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.”
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.
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.
Howard Gugel, NERC | Energy Bar Association
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
Patricia Hoffman, Department of Energy | Energy Bar Association
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.”
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.
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.’”
“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.”
Michael Hanson has been in the wind energy workforce for 14 years. He started onshore, managing the operation, maintenance and repair of turbines at a number of sites before moving to the first offshore wind farm in the Western Hemisphere, the 5-MW facility off Block Island, R.I.
It takes a diverse village to run a successful wind farm, according to Hanson.
“You can cast a wide net and get good people from a variety of backgrounds,” said Hanson, operations and maintenance manager for GE Renewable Energy.
Hanson was part of a panel at the American Wind Energy Association 2020 Offshore Windpower Virtual Summit Tuesday that discussed the education and training needed to prepare the American wind energy workforce of the present and future.
Marjaneh Issapour| Farmingdale State College
Marjaneh Issapour, an electrical engineering professor and director of the Renewable Energy and Sustainability Center at Farmingdale State College in New York, said there are many different areas of expertise and credentials needed to “fully deploy the wind energy workforce in the United States.”
Issapour said about 47% of jobs in the field are entry-level, open to high school graduates or those who have completed apprenticeships or associate degrees. Another 41% require a bachelor’s degree, with only 12% requiring a master’s or doctorate.
Among the two job titles in most demand are wind technicians, representing 9% of the total, and wind engineers, representing 12%. “Wind engineer is a multidisciplinary expertise that is a cross … of mechanical, electrical and possibly civil engineering,” she said.
Nuria Soto | Avangrid Renewables
Nuria Soto, senior director of offshore operations for Avangrid Renewables, said 20 years ago there were no offshore wind technicians, and “now it’s an established industry” that is also moving very fast and also needs workers for OSW development, construction and operations.
“One of the main challenges is to ensure that the workforce is ready, and the supply chain is ready,” Soto said. “All these jobs will support the different phases of each project.”
In another panel, Mark Mitchell, director of generation projects for Dominion Energy, said the industry is generating an increasing number of jobs today.
This summer, Mitchell said, Dominion had more than 25 vessels operating with more than 400 people working on the utility’s two-turbine pilot project, now in operation, and early work on its 2.6-GW commercial-scale project.
Workers needed for the U.S. wind energy workforce | National Renewable Energy Laboratory
“We’ve got several hundred [people] working today offshore. It’s not just something in the future. It’s kind of here and now, creating many, many jobs,” Mitchell said.
Bruce Gresham | International Marine Contractors Association
Bruce Gresham of the International Marine Contractors Association said there’s “a mix of different levels of experience” needed to work on OSW facilities. Gresham added that tens of thousands of workers in the offshore oil and gas industry laid off during the COVID-19 pandemic have that kind of baseline experience.
“The younger generation is much more interested in working for the wind industry than the dirty oil industry,” he said.
Soto said Avangrid’s internships are a good opportunity to see how a project is developed and understand different roles.
Hanson said the best training from his perspective is to come from an onshore facility. OSW turbines are “the biggest, most technologically advanced in the world, and having that experience on the smaller machines, I think is second to none.”
Michael Hanson | GE Renewable Energy
That does not diminish other experience, Hanson added.
“There [are] so many different jobs that are going on within a turbine — you can come from being an electrician or technician or a mechanic or someone from the oil and gas industry, or of course from another renewable energy field or utility,” said Hanson, who also mentioned technical college and military training.
“The maintenance and construction of generators at heights in a marine environment is a new industry,” said Andy Goldsmith, a technical adviser for IMCA. “But marine construction and going to sea … is not a new industry. Lighthouses and such … have been constructed for eons, let alone the oil and gas industry, which of course started back in the [19]60s.”
The U.S. energy industry is still wrestling with the economic and social impacts of the COVID-19 pandemic that gripped the world nearly nine months ago, experts said Tuesday.
Managing the magnitude of the pandemic was the first discussion at the Energy Bar Association’s 2020 Fall Conference, held virtually Tuesday because of the pandemic. The discussion covered load impacts and economic consequences for utilities, regulatory responses, consumer-side adjustments and fuel and supply chain price changes.
