With less than two weeks until the Oct. 31 opening of the U.N. Climate Conference in Glasgow, a group of congressional Democrats rallied on Wednesday in front of the Capitol with the goal of cutting through the current political wrangling over the budget reconciliation bill and getting it to President Biden’s desk before the summit.
“This is not a time for politics,” said Rep. Andy Kim (D-N.J.), noting that he is one of seven Democrats in Congress whose districts voted for former President Donald Trump in 2020. “This is not a time for you, for me or others to be thinking about how is this going to affect my race in 2022.”
“History will not judge us by the [bill’s] price tag, however that’s debated,” said Rep. Kathy Castor (D-Fla.), who chairs the House Select Committee on the Climate Crisis. “History is going to judge us by our determination to do the right thing at the right time before it is too late.”
The bill, dubbed the Build Back Better Act, contains many provisions for mitigating climate change sought by the Biden administration and progressive Democrats. As a reconciliation bill, it would not be subject to the Senate filibuster, requiring unanimous Democratic support in the evenly split upper house. But it has encountered opposition from Democratic Sens. Joe Manchin (W.Va.) and Kyrsten Sinema (Ariz.).
Sponsored by the League of Conservation Voters, the press event provided the lawmakers an opportunity to preach about the increasing threats and impacts of climate change. They also underlined the high stakes for U.S. leadership on climate action before the U.N. conference.
Sen. Ed Markey (D-Mass.) said, “The Senate must put together a climate package [so that] Joe Biden can say to the rest of the world that we are the leaders and not the laggards, because you cannot preach temperance from a bar stool. You cannot tell the rest of the world what to do if you, as a country, are not doing it yourselves.”
“We must save this planet that we will pass on to future generations. It would be a dereliction of duty to build the infrastructure of America without doing so in a green way that protects the planet,” House Speaker Nancy Pelosi (D-Calif.) said, a seeming reference to the Senate-passed bipartisan infrastructure bill that Democrats have refused to pass without first passing the budget bill.
As originally introduced and passed in the House, the $3.5 trillion budget reconciliation package not only includes strong climate provisions, such as incentives for electric vehicles, but also a raft of social programs, including free pre-kindergarten and community college education and an expansion of Medicare and Medicaid.
But beyond the price tag, the bill’s Clean Electricity Performance Program (CEPP), which would pay utilities to accelerate their transition to clean energy, has become a central pain point. Manchin opposes the $150 billion program, arguing utilities should not be paid for something many are already doing. (See Reports: Clean Energy Performance Program Killed by Manchin.)
As Biden continues negotiations with House progressives and Manchin and Sinema, reports from media outlets including NPR and CNBC suggest that both sides are finding some common ground on key objectives. But it seems likely, reports say, that the final package will come in closer to $2 trillion and not include the CEPP.
Speaking at the rally Wednesday, Sen. Cory Booker (D-N.J.) called for holding the line on core climate funding in the bill.
“As we look at this bill in the final hours of negotiations, we can’t cut funding for natural climate solutions or protecting old growth forests, planting millions of trees in urban areas and restoring our coastal wetlands,” Booker said. “We can’t cut conservation funding that makes farmers part of the solution leading us out of this crisis. We can’t cut environmental justice provisions that are so critical.”
Sen. Ron Wyden (D-Ore.) also emphasized the central role that the taxes and tax credits could play if included in the bill, even without the CEPP. Wyden has long supported a carbon tax on polluters and tax credits for clean energy.
“The more you reduce carbon emissions, the greater your tax savings,” he said. “And that gets us to 73% of the target we want to get to” on emissions reductions.
Taxes may not be “the most glamorous topic in the world,” Wyden said, “But I’ll tell you, at the end of the day, the lobbyists are spending all their time on that, trying to pack every single favor they can possibly pack into this package.”
NextEra Energy (NYSE:NEE), apparently not content with being one of the biggest kids on the utility block, is now dipping its toe into regulated water utilities.
The company said Wednesday that its NextEra Energy Resources (NEER) subsidiary has entered into a $45 million agreement to acquire a portfolio of regulated water and wastewater assets in eight counties near Houston that furthers its strategy to build a “world-class” water utility. And that could just be the beginning.
NextEra CFO Rebecca Kujawa | NextEra Energy
“We’re really excited about building a significant presence in the water business,” CFO Rebecca Kujawa said during NextEra’s third-quarter earnings call with financial analysts. “It’s good to be us.”
Kujawa said that while the $45 million pales in comparison to NextEra’s annual $15 billion capital investment program, the company referenced it in its prepared remarks because of the potential opportunities.
“I think it’s a lot like transmission in the sense that it will be built slowly over time and create opportunities for us to continue to have that regulated and long-term contracted base of value creation,” she said.
