MISO is evaluating nine projects to supplement or substitute for the contract path on SPP transmission linking its Midwest and South regions.
The RTO last week said it is still analyzing project ideas submitted by stakeholders, with nine projects passing the initial screening phase and multiple HVDC options undergoing further analysis, before completing the first round of screening.
It received 35 project ideas to reduce dependence on the North-South transmission constraint after it opened the floor to ideas in April, Economic Studies Engineer David Severson said during a conference call with stakeholders Thursday. (See MISO Seeking Proposals to Relieve North-South Constraint.)
The RTO now says its analysis will continue beyond the 2019 Transmission Expansion Plan (MTEP 19) deadline in December. In spring, staff said they weren’t bound to a deadline to submit any project recommendations and could take more time to conduct thorough testing of candidates.
“Given the uniqueness of some of the solutions we received … we fully expect the study to continue into 2020,” Severson said.
He added that MISO might try out new “exploratory” benefit metrics on the project candidates, although those metrics would not yet be applied to official benefit-cost ratio figures. The RTO has so far suggested it might incorporate the benefits of increased capacity flowing between regions as a new metric.
MISO currently relies on three metrics in its ratios, including adjusted production costs, the value of deferred or avoided reliability transmission projects, and the value of reducing power flows on the North-South constraint.
It will provide more updates on ideas later this year. Multiple stakeholders asked RTO staff to return with maps of potential transmission routes, a suggestion Severson said he would take under advisement.
8-Project Draft from Congestion Study
MISO will work through fall on its 2019 Market Congestion Planning Study, which now contains a shortlist of eight projects.
The RTO last month reported it was analyzing seven projects that passed the first round of screening. Those projects focused on just three congested areas, leaving MISO to compare multiple alternatives for just two congested areas. (See “Shortlist from MCPS,” MTEP 19 Revealing High Price Tag.) Additional projects are now in the running to solve interregional congestion.
MISO MCPS preliminary projects | MISO
The project shortlist has grown to eight after initial testing, with only one regional project focusing on a 345-kV flowgate in southern Minnesota, the $32 million Helena-Scott County 345-kV line, which stands to deliver a 4.76:1 benefit-cost ratio, MISO said. The project is now the best option out of three originally proposed to solve the Minnesota congestion.
While MISO has whittled down options on the lone regional project, the number of possible interregional solutions has grown.
The remaining projects address interregional flowgates, with three intended to ease two MISO-SPP flowgates in southwest Arkansas and on the Iowa-Nebraska border, and four addressing two MISO-PJM flowgates in northwest Indiana and western Illinois.
Possible MISO-PJM projects range in cost from $23.3 million to $34.6 million, while costs for the potential MISO-SPP solutions range from $35 million to $58 million.
All of the projects still must undergo further testing before they are deemed viable. Economic Studies Engineer Karthik Munukutla also said MISO is coordinating with SPP and PJM to figure out if they foresee benefits from the potential interregional projects.
“We want to make sure the projects we are testing stand the test of time,” Munukutla said.
He said staff will wrap up studies in August and reveal final recommendations at the Planning Advisory Committee meeting Sept. 25. “We will have all the recommendations there, both from an interregional and regional standpoint.”
BOSTON — More than 200 people — nearly all women — gathered on the sparkling new Campus Center at the University of Massachusetts Boston on Wednesday for the annual summer meeting of New England Women in Energy and the Environment (NEWIEE).
“There’s just so much going on here that is relevant to the work that you do in the energy and environment field,” UMass Boston Chancellor Katherine Newman said as she welcomed the group’s members and state officials invited from around the region.
Newman pointed to a program the university inaugurated this year to establish 20 industry clusters on the campus, companies linked together by “common labor markets” and looking for people with the “same kinds of skills.”
“One of them will definitely be in energy and environment,” she said.
Massachusetts Attorney General Maura Healey quoted the former president of Ireland, Mary Robinson, who recently said that “climate change is a manmade problem with a feminist solution.”
“The crisis we face is, of course, existential,” Healey said. “No other country is going to solve this problem for us, and even while our federal government hands control over to coal lobbyists and climate change deniers, the world does continue to look to us for global leadership. And we need to demonstrate the path that transitions our economy away from fossil fuels by transforming the way we power our communities.”
Healey will host the annual meeting of the National Association of Attorneys General’s Eastern Region in Boston this September and is making energy the focus of that meeting. “That’s how important I view this topic,” she said.
She recommended applying the clean energy revolution to buildings and transportation as well as to the power sector, possibly mandating efficiency retrofits on old buildings, and incentivizing the adoption of electric vehicles.
Regional Collaboration
“On behalf of a very small state with a strong governor [Gina Raimondo], we can collaborate to help make this region be more than the sum of its parts,” said Carol Grant, commissioner of the Rhode Island Office of Energy Resources. “At the end of the day, that is the goal. Each state is going to do what each state is charged with, but how can we collaborate?”
Raimondo set a goal of developing 1,000 MW of renewable energy in the state by 2020, Grant said. “The good news is, as of the second-quarter report — not out officially — we will be over 750 MW, so we are going to make that goal.”
Grant also said her office works to ensure the state’s clean energy moves help those who need it most, such as by introducing electric buses into poor communities identified as most subject to public health disparities.