Panelists included John O’Brien, executive vice president for strategy and public affairs at Washington Gas, and David DesLauriers, vice president at Charles River Associates.
Frank Graves, a principal with The Brattle Group, said the COVID-19 burden has been “uneven” across the energy industry, with different utilities and sectors experiencing contrasting impacts.
Utility companies have weathered most of the economic impacts of COVID-19, Graves said, while some businesses in the energy sector, such as small oil and gas development companies, have experienced bankruptcy. He said utility stocks have trailed the S&P 500, remaining relatively sluggish throughout the summer versus the S&P 500’s overall growth of 10%.
“Even though we’ve improved a lot, we still aren’t very close to where we would like to be,” Graves said.
The U.S. Energy Information Administration forecasts that 2020 electricity consumption will drop by 2.2% relative to 2019 based on a 3.2% increase in residential sales, a 6.2% drop in commercial sales and a 5.6% drop in industrial sales.
Daily LMPs have been below past two-year averages by 10-70% in almost every month since February in every ISO/RTO, Graves said. The drop in LMPs is not solely due to COVID-19 consumption changes, he said, with lower natural gas costs — partially the result of the pandemic — likely playing a bigger role.
But the drop in LMPs will strain the viability for some coal and nuclear plants, Graves said. ERCOT prices were down 64% in September compared to the two-year historical average, while PJM and NYISO have seen declines of 33% and 32%, respectively, in the same period.
Graves highlighted the impact on regional electric loads, which declined by 7% in September compared with the previous four years, despite a return to relatively normal in mid-summer. The September decline was in line with the April (6.5%) and May (7.5%) declines at the height of the pandemic.
PJM and MISO accounted for most of the September decrease, with states in their footprints seeing among the largest surges in COVID-19 cases since mid-summer, Graves said. Warmer than normal temperatures in those regions also contributed to the decline, along with colleges and universities that have not reopened campuses.
“We haven’t been able to unpack this very much, but that’s a surprise that there’s a big drop in September when we’ve had some economic rebound over the last few months,” Graves said.
‘Devastating’
Sandra Mattavous-Frye of the D.C. Office of the People’s Counsel said the pandemic has been “the single most devastating event to impact our country” in more than a century and no sector, population or industry has gone unscathed, including the energy industry.
Mattavous-Frye said the unique nature of the pandemic provides challenges for the energy industry but affordable, safe and reliable utility service, along with strong consumer protections, remains her guiding principle as a consumer advocate.
She said three principles must be in place when dealing with the fallout from COVID-19.
First, there must be equitable cost sharing. While the financial stability of utilities must be ensured, it can’t be “business as usual” where ratepayers are expected to bear the entire cost — utilities must also carry a fair share, she said.
Second, public officials must implement enhanced and sustainable permanent consumer protections for underserved and low- to moderate-income households. Those protections must offer a comprehensive approach to service disconnections, including reasonable payment and billing plans.
Finally, industry participants should identify the short- and long-term negative impacts of the pandemic on all segments of the energy industry. She said forums like Tuesday’s event are a good start.
“I really believe it is an obligation to step outside of the box of our traditional regulatory roles with a shared commitment to overcome the challenges we are facing and explore viable options to address the problem head on,” Mattavous-Frye said.
Global Infrastructure Partners announced Tuesday it will sell generation developer and operator Competitive Power Ventures (CPV) to Tel Aviv-based OPC Energy and Israeli institutional investors. Terms were not announced.
Maryland-based CPV, which develops natural gas and renewable power generation, is one of about 40 portfolio companies owned by GIP, which invests in the energy, transport and water/waste sectors internationally.
The sale would include all of CPV’s 5.3 GW of generation in the U.S. as well as its development pipeline and asset management business, which operates more than 10.6 GW of fossil and renewable generation in nine states for 13 owner groups.
Incorporated in 2010 as the first private electricity company in Israel, OPC Energy generated about 5% of that nation’s electricity in 2018. It will own 70% of CPV and serve as general partner, with the remainder owned by three Israeli institutional investors: Clal Insurance Enterprise Holdings Ltd. Group (12.75% interest), Migdal Insurance and Financial Holdings Ltd. Group (12.75% interest) and Poalim Capital Markets (4.5% interest).