Already generating more electricity from wind and solar resources than any other company in the world with a market capitalization of more than $100 billion, NextEra has added 5.7 GW to its renewables and storage backlog this year. NEER now has about 18.1 GW of signed contracts in the backlog and is looking to add more in California, where it has nearly 300 MW of projects and is developing nearly 2.4 GW of additional storage projects.
“We are proud to help the state lead the country to a carbon-free, sustainable future,” Kujawa said.
Ironically, Bloomberg reported Monday that NextEra was among three renewable technology heavyweights that have been removed from S&P Dow Jones Indices’ Global Clean Energy Index because of tightened membership requirements.
NextEra also told analysts that its Florida Power & Light subsidiary has filed a proposed rate-case settlement with regulators that will be heard on Wednesday. The settlement, which includes its recent acquisition of Gulf Power, would result in a $1.25 billion rate increase over the next two years.
The Juno Beach, Fla.-based company posted earnings of $447 million ($0.23/share), compared to $1.23 billion ($0.62/share) during the third quarter of 2020. The results included unrealized gains and losses on equity securities held in NEER’s nuclear decommissioning funds and other than temporary impairments.
NextEra’s shares opened at $82.03 on Wednesday and shot to $84.41 before closing at $83.92, a 2.3% increase.
The possibility of forming a Western RTO with or without California was a central topic at this week’s joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB).
Held in San Diego and virtually, the three-day summit brought together stakeholders and state regulators from across the West for panels on markets and transmission and to hear from three FERC commissioners.
FERC Chairman Richard Glick addressed the CREPC-WIRAB meeting by video. | CREPC-WIRAB
Utah Public Service Commission Chairman Thad LeVar asked Glick whether California could be part of an RTO given its size. States with loads that “significantly overshadow” neighboring states — California, Florida, New York and Texas — are not in RTOs, he pointed out.
“None of those areas have successfully created multistate RTOs with that kind of load difference,” LeVar said.
Glick acknowledged CAISO’s governance issues had “stunted” an RTO in the West, causing prior attempts to expand the ISO to fail. California’s governor appoints the members of CAISO’s Board of Governors, and state lawmakers have been unwilling to expand CAISO’s governance to include out-of-state representatives or to consider allowing California to join a multi-state organized market.
That might need to change for California to avoid resource adequacy problems like those it experienced during the past two summers, when heat waves and wildfires limited electricity imports from the Pacific Northwest and the Desert Southwest.
“California can’t do it alone,” Glick said in a virtual appearance. “It would be a mistake for people to say, ‘Well, I’m a lot bigger, and therefore we should set our own rules and ignore everyone else. It just doesn’t work that way, at least in the West. It hasn’t worked that way in the past.”
He said other RTOs have been able to cope with a mix of larger and smaller states.
“There are some relatively big states in PJM, for instance, that work with a lot smaller states, and I would argue they get significant benefit from doing that,” Glick said.
“It also won’t work for policymakers in California to continue saying, ‘We’re California. We’re going to appoint our board members and have our own governance,” the FERC chairman said. “I understand why that’s attractive if you’re in California, but I don’t think it is sustainable.”
In her in-person presentation, Commissioner Allison Clements said the fact that three of the four sitting FERC commissioners decided to speak at the CREPC-WIRAB meeting showed the importance of events taking place in the West, where multiple regionalization efforts are underway.
The Northwest Power Pool has launched its Western Resource Adequacy Program (WRAP), the topic of a presentation by NWPP and Pacific Northwest utilities at the meeting and a panel discussion of state regulators on its governance. SPP is administering the program. (See SPP to Operate NWPP’s Resource Adequacy Program.)
CAISO is seeking to expand its Western Energy Imbalance Market (WEIM) from a real-time to an extended day-ahead market (EDAM), which CAISO CEO Elliot Mainzer touted in San Diego and in an Oct. 13 stakeholder forum. (See CAISO Promotes EDAM Effort in Forum.)
In addition, SPP has been pitching its plan to include Western utilities in its RTO along with its Western Energy Imbalance Service (WEIS). SPP CEO Barbara Sugg promoted those efforts at CREPC-WIRAB and presented a new SPP proposal called “Markets+,” which the RTO says is “more than just a day-ahead market offering.”
“It’s a conceptual bundle of services proposed by SPP that would centralize day-ahead and real-time unit commitment and dispatch, provide hurdle-free transmission service across its footprint and pave the way for the reliable integration of a rapidly growing fleet of renewable generation,” SPP says on its website.
The service is intended to appeal to Western utilities that “aren’t ready to pursue full membership in a regional transmission organization at this time” but instead want “a voluntary, incremental opportunity to realize significant benefits,” more like the WEIM or WEIS.