“Our renewable portfolio standard is set at 38.5%,” Grant said. “When we set it, we were first in New England; now we’re fourth. That’s amazing and a compliment to Maine and to other states that have been pushing their RPSes. So everybody keep going.”
Energy and climate are a focus of Maine Gov. Janet Mills, said Hannah Pingree, director of the governor’s Office of Policy Innovation and the Future (OIF).
A former state legislator, Pingree recommended NEWIEE members “run for public office, in your spare time if you have to, because that’s where policy gets made.”
Maine is about two years behind Rhode Island in the push for clean energy, but it is now first in the country on RPS targets with a goal of 80% renewables by 2030, she said.
The state led the country in offshore wind in 2008 and 2009 until Mills’ predecessor, Gov. Paul LePage, “shut that down in a big way,” Pingree said. (In 2008, former Gov. John Baldacci established the Maine Ocean Energy Task Force, which in 2009 published a report recommending the development of 5 GW of offshore wind energy by 2030.)
LePage served two four-year terms until Mills was inaugurated in January.
“My kids are into ‘Harry Potter’ now, and I’m sure you’re all familiar with the phenomenon of ‘He Who Must Not Be Named,’” Pingree said of LePage.
The University of Maine has received a $40 million grant from the U.S. Department of Energy to build Maine Aqua Ventus, which they hope will be the country’s first floating offshore wind platform. In addition, she said her state is working with New Hampshire and Massachusetts on a Bureau of Ocean Energy Management task force to develop offshore wind regionally. (See New England Officials Speak on Grid Transformation.)
New Hampshire Public Utilities Commissioner Kathryn Bailey recommended that project developers “work with local people way before they put any plan forward. They need to get buy-in from local people.”
Bailey served on the state’s Site Evaluation Committee that rejected Eversource Energy’s proposed 1,090-MW Northern Pass transmission project to carry Hydro-Québec hydropower to Massachusetts. The New Hampshire Supreme Court the previous week upheld the rejection, and on Thursday, Eversource filed with the Securities and Exchange Commission its intent to drop the project.
“Not every local person has to buy in, but without it, you’re going to get a lot of animosity and opposition, and it’s really hard to overcome that,” Bailey said. “It may cost you more, but in order to get these things sited — and cost is my main issue — you’re going to have to pay a little bit more for it than people thought because you can’t do it without some local support.”
‘Women Know What to Do’
When Healey first became attorney general in 2014 — she was re-elected last year — she brought together what had previously been separated: the office’s Environmental Protection and Energy divisions.
“It was my view that unless we thought about synergies between these spaces, we weren’t going to get to where we needed to be. So that’s why we created, for the first time, an Energy and Environment Bureau, housed everybody together, and I think it’s made us smarter, more strategic and hopefully … more of a leader in this space,” Healey said.
Study after study has shown that women are more likely to understand the impact that climate change will have on their lives, she said, and they’re more likely to worry about what that’s going to mean for future generations.
“And even more importantly, women know what to do. We know the game plan; we know the blueprint. Every day, we see cities across this country adopting their own Green New Deals. Every week we see hundreds of municipalities and businesses signing new clean power purchase agreements. Our clean tech community continues to roll out new programs and policies that are making real differences.”
Ultimately, running the economy on clean energy is a win for everyone — for consumers, the climate, public health and the economy, she said.
“I explain to people that I am forced to sue Donald Trump and his administration time and time again because the actions they are taking undermine the interests of Massachusetts residents and our businesses,” Healey said. “I explain that Massachusetts has over 100,000 clean energy jobs and growing right now, twice the number of coal jobs in the entire country and representing an $11 billion dollar industry.”
The solar and wind industries are creating jobs 12 times faster than the rest of the economy, she said, with more Americans working in solar energy than in oil and natural gas extraction. “Think about that.”
INDIANAPOLIS — Commissioners were pitted against industry stakeholders in an energy-themed “Family Feud” event that lightheartedly capped off the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week.
The game show Wednesday delivered a win for the “Legends” stakeholder group, who prevailed 541-483 against the “All-Stars” commissioner team.
The commissioner team consisted of Sarah Hoffman of Vermont, Judith Jagdmann of Virginia, Paul Kjellander of Idaho, Kim O’Guinn of Arkansas and Brandon Presley of Mississippi. The stakeholder team — itself heavy with ex-regulators — included Paladin Energy Strategies’ Kevin Gunn, PJM’s Asim Haque, Edison Electric Institute’s Philip Moeller and the National Association of Water Companies’ Robert Powelson.
NARUC staff polled roughly 100 NARUC attendees for answers.
“This is not the [Richard] Dawson era; I will not be kissing anyone,” joked game show host Nick Wagner, NARUC president and Iowa Utilities Board member.
Questions ranged from “Name a reason a commissioner would wake up at 2 a.m.” to “What are the common causes of power outages” to “What item in the house uses the most energy.”
“What kind of coffeemaker do you have?” Wagner joked after Haque’s answer to the last question.
“Are these planned or unplanned outages?” O’Guinn laughed as she asked for clarification.
The All-Stars team took one round of the close game when Moeller took too long to answer.