Pending regulatory approval, closing of the sale is expected in early 2021.
| Competitive Power Ventures
OPC said it plans to invest “significant capital” in CPV to fund future growth with a focus on renewable and combined-cycle gas generation. It said CPV’s leadership team will remain intact. “OPC has long recognized the potential in the U.S. electricity market,” OPC CEO Giora Almogi said in a statement.
Founded in 1990, CPV was acquired by GIP five years ago.
“We look forward to the opportunities created by our new partnership with OPC, which positions us well for our next phase of growth during a pivotal time as the U.S. transitions toward greener and lower emitting generating resources,” CPV CEO Gary Lambert said in a statement. ” … I am grateful to Global Infrastructure Partners for its confidence in CPV over the past five years, providing not only access to capital but credible execution and operations expertise that helped guide us through a significant growth period.”
Tom Rumsey, CPV’s senior vice president of external and regulatory affairs, told RTO Insider the company will continue to pursue natural gas generation investments as well as renewables.
CPV Three Rivers Energy Center near Chicago is expected to go into operation in 2023. | Competitive Power Ventures
“We are very focused on reducing carbon emissions from the power sector, but policy must align with technological capability,” he said. “As we’ve seen in California, without dispatchable power to augment and facilitate the growth of renewables, reliability is difficult if not impossible to maintain. Highly efficient and operationally flexible natural gas resources are exceptional partners to today’s renewable technologies, specifically wind and solar. We have very aggressive development programs for both.”
Portfolio
CPV’s portfolio includes an 805-MW combined cycle plant in Connecticut and three combined cycle plants totaling 2,500 MW in PJM, with a fourth, the CPV Three Rivers Energy Center, a 1,250-MW combined cycle plant in Grundy County, Illinois, southwest of Chicago, under development.
CPV, GE Energy Financial Services, Osaka Gas USA, Axium Infrastructure and Harrison Street announced the financial closing on Three Rivers in August. The $1.3 billion plant is expected to commence operations in 2023.
CPV is also developing a 100-MW solar project in Pennsylvania and a 50-MW solar farm in Massachusetts.
Most of CPV’s generating capacity is in PJM. | Competitive Power Ventures
CPV attracted some undesirable attention in 2016 over its development of the Valley Energy Center, a 680-MW combined cycle plant in Orange County, N.Y., when Peter Galbraith Kelly Jr., then the company’s head of external affairs and government relations, was indicted in a federal bribery case involving two former aides of Gov. Andrew Cuomo. (See Competitive Power Ventures Lobbyist, Former Cuomo Aides Named in Bribery Indictment.)
Kelly was sentenced in October 2018 to 14 months in federal prison after pleading guilty to creating a $90,000-a-year “low-show” job at CPV for the wife of Joseph Percoco, then Cuomo’s executive deputy secretary. Percoco received a six-year sentence.
Kelly pleaded guilty to defrauding CPV by falsely claiming that Percoco had obtained state ethics approval for his wife to work at CPV. She was paid $285,000 over the course of three years through a consultant in an effort to hide the payments, according to trial testimony. Kelly also made sure that Percoco’s wife’s photograph and full name were not included in promotional materials for CPV.
A 2019 outage event in the United Kingdom highlights the need for both comprehensive underfrequency load shedding (UFLS) protection and an understanding of the impact of a “rapidly changing portfolio” of generation resources on reliability of the electric grid, according to a “lessons learned” notice from NERC.
The incident began Aug. 9, 2019, with a lightning strike on a 400-kV transmission line north of London that caused a single-phase-to-ground fault. The fault was detected and isolated, and the line was reclosed within 20 seconds. During that time, a steam turbine at the combined cycle plant in nearby Little Barford tripped offline, removing 244 MW of generation from the grid. At the same time, the Hornsea offshore wind farm, operated by Danish energy company Ørsted A/S, unexpectedly reduced output from 799 MW to 62 MW.
