote. Chair Greg Ford, of Georgia System Operations, promised that the committee would consider revising its procedures with an eye toward clarity.
An estimated 20,000 to 30,000 MW of offshore wind capacity representing a $28 billion to $57 billion investment in the U.S. economy will be operational by 2030, according to the U.S. Offshore Wind Power Economic Impact Assessment.
OSW project development, construction and operations could bring a projected 83,000 jobs in that time and deliver $12.5 billion to $25.4 billion per year in economic output. During a panel at the American Wind Energy Association’s Offshore Windpower Virtual Summit on Wednesday, state officials from Massachusetts, New Jersey, New York and Rhode Island discussed their role in training tens of thousands of people for those jobs as part of that hoped for economic boon.
Kirsten Holland | Massachusetts Clean Energy Center
Kirsten Holland, program manager for offshore wind for the Massachusetts Clean Energy Center (CEC), said a “well trained and highly skilled workforce” is needed for OSW jobs where educational requirements range from apprenticeships to advanced degrees. Holland’s agency released an assessment in 2018 examining the workforce needs and economic impact associated with 1,600 MW of OSW development.
“It really laid the groundwork for our workforce development initiatives by demonstrating that there are thousands of jobs and hundreds of millions to billions of dollars in economic impact associated with just 1,600 MW of offshore wind built out,” Holland said.
Building on that initial assessment, Holland said the CEC maintains a website dedicated to training and educational programs for clean energy jobs, including OSW, which lays out career pathways, educational offerings and training programs. Additionally, Holland said there is an active process to identify unemployed or underemployed people to set up those “who need the jobs most” with education and technical training programs.
According to Holland, another priority area was increasing access to OSW jobs, specifically those in the commercial fishing industry. She said $2 million in grant funding to 15 institutions, including a public university, community colleges and other organizations, have helped build a bridge to new employment opportunities and training over the last two years.
Laura Hastings, deputy director of the Rhode Island Department of Labor and Training’s Real Jobs program, said her state offers the Wind Win RI certification program for high school students looking to work in the OSW industry. The state also offers two free years of tuition at a community college for a renewable energy program, and there is a partnership with the Business Network for Offshore Wind to train companies that want to work in the industry. (See Tiny RI Seeks its Share of Offshore Wind Jobs.)
Earn and Learn
Matthew Vestal, senior adviser for large-scale renewables at the New York State Energy Research and Development Authority, noted his state’s legislative mandate to install 9 GW of offshore wind by 2035. By his “fairly conservative estimate,” that could mean 10,000 jobs and the capacity to provide enough renewable energy to power 6 million homes and produce 30% of the state’s electricity load.
Matthew Vestal | NYSERDA
“We recognize that offshore wind is a very unique economic opportunity,” Vestal said.
Vestal said New York is spending $20 million to create the Offshore Wind Training Institute at the Farmingdale State College and Stony Brook University campuses and additionally providing grant funds for the Center of Excellence for Offshore Energy at SUNY Maritime College. The developers of the Sunrise Wind project will spend $10 million on the Offshore Wind Training Center at Suffolk County Community College. (See related story, Preparing the Wind Energy Workforce.)
Brian Sabina | NJEDA
Brian Sabina, senior vice president of economic transformation at the New Jersey Economic Development Authority, said Gov. Phil Murphy wants to expand opportunities for good-paying OSW jobs through “on-ramps and off-ramps” so that people can “earn and learn at the same time,” especially people of color and women.
“We’ve more than doubled participation in apprenticeship programs by Black, Latinx and female apprentices,” Sabina said.
One area where apprenticeships are needed is welding, a skilled trade that Sabina said has leveled off in New Jersey. That is where increased regional cooperation comes into play, according to Hastings.
Laura Hastings | RI Department of Labor & Training
“Welding is robust in Rhode Island and Connecticut, as we can build nuclear submarines, largely with welders, so that’s one way we can use regionalization to play on each other’s strengths versus what we don’t have,” Hastings said.
“There’s definitely the opportunity for direct or indirect collaboration on workforce training,” Vestal added. “I think there’s the ability to send workers to different states to make this a regional workforce rather than a state-by-state workforce.”
For students in either high school or college considering the OSW industry, Hastings said that critical-thinking and problem-solving skills are in-demand attributes, aside from education and training initiatives.
“Being able to look at something critically and come up with a new solution that doesn’t exist yet, this industry is ripe for that, and if that’s the kind of person and kind of thought process that you go through, that would only help you,” Hastings said.
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.
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.”
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-2a, 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
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.
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.
“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.”
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).
| MISO
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.
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.
Adam Stern, Offshore Wind California | AWEA
“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.
Sarah Courbis, Advisian Worley Group | AWEA
“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.”
Brita Woeck, Deepwater Wind | AWEA
“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.
Mari Smultea, Smultea Sciences | AWEA
“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.”
Desray Reeb, BOEM | AWEA
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.”
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.”
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.
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.”