“The Sopranos!” Kjellander shouted to a buzzer sound when asked what TV show mostly resembles his office. Other answers thrown out were “Game of Thrones,” “The Office” and “The Bachelorette.” Both teams failed to guess the remaining answer: “The Walking Dead.”
CAISO says it will seek to protect neighboring balancing authority areas if its investor-owned utility members de-energize transmission lines because of wildfire threats — even at the expense of the ISO’s own load.
But the policy of ensuring energy flows to adjoining BAAs during public safety power shutoffs (PSPS) didn’t exactly earn plaudits from the ISO’s own Board of Governors when it was revealed to them Wednesday.
“Not to sound un-neighborly, but why do we feel so strongly that there should not be [PSPS] impact to other IOUs or balancing areas?” Governor Ashutosh Bhagwat asked ISO officials during the board’s monthly meeting.
Bhagwat’s question came after CAISO CEO Steve Berberich and Director of Real Time Operations John Phipps laid out the measures the ISO would take to respond to an “extreme” PSPS event involving high-voltage transmission.
A CAISO slide illustrates the potential impact of an “extreme” public safety power shutoff taking out multiple high-voltage lines in PG&E’s territory. | CAISO
Berberich pointed out that California — which is only now heading into its peak wildfire season — has already experienced three PSPS events this year, compared with seven for all of 2018. (See Fire Season Starts in Calif. with Power Shutoffs.)
“At least some of the utilities have indicated that they very well could de-energize high-voltage [lines] through public safety power shutoff areas. We need to anticipate that this could happen, and we want to make sure everyone knows how we’re going to handle” shutoffs, Berberich told the board. “This is a very important matter. It could significantly impact people across the state.”
It fell to Phipps to describe how significantly. He presented the board with two possible scenarios related to emergency shutoffs in Northern California, clarifying that CAISO’s transmission-owning utilities — and not the ISO — decide when and where to initiate PSPS events.
Under a first, relatively benign, scenario, a wildfire danger limited to the remote northwestern part of the state would prompt Pacific Gas and Electric to de-energize one 60-kV line and a small portion of its distribution system, curtailing 200 MW of customer demand, but having no impact on CAISO’s larger grid and requiring little response from system operators.
But under a second, “extreme” scenario, Phipps said, PG&E would inform CAISO a day in advance that it would de-energize 230-kV and 500-kV circuits vital to the operation of the bulk electric system.
In that situation, PG&E would curtail high-voltage lines serving the Diablo Canyon nuclear plant on the Central Coast, taking more than 2,000 MW of generation offline. The utility would also be shutting off the portion of the California-Oregon Intertie (COI) running through the fire-prone area near Paradise, curtailing 4,000 MW of import capacity. The Sacramento Municipal Utility District (SMUD), a member of the Balancing Authority of Northern California (BANC), owns part of the COI along with PG&E and other entities.
“So, between the loss of transmission and energy capacity, we can now no longer meet the forecasted demand and reserve obligations for the next day,” Phipps said. “Due to that, the ISO would need to direct approximately 2,500 MW of load reduction to be able to meet our load and reserve obligations meeting N-1 criteria.”
In that scenario, BANC could expect to lose about 900 MW of imports from the Pacific Northwest, forcing it to shed about 400 MW of load, CAISO estimates.
“In order to help BANC avoid doing that, the ISO would make decisions to shed an additional 400 MW of ISO balancing authority load and provide emergency assistance to BANC during the hours that they would be short,” Phipps said.
The rationale for CAISO’s sacrifice is rooted in a set of operating principles the ISO has established to guide its response to wildfire shutoffs.
First among them is to protect the integrity of the BES, “so we will analyze the impact to determine what mitigation measures would need to be taken, including possible additional load shedding to manage N-1 loading issues.”
The second principle is to attempt to limit the impact of a PSPS to the territory of the utility initiating the action.
“So if one of the PTOs [participating transmission owners] is activating a PSPS and it does require the ISO to take actions to mitigate that leading up to the load shedding, we would try to confine that load shedding to that IOU and not let it propagate onto additional, adjoining IOUs,” Phipps said.
The third — and most controversial — principle: to prevent allowing the impact of an “extreme” PSPS to spill over into neighboring BAAs.
“So, in a sense, we would shed additional load so we could provide that energy to the adjacent BA so they could avoid the load shed,” Phipps said.
Doing the Right Thing?
The board bristled at the last principle, questioning the reasoning behind it.
Severin Borenstein, CAISO | University of California Berkeley
“Is there a sort of joint efficiency argument that it’s just going to be harder to recover, or is this good neighborliness, and how does that interact with the fact that these IOU lines are carrying power to these other balancing authorities?” Governor Severin Borenstein asked.
“The best I could give you is that it’s a good-neighbor policy,” Berberich responded. “I’ve consulted with the CEOs of the IOUs about this [and] they think the best public perception outcome would be to contain [PSPS impacts] to their own PTOs.”
“Even if that means shutting off power to the much larger number of people in the ISO balancing authority?” board Chair David Olsen asked.
“I don’t think that’s what we’re talking about,” Berberich replied, pointing out that CAISO would be only shedding an additional 400 MW of load in the scenario outlined by Phipps.
“I guess it’s not obvious to me what’s the right choice. I understand the politics, but I guess it’s not clear to me the efficiency of shedding that load in the same balancing authority,” Borenstein said, adding that one could make the case that the other BAs that benefit from the transmission lines every day should also bear part of the costs of de-energizing them.