Parameters measured at Hornsea Onshore Station — MW and MVAR | NERC
After grid control systems reduced generator output — including 150 MW of distributed energy resources (DER) as part of the rate of change of frequency (ROCOF) scheme, an additional 350 MW of DERs tripped offline, resulting in a cumulative loss of nearly 1,500 MW of generation within one second of the fault. Within 58 seconds, frequency had declined from the European standard of 50 Hz to 49.1 Hz.
After another 33 seconds, as frequency was recovering to 49.2 Hz, a combustion turbine at the Little Barford plant — generating 210 MW — tripped offline, causing another frequency decline. As grid frequency passed below 49 Hz, more DERs tripped, and then operators at Little Barford took a second 187-MW combustion turbine offline. By this point, the cumulative generation loss stood at 1,878 MW and frequency had declined to 48.8 Hz, triggering UFLS schemes that disconnected 931 MW of load. This allowed the frequency to stabilize and begin to recover.
Frequency throughout the event | NERC
Poor Understanding of Weak Conditions
Post-event analysis found a number of issues with the performance of both Ørsted and local grid operator RWE. One of the most important was “limitations in [RWE’s] knowledge” of the Hornsea plant’s control system and “the interaction between its onshore and offshore arrangements,” which caused the loss of 727 MW of generation.
Simplified transmission map for southeast England | NERC
At the time of the transmission line fault, the wind farm was operating in a “weak” system condition due to a number of transmission facility outages already in progress. In addition, one of the undersea cables between the wind farm and land was out of service. As a result, when the voltage control algorithm called for increased output due to the line fault, an oscillation began that led to the overcurrent protection system intervening to reduce output.
The second major contributor to the outage was the Little Barford combined cycle plant, which accounted for more than 640 MW of lost generation capacity. Three issues led to the plant’s shutdown. First, the steam turbine went offline during the initial fault due to a speed sensor input error. The combustion turbine subsequently tripped off after a problem with the steam bypass system led to a buildup of steam pressure, which led operators to take the second combustion turbine offline about 27 seconds later. The cause of the initial speed sensor input error has yet to be determined, but the steam bypass system has since been repaired.
The last significant loss of generation — about 500 MW — came from the shutdown of multiple DERs. Although the initial 150-MW loss was part of normal phase shift protection procedure, the additional 350 MW was unexpected. Investigators determined that some of these DERs tripped offline due to incorrect ROCOF settings, while others were found to have had their UFLS triggered at 48.9 Hz instead of the correct setting of 47 Hz.
Study Needed on Behavior of Renewables, DERs
Corrective actions recommended by RWE in the aftermath of the event included reviewing its operational criteria to “determine whether it would be appropriate to provide for higher levels of resilience in the electric system,” along with reviewing the time scale for anti-islanding protection to “reduce the risk of inadvertent tripping and disconnection of embedded generation.” The utility also recommended an industry-wide review, involving regulators, utilities and other stakeholders to establish communication protocols for future events.
NERC’s analysis focused on the implications of the widespread adoption of renewable energy and DERs on grid reliability, in particular their “increasingly complex controls” that make it difficult to “predict resource responses to network faults.” The organization noted several potential flaws in RWE and Ørsted’s procedures:
Overreliance on self-certification of the models for generating resources, including DERs;
Insufficient understanding and coordination of the interactions between onshore and offshore wind generation control systems, particularly the performance of wind farms in weak system conditions;
Inadequate coordination between transmission planners, generation and transmission owners, reliability coordinators and equipment manufacturers to accurately model their connected resources;
Outdated tools, techniques and simulation approaches to planning and operations, particularly related to weak grid conditions and inverter-based resources; and
Inadequate understanding of the impact of tripping multiple DERs on grid reliability.
To illustrate one approach to modeling DERs, NERC cited PJM’s use of publicly available data, from sources such as the Energy Information Agency and its own Generator Attribute Tracking System, combined with data requested from transmission owners. The RTO uses this information to generate behind-the-meter solar forecasts that are factored into its load forecast and to notify TOs of generation resources that may be available to help with a transmission emergency.
In addition, Thomas Bialek, the chief engineer for San Diego Gas & Electric, warned in January that the behavior of residential rooftop solar panel users is often very different than that expected by system planners. This creates “hidden loads” that can’t be accounted for in planning, he said. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)