Adding urgency to RTO talks, Colorado and Nevada passed bills in June requiring transmission-owning utilities to join an RTO by 2030. (See Talk of Western RTO Intensifies.)
Colorado state Sen. Chris Hansen, a main sponsor of the bill, said at the CREPC-WIRAB meeting that the measure was designed to give utilities a “nudge” toward greater regional collaboration as Colorado and other Western states pursue ambitious clean-energy goals.
And Oregon lawmakers last spring passed a bill requiring the state’s Department of Energy (ODOE) to complete a study by year’s end exploring the potential benefits and risks of joining an RTO, a potential prelude to a more serious push for membership. ODOE has this fall convened two meetings with an advisory committee on study design and hopes to have a draft report completed by late November. (See Oregon Group Contemplates RTO for a ‘Decarbonized World.’)
‘Neatly Into One Box’
The usual roles of an RTO — operating a wholesale energy market, overseeing transmission and ensuring resource adequacy and reliability — “don’t have to all get connected neatly into one box” in the West, Clements said. But the challenges of climate change and a shifting resource mix suggest that “broader integration [and] coordination will better meet the challenges the Western system is facing as well as make it more cost-effective,” she said.
The division that once existed between California and the rest of the West has dissipated as other states have adopted clean energy mandates like California’s and moved to adopt more wind and solar power.
Clements referenced a state-led study funded by the U.S. Department of Energy that showed the development of a single RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion a year in energy costs by 2030.
The study — presented in a separate session at the CREPC-WIRAB meeting — also found that a full Western RTO would be more effective at saving money, reducing renewable resource curtailments and cutting CO2 emissions than RTO configurations in which the region is broken up into separate markets, including one that divides CAISO from the rest of the West. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
Should Western states decide to form an organized market or markets, they can learn from the successes and avoid the mistakes of Eastern RTOs, she said.
“I have this desire for you all to take advantage of those lessons learned, which makes me a cheerleader for regional market integration,” Clements said.
‘Full Buy-in’
Commissioner James Danly, a vocal critic of CAISO’s market design and frequent dissenter at FERC, praised the success of the WEIM and said it had altered perceptions of CAISO in the West.
“The distrust that had developed at one point in this region for interactions with California has, to a very large extent, I think, been modified by the positive experiences people have had in the EIM,” Danly said. “The value that has been delivered to ratepayers is undeniable, and the scale is vast.”
(The latest tally showed the WEIM had saved its 15 participants more than $1.4 billion since its inception in 2014.)
“On top of everything else, I think there’s been a benefit to the EIM that it has allowed utilities that are not typically engaged in complex cooperative endeavors, like this market, to get better and better at it, which I think bodes well for the future for their cooperation, perhaps on a greater scale,” Danly said.
“I’ve been very deeply impressed by the thoughtful, incremental and deliberate development of the Northwest Power Pool and their desire to establish what appears to be an absolutely positive value proposition and to do so thoughtfully, with as much buy-in from as many people as possible, which I think is key to any type of market system like this,” Danly said. “Having people pushed into it kicking and screaming is the worst possible way of doing it.
“The collaboration that I saw was impressive,” he said. “There is a deep commitment from everybody involved to a cooperative endeavor there, and all I can say is … [that] I am cheering Northwest Power Pool on from the sidelines, and I really hope that that the fledgling effort succeeds as much as it appears that it will.”
Some supporters of a full RTO describe steps such as EDAM and WRAP as too incremental and piecemeal, but Danly said smaller steps that foster cooperation can be a model for the formation of a Western RTO.
“I am a true fan of markets,” Danly said. “I think they deliver immense benefit to ratepayers, and I want to see them executed but … properly executed. I do think that the march toward a full RTO, much like the way the Northwest Power Pool is doing things deliberately and gradually, is something also that should be done with full buy-in from everybody.”
“I’m a big fan of RTOs, but they’re not necessarily right for every region,” he added. “I would just suggest that everything be done as incrementally as possible, with as many people at the table to discuss it as we can get.”
FERC on Thursday authorized MISO’s settlement agreement with parties unhappy over their fees for using the regional transfer limit linking the RTO’s Midwest and South regions (ER21-530-001).
The RTO’s settlement with MidAmerican Energy, Alliant Energy and the Michigan Public Service Commission replaces the rate structure used to compensate SPP and six other parties for its members’ use of the sub-regional transfer limit beyond the 1,000-MW contract path linking MISO Midwest and MISO South. The new rate structure is effective February 2021.