“But you also have to keep in mind that they have no role in deciding to de-energize the lines either,” Berberich said.
“Yeah, that may be, but somebody’s got to make those hard decisions, and I’m sure the utilities are not going to decide to do it because they don’t have to bear 100% of the costs. I guess this is something that is a policy choice that has to be made,” Borenstein said.
Attempting to further illuminate the ISO’s position, Berberich offered another scenario in which PG&E takes out a line that doesn’t affect its own load, while requiring SMUD to shed 200 MW. “That doesn’t sound to me like a very good outcome,” he said.
“If PG&E has to shed a much larger amount of load in order to avoid that, it sounds like neither choice is good, but at some point, having an absolute rule that the PTO’s control area bears unlimited costs before any cost is borne by neighboring BAs seems not the right answer either,” Borenstein contended.
Berberich clarified that there would be no “hard and fast rule” for dealing with PSPS events — that each event would be addressed individually.
“There well could be cases where load has to be shed in adjacent balancing areas,” he said. “Our intentionality is to try to protect them, and our intentionality is to try to keep it perched within the PTO and then within our BA. And if we can’t do that, then it goes to another BA.”
Phipps piped in with a ground-level perspective, speaking from the point of view of a system operator answering an alert that a transmission line is being taken down, not because of a threat to the grid, but because of a “corporate decision to manage the risk of starting a fire.”
“And now I’m going to have to make a call to San Diego [to another IOU] and tell them I need you to shed 200 MW of load. I know you just spent a billion dollars upgrading your system so you wouldn’t have to do this, but I need you to shed load. And now SMUD, by the way, I need you to shed some load also.”
Borenstein, a University of California Berkeley energy economist, pondered whether the complications around wildfire shutoffs were rooted in the broader history of the utility system.
“Because in most other situations, if that other entity had some benefit and ownership of the line [such as the COI], they would also have some co-liability in the line,” Borenstein said.
Instead, PG&E is “solely liable” for any wildfires sparked by the line within its service territory, leaving it as the sole decision-maker regarding operation of the line, despite having a contract with the joint owner that should — but apparently doesn’t — include a right not to deliver energy in order to avoid the costs for wildfire liability, he said.
Borenstein speculated that CAISO’s need for such an “extreme” response to a potential high-voltage shutoff — curtailing ISO load — is an “idiosyncratic outcome” of how the region’s grid has been formed and “the casual relationship that has grown up among adjoining utilities” in the region with respect to risk-sharing for joint projects.
Berberich emphasized the scenario laid out in Phipps’ presentation was an “extreme version” of how the ISO plans to approach wildfire shutoffs, pointing out that utilities have yet to shut down any high-voltage lines running through areas already subject to PSPS.
“Let’s hope we never have to cross this bridge, but in the event we do, we wanted to make sure everybody understood how we’re going to handle it.”
ERCOT on Wednesday asked Texas regulators to dismiss a complaint by energy broker Aspire Commodities seeking to make generators repay the market an estimated $18 million as a result of a May pricing error.
The grid operator said the state’s Public Utility Commission should dismiss Aspire’s complaint because the broker failed to complete its alternative dispute resolution (ADR) procedure and also suffered no direct injury from the error.
ERCOT also asked the commission to deny Aspire’s request for a price correction for the May 30 event because its protocols don’t allow for price corrections “when a market solution is attributable to an external data error caused by an ERCOT market participant.”
“Requiring ERCOT to conduct price corrections in cases of external data errors would be imprudent, as this practice would lead to frequent price corrections and result in increased price uncertainty and market instability,” the grid operator said.
ERCOT noted that state agency rules require that a complaint made against it include a statement as to whether “the complainant has used the applicable ERCOT procedures for challenging or modifying the … conduct or decision.”
“Aspire fails to identify any provision … to excuse its failure to use the ADR process,” the grid operator said.
During a June meeting of the ERCOT Board of Directors, Vice President of Commercial Operations Kenan Ögelman said the event briefly resulted in $9,000/MWh prices when the security-constrained economic dispatch system received bad telemetry data. (See “Telemetry Data Blamed for Market Event,” ERCOT Board of Directors Briefs: June 11, 2019.)
He said the data indicated about 5,000 MW of resources wanted to move down during an interval. When the market didn’t respond quickly enough, the SCED engine used regulation-up to get the ramp it thought it needed. When energy prices hit their $9,000/MWh maximum, ERCOT operators reran SCED and corrected the data, but not before settlement prices reached as high as $1,500/MWh in some load zones for one 15-minute interval.
Ögelman said during the board meeting that staff would look into strengthening telemetry data and work with stakeholders to evaluate alternatives.
ERCOT declined to comment on staff’s work, saying it would not comment beyond its filing.
Adam Sinn, Aspire Commodities | Mays Business School/Texas A&M
In its complaint to the PUC, Aspire said it estimates ERCOT’s “fictitious price spike” cost the market almost $18.4 million. Aspire said it wasn’t a direct counterparty to the market, but it had exposure through its forward positions in the Intercontinental Exchange (49673).
“We simply cannot understand how anybody associated with the market cannot argue that repricing is absolutely required for this interval,” Aspire President Adam Sinn said.
“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman told the board in June.
Calpine admitted last week one of its IT employees had caused the error, and the company said it has asked ERCOT to reprice the 15-minute interval.
Avangrid reported second-quarter earnings of $110 million ($0.36/share), up slightly from $107 million ($0.35/share) in the same period in 2018, though first half net income was down about 7% from the first six months of last year.
A subsidiary of Spain-based Iberdrola, Avangrid owns United Illuminating, Connecticut Natural Gas, Central Maine Power, New York State Electric and Gas, and Rochester Gas & Electric.
In an analyst call on Wednesday, CEO James P. Torgerson said the company was “disappointed with the continued lack of wind resource that impacted most of our fleet.” (See Avangrid Earnings Drop on Weak Wind.)
The firm’s New England Clean Energy Connect transmission project is “on track,” he said, adding that the Massachusetts Department of Public Utilities recently approved 20-year contracts between Hydro-Québec and utilities Eversource Energy, National Grid and Unitil.
| Avangrid
In New York, NYSEG and RG&E filed their electric and gas rate cases in May for new rates effective in the second quarter of 2020, which includes requests for recovery of resilience investments and deferral of staging costs for storms. NYSEG was among utilities penalized last month by the New York Public Service Commission for safety and reliability issues. (See NYPSC Dings Utilities for 2018 Reliability, Safety.)
Central Maine Power is currently subject to hearings by the Maine Public Utilities Commission regarding the mismanaged introduction of a new billing system last year that saw some customers’ bills double or triple.
Torgerson said that the commission outsourced a forensic audit of the billing system and “concluded that it was billing things correctly.” He said the high bills were in part a reflection of a very cold winter. But for some customers, the company also failed to issue bills for a couple of months. In other cases, unpaid bills from one month got added to a second month.
“The issue really is … the fact that we didn’t provide the customer service that our customers expect,” he said. “Every individual has different circumstances, and we need to go through every one of those and work with the customer to make sure they understand what occurred … so that they can have confidence that actually their bill was correct.”
Commission staff are recommending a 75- to 100-basis-point reduction in CMP’s return on equity for one year until the company demonstrates that it has improved customer service “and gotten things back on track,” Torgerson said.
A Second Wind
Vineyard Wind, the company’s joint venture with Copenhagen Infrastructure Partners, had a rough start to the summer when the U.S. Bureau of Ocean Energy Management in June declined to issue its final environmental impact statement (EIS) on the 1,200-MW offshore wind project. This month, the Massachusetts town of Edgartown’s Conservation Commission denied a permit for the project’s transmission cables to come ashore on Martha’s Vineyard. (See “Land Ho is Wind Woe,” New England Officials Speak on Grid Transformation.)
On Tuesday, however, the Massachusetts legislature authorized the Barnstable Town Council to grant an easement at Covell’s Beach for Vineyard Wind to land its cables and build an interconnection to the New England grid.
The Massachusetts legislature on July 23 authorized the Barnstable Town Council to grant an easement at Covell’s Beach for Vineyard Wind to land offshore wind transmission cables and build an interconnection to the New England grid. | Vinyard Wind
On BOEM’s delay, Torgerson said, “We are confident that the pending reviews can be concluded shortly, and the final EIS released soon after. … We’re still working with them and pretty confident that we can get something done by the end of August, and that will keep us on track with our time frame.
“It would be challenging to move forward if we don’t get the final EIS in the next four to six weeks,” he said. “That having been said, it doesn’t mean the project is dead by any stretch. It just means we’re going to have to reconfigure things or do something differently.”
Laura Beane, head of Avangrid Renewables, said, “Right now, we are absolutely focused on getting to resolution under the current configuration and maintaining the current schedule. If we’re required to, I think we’ll look at other alternatives, but really our focus remains on maintaining our current schedule and working through these issues.”
In addition, the company said it had purchased the 226-MW Patriot Wind project in Texas upon commercial operation in June and that it has 763 MW of renewables assets under construction and on track to come online by the end of this year. Avangrid also secured a power purchase agreement on its 140-MW La Joya ll wind farm in California.
INDIANAPOLIS — Most state regulators think it is time to begin preparing for a 100% clean energy future, based on discussions at the National Association of Regulatory Utility Commissioners’ 2019 Summer Policy Summit.
In real-time voting during a panel Monday, 75% of regulators and industry staffers in the audience said it was time to begin prepping for a 100% clean energy future, with 4% saying the question could wait two to five years, 10% saying not for a while and 11% deeming the preparations not a priority.
Energy consultant Debbie Lew said 100% clean energy is within reach now.
“You can do 100% clean energy today; it just depends on how expensive it will be,” said Lew, who said the expense of synchronous condensers, grid-forming inverters and other power electronics quickly adds up. The effectiveness of a proliferation of four-hour batteries on resource adequacy also has a saturation point, she said.
The question remains, she continued, as to how smart and cost-conscious regulators and utilities are going to be during the transition. More accurate forecasting, price sensitive-demand response and effective curtailments can smooth the changeover, Lew said.
A 100% renewable future can be facilitated by larger regions with faster trading, a varied storage portfolio, demand-side flexibility, better forecasting and intermittent resources sometimes used for ancillary service dispatch, she said. “We tend to think of curtailment of wind or solar PV as a bad or ugly thing, but if we use that in combination with forecasting, we can use that as a reserve product. … It’s a technology that’s available right now.”
Lew said she can’t yet tell if there will be a need for regional energy markets after such a transition, but capacity markets could become more vital as seasonal, on-demand capacity becomes more necessary to cover intermittent resources.
“We’re really good at running energy markets, but is there much of a place for markets with zero-marginal-cost energy?” Lew asked.
Hawaii Public Utilities Commission Chair James Griffin said regulatory changes are a vital component to reaching 100% clean energy goals.
But Xcel Energy Director of Energy and Environmental Policy Jeff Lyng said a regulatory overhaul isn’t necessary to make the transition.
“Utilities have demonstrated that they can innovate and deploy [renewables] at scale,” Lyng said. He added, however, that small rule changes could be appropriate, in addition to the timely approval of pilots and generation projects and a continued focus on emissions control.
Lyng said Xcel worked with climate scientists to develop its 2050 zero-carbon goals, which line up with the target to keep global surface temperatures from rising beyond 2 degrees Celsius.
Griffin said the Hawaiian islands, which are especially susceptible to the risks of climate change, can’t afford to wait on high-tech solutions that will facilitate 100% renewable energy.
“Every time I’m told to slow down, I remind others that the status quo is the problem,” Griffin said.
Clean Air Task Force Executive Director Armond Cohen pushed back on the oft repeated conclusion that an 80% renewable mix is doable now, but a 100% renewable takeover remains out of reach. He said 100% clean energy is not an impossibility — it will just be expensive. Cohen also said he supports bills for 100% clean energy over bills that call for 100% renewable energy.
“I think that if we keep out options open, it’s totally doable,” Cohen said. “It’s going to be a lot of capex run very seldomly. … It gets very expensive very fast.” Cohen said an ideal, albeit wholly unrealistic solution, would be to cover the remaining 20% with zero-marginal-cost storage devices.
Multiple panelists repeated the call for federal-level carbon pricing to prompt more technology investment to facilitate renewable integration.
“Politics is going to be a big part of getting from here to there,” Sustainable FERC Project Director John Moore said.
He also said if he could have his way, the entire Eastern Interconnection would be consolidated into a single RTO to pave the way for renewables; however, he admitted such a scenario is unlikely.
FERC halted PJM’s plan to run its capacity auction next month in a surprise order issued Thursday, just hours after the Markets and Reliability Committee reaffirmed the RTO’s decision to move forward as planned.
The commission refused to “rule prematurely” on PJM’s request for clarification that if it ran the 2022/23 Base Residual Auction using the existing minimum offer price rule (MOPR) — while the revised version awaits approval — that FERC would enforce any new rates prospectively, saving the August auction from being rerun (EL16-49).
PJM argued that if the commission granted its request, filed in April, the “critical” confidence in auction results necessary for market participants would be preserved. (See PJM to Hold Capacity Auction in August.) The RTO’s Board of Managers also maintained that the rejected MOPR only impacts a small number of resources, meaning an updated commission ruling on the matter wouldn’t change prices too much within the current environment.
“PJM asserts that, here, refunds would not be warranted because the basis of the underlying complaint is that the relevant rates are too low, not too high, which is a required finding for refunds under Section 206 of the Federal Power Act,” FERC summarized in its ruling.
FERC advised PJM to cancel its August capacity auction. | PJM
PJM delayed the BRA once already after FERC ruled in June 2018 that the RTO’s MOPR was unjust and unreasonable because it didn’t address price suppression arising from state subsidies for renewable and nuclear power. The RTO proposed a new rate in October and had hoped for a ruling from the commission by March 15 to no avail.
PJM entities including American Municipal Power, Dominion Energy, Exelon, EDP Renewables, FirstEnergy and its subsidiaries, Talen Energy and its subsidiaries, the Electric Power Supply Association, Direct Energy, the American Wind Energy Association, the Solar Council and the Illinois attorney general’s office all filed in support of the RTO’s decision to run the auction in August, agreeing that further delays have proved detrimental to the market and interfered with the necessary forward pricing signals that sellers need.
The entities also agreed that should FERC reject the clarification, PJM should delay the auction because running it without the guarantee from the commission would “undermine the very certainty the BRAs are designed to provide.”
The Illinois AG’s office further argued that if FERC granted the request, it should also “address flaws in the existing capacity market rules that facilitate market power abuse by requiring PJM to release generator bidding data and to replace the algorithm that PJM uses to increase clearing prices above the highest bid.”
In the end, FERC advised PJM to cancel the auction until it provides a suitable replacement rate, though it’s unclear when that decision may come. ClearView Energy Partners speculates that if the commission doesn’t provide a ruling on the MOPR before November, PJM won’t have enough time to implement Tariff changes in time to hold the 2022/23 auction in April.
“We recognize the importance of sending price signals sufficiently in advance of delivery to allow for resource investment decisions,” FERC said. “However, we believe that in the circumstances presented here, on balance, delaying the auction until the commission establishes a replacement rate will provide greater certainty to the market than conducting the auction under the existing rules.”
PJM spokesperson Jeff Shields said on Thursday that the RTO will follow the commission’s guidance.
“In its ruling today directing PJM Interconnection to postpone its capacity auction, the Federal Energy Regulatory Commission recognized that confidence in the auction and its results is vitally important to all of our stakeholders and the integrity of the market,” Shields said in an emailed statement. “We look forward to additional guidance from FERC on the design of PJM’s capacity market.”
Commissioners Debate
While concurring with the order, Commissioner Richard Glick issued a scathing indictment of FERC’s inaction on PJM’s proposed changes, saying the RTO and its 65 million customers deserve better.
“One year later, Commissioner [Cheryl] LaFleur’s description of the June 2018 order as ‘regulatory hubris’ seems more apt than ever after the commission has shown an absence of leadership that has caused us to drift rudderless into the position in which we find ourselves today,” he said.
As the lone dissenter on the June 2018 order, Glick said he agrees with his colleagues that running the auction next month provides only a “short-term palliative effect … that would be outweighed by the long-term uncertainty” of allowing capacity commitments under Tariff previsions found unjust and unreasonable, leaving PJM vulnerable to years of litigation.
But he blamed FERC for putting PJM in the situation in the first place.
“If ever the Pottery Barn Rule applied to a regulatory proceeding, it is this one,” he said, referencing what Secretary of State Colin Powell told President George W. Bush in the lead-up to the War in Iraq: “You break it, you own it.”
LaFleur took her previous criticisms a step further in her own statement.
“Given the passage of time, the uncertainty created by the commission might better be labeled an act of regulatory malpractice,” she said. “The commission, whatever concerns it has with the PJM capacity market, should not have put PJM, the states and customers served by its markets, and its stakeholders in this position.”
Commissioner Bernard McNamee — who joined FERC after the June 2018 order — called Glick’s usage of the Pottery Barn Rule “misleading.”
“To suggest the commission is the source of the problems presently facing PJM is to ignore nearly a decade of proceedings attempting to address the interaction between competitive markets and out-of-market subsidies,” he said. “More importantly, such a statement only makes sense if one ignores the impetus behind PJM’s original filing in Docket No. ER18-1314, which was PJM’s desire to address issues arising from state out-of-market support for generation resources in its footprint.”
Glick argued that McNamee “misses the point.”
“It was the commission — not PJM — that made the finding that has prevented PJM from running its capacity auction,” he said. “And it has been the commission — not any party to this proceeding — that has failed to act, even though we are now more than six months past the date promised in the June 2018 order. Meanwhile, neither the facts nor the law have changed, and the time for deliberation has long passed. The commission is now fully responsible for the damage done to date and whatever comes next.”
Chairman Neil Chatterjee did not weigh in on the controversy.
The federal judge overseeing PG&E Corp.’s Chapter 11 bankruptcy granted a motion by the California Public Utilities Commission on Wednesday to hold off on deciding whether to terminate the utility’s exclusivity period while it attempts to create a process for choosing among the several competing plans.
A group of unsecured bondholders on Tuesday had requested that Judge Dennis Montali, of the U.S. Bankruptcy Court for the Northern District of California, terminate PG&E’s exclusivity — the time it has to offer a reorganization plan without the judge having to weigh competing proposals — in light of the enactment of Assembly Bill 1054 earlier this month.
“The debtors’ legislative requirement was addressed on July 12,” the ad hoc committee of senior unsecured noteholders told Montali in court papers. PG&E would have to emerge from bankruptcy by June 30, 2020, to take advantage of the measure’s provisions. The unsecured bondholders — a group of 25 banks, mutual funds and others — say that makes getting PG&E out of bankruptcy more urgent. They encouraged the judge to accept their proposal, which would pay off or refinance their notes.
“With the recent inception of the 2019 wildfire season and the impending June 30, 2020, deadline, it is now time to move these cases as quickly as possible towards emergence,” the bondholders’ lawyers wrote. “Unfortunately, to date the debtors have almost entirely failed to do so” and instead have sought legislative help to securitize equity in the company to protect shareholders and raise capital.
But on Wednesday, Alan Kornberg, an attorney representing the California PUC, told Montali that the commission is “keenly interested” in the bondholders’ plan, as well as a competing plan by insurers with more than $20 billion in unsecured claims against PG&E for payments made to wildfire victims.
Any exit plan would need to be approved by the commission, and it is “vital” that be done by the June 2020 deadline, Kornberg said. Both the commission and Newsom want a competitive process, and he acknowledged the request was an unusual one, “but we cannot permit competition to turn into chaos.” He asked Montali to give the commission and PG&E two weeks to work out a process and timeline for evaluating the different plans.
The bondholders’ lawyer, Michael Stamer, objected to the proposed delay, calling it “an unprecedented, undocumented road to nowhere.”
“Everyone is in violent agreement that every day counts, and two weeks is a long time,” Stamer said.
This did not persuade Montali, however. He noted that he had only received the bondholders’ 33-page plan Tuesday morning and finished going through it at midnight, indicating he was not prepared to rule on the exclusivity motion that day anyway.
Montali also noted that the bondholders were not the only ones seeking to terminate exclusivity. “The one thing we don’t need, more than anything, is a lot of lawyers writing a lot of briefings that don’t need to be written, and one judge reading all the briefs that don’t need to be read,” he said.
He set Aug. 9 to hear the results of the PUC and PG&E’s discussions, and Aug. 13 to rehear the bondholders’ exclusivity motion. A hearing to consider the insurers’ exclusivity motion was already set for that day.
Montali has wide latitude to consider the competing plans. He ended exclusivity early during PG&E’s prior bankruptcy case in the early 2000s, allowing the PUC to offer its own reorganization plan.
The judge warned PG&E’s lawyers in May he could revoke exclusivity if he saw fit. “This judge has never been a fan of exclusivity but is a fan of practical consequences,” Montali said. He explained at the time he did not want to deal with competing reorganization plans that might be unworkable.
“The proposal would hold PG&E accountable for wildfire liability, maintain price stability for PG&E’s ratepayers [and] contribute billions of dollars to California’s wildfire recovery fund,” the insurers said in a news release.
Their plan provides for payment of victims’ wildfire claims through a settlement trust, with a $5 billion contribution to the state’s recovery fund for future wildfire claims that was part of AB 1054.
Subrogation claimants would be paid 90% of their claims with shares in the company, “thereby reducing the amount of new money necessary for PG&E to exit Chapter 11,” they said.
Like the unsecured bondholders, the unsecured insurers stand to lose in the PG&E bankruptcy because they would have to get in line behind secured creditors whose claims will be paid first.
PG&E cited billions of dollars in wildfire liability when it filed for bankruptcy in January. The company has been blamed for starting major fires in 2015, 2017 and 2018, including last November’s Camp Fire, the deadliest in state history.
INDIANAPOLIS — Regulators should preserve the multiple incentives currently offered to transmission developers — and possibly consider creating new ones, two former FERC commissioners said Monday.
Speaking on a panel at the National Association of Regulatory Utility Commissioners’ 2019 Summer Policy Summit, former Commissioners Suedeen Kelly and Philip Moeller expressed support for incentives granted on a case-by-case basis, but they said the time may be ripe to create new categories of adders to encourage development.
Entitled “(Trans)Mission Critical? Reconsidering FERC’s Electric Transmission Incentives,” the panel focused on the commission’s recent Notice of Inquiry into transmission rate incentives and the ensuing comments from transmission owners, load, utilities, regulators and trade groups. (See Tx Incentives NOI Brings Calls for Broader Reforms.)
Virginia State Corporation Commissioner Judith Jagdmann, the panel moderator, asked if regulators view the incentives as a “fist on the scale or a thumb on the scale.”
Kelly, now a partner with the law firm Jenner & Block, said the incentives were designed to be a thumb. “It was clear from the beginning that you couldn’t incent something where rates were no longer just and reasonable,” she said of FERC’s philosophy behind creating incentives.
She said there wasn’t much common ground on specific, standardized incentives as she and her fellow commissioners were developing Order 697, issued in 2006.
“We agreed that incentives were necessary. We didn’t agree on what certain projects should be incented and not others. We couldn’t agree on the particulars. If you look at the rule, it reflects that. … We put the burden on the developer when they came to us” with an application, Kelly said.
Moeller, now executive vice president at Edison Electric Institute, said the incentive applications that started to come in after the 2006 rulemaking were generally on par with the commission’s expectations.
“I actually dissented from many incentive requests, and through my dissent, I was trying to create my own incentive policy, Kelly recounted. “Some of my dissents were an inchoate wanting to know more about the challenges and the benefits.”
Save the RTO Adder
RTO adders are still an important piece of encouraging transmission investment, Kelly said, especially in the West and Southeast, where participation in organized markets is less common.
“RTO membership was clearly something that the commission was trying to encourage. I think it’s taken for granted now, but 15, 20 years ago, it was really something different,” Moeller said.
However, the lone panelist without a regulator background argued for eventual phaseout of the RTO adder.
“We were concerned that the RTO incentive packages were too easily granted. It was becoming routine,” American Public Power Association General Counsel Delia Patterson said.
She said FERC has struck more of a balance between consumers and investors since its 2012 policy statement on transmission incentives, which was crafted to create a more rigorous standard for requesting incentives. Still, she said RTO membership is too commonplace to warrant the incentive.
But Moeller said it remains fair, also adding that between 2006 and 2012, transmission buildout was appropriately robust.
“I thought we went too far in terms of cutting things back in 2012. But I agree that transmission investment is necessary. … It’s so doggone hard to build for the most part,” Moeller said.
Risky Business
Kelly agreed that transmission construction is a risky venture: “It’s a very difficult decision in a public company to put up capital and make a transmission investment.”
During her time on the New Mexico Public Regulation Commission, Kelly said, she agonized the most over transmission siting decisions. “Nobody wants to put a transmission line in their neighbor’s farm or yard or along the edge of a national forest. It’s not a pleasant job.”
Asked whether they would prefer a case-by-case review or standardized incentive approval, the former commissioners still prefer the former — although Kelly thinks “slam dunk” incentives should be made into a standard.
Patterson concurred on the need for case-by-case review. “I trust my daughter, Emily, to make sure to pack a balanced lunch, but it’s up to me to verify that,” she said to audience laughter.
Moeller said FERC might consider additional incentives for transmission systems that are reinforced against intensifying climate change.
“What’s the value of electricity when you don’t have it? Many, many, many times more.”