MISO originally planned to extend the use of its current load ratio-based allocation among members until February 2022 while it developed a permanent rate structure. But Alliant Energy and MidAmerican Energy complained that market participants in an Iowa local resource zone bore a disproportionate one-third of rate schedule costs in 2020, leading FERC to order a hearing into the matter. (See FERC Orders Hearing on MISO Pact for Midwest-South Tx.)
MISO has proposed adopting a new, market-based allocation that assigns costs based on the congestion accrued when the transfer limit binds on its 2,500- or 3,000-MW limits, depending on flow direction. The RTO has said its current load-based method, which also employs a diminishing flow-based calculation, is too complex. (See MISO Proposes New Cost Allocation on Regional Tx Limit.)
While the load-based allocation will technically stay in place this year, MISO has pledged to retroactively use the new allocation to redistribute payments made between Feb. 1, 2021, and Jan. 31, 2022.
The commission said the settlement — which will likely involve MISO issuing refunds or supplemental bills with interest to members — is reasonable, fair and in the public interest.
After passing an extensive climate law earlier this year, the Massachusetts administration must look closely at the pathways for rapid decarbonization and if it is betting on the right solutions, according to energy consultant Dan Allegretti.
“I think it is important to keep checking in every so many years and ask the question: What do we need to change as we go forward,” the former vice president at Exelon said at the Northeast Energy and Commerce Association’s Legislative Update event on Wednesday.
Wind and solar power variability, as well as worsening storm events, “all need to be addressed” in the state’s next steps implementing the Next-Generation Roadmap law, Allegretti said.
Instead of racing to 100% renewable energy, state policymakers should “think about decarbonization more holistically across sectors,” he said, and “determine where it is best to deploy capital to reach incremental goals once we develop a predominantly renewable power sector.”
The state’s new climate law sets emission reduction sublimits for certain sectors every five years, including the natural gas and building sectors. Massachusetts is heavily reliant on neighboring states and Canada for its energy resources, which “makes transmission planning tricky,” he said. Gov. Charlie Baker’s administration will need to focus on building the in-state supply of solar and offshore wind.
Massachusetts is making a “big bet on offshore wind,” Allegretti said. “And I wouldn’t go much bigger.”
Advancements in green hydrogen, long-duration energy storage and solar technologies are in the pipeline.
“We don’t know what’s coming along 10 years from now,” he said.
However, a siloed approach could mean state agencies are moving too slowly in acting on their newly prescribed roles in the climate law, said Elizabeth Mahony, assistant attorney general and senior policy adviser for the Massachusetts attorney general’s office.
“Who brings [all these efforts] together?” Mahony asked.
The climate law incorporated equity and greenhouse gas emission reductions into the state’s Department of Public Utility’s (DPU) mission statement and codified that mission statement for the first time. But the DPU and the Executive Office of Energy and Environmental Affairs haven’t opened a docket to explore what that means, and Mahony hasn’t seen this question come up in a docket under the DPU yet, she said.
The agency could play a role in determining how electric utilities will be involved in covering the costs of the renewable energy transition, such as solar storage.
Utilities in the state need to file energy efficiency plans with the DPU by Nov. 1, which will put new provisions and cost efficiency standards to the test, Mahony said.
But the climate bill is meant to transition the state to renewable energy over 30 years, said state Rep. Joan Meschino (D), one of the main architects behind the legislation. “We are not turning off the switch to natural gas tomorrow.”
FERC Chairman Richard Glick had strong words at Thursday’s open meeting regarding the end of PJM’s expanded minimum offer price rule (MOPR), saying “good riddance” to the controversial rule that had been in effect since 2019 (ER21-2582).
PJM’s narrowed MOPR proposal, filed by the Board of Managers on July 30, took effect Sept. 29 by operation of law after FERC deadlocked 2-2. The new rule applies only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction. (See FERC Deadlock Allows Revised PJM MOPR.)
“The expanded PJM MOPR was an absolute disaster, creating enormous uncertainty, threatening to impose billions of dollars in additional costs onto consumers and imperiling the future of the PJM capacity market itself,” Glick said.
Glick said PJM’s original MOPR in 2006 was a “narrowly constructed instrument” that was designed to address concerns about the exercise of buyer-side market power in the RTO’s capacity market. As wind and solar generation became more competitive and energy prices decreased, Glick said “new rationales” were offered to expand the rule’s reach.
The expanded MOPR order was a “thinly veiled attempt to frustrate state efforts to promote cleaner energy,” he said. The narrowed rule “returns the focus of the MOPR to where it belongs.”
Glick said he may have written some of the proposal’s aspects “slightly differently,” but it “plainly meets [the] standard” of Federal Power Act Section 205.
The commissioners on Tuesday issued formal statements explaining their views on the change, with Glick and Commissioner Allison Clements filing a joint statement.
Commissioner Mark Christie said in his statement that he agreed that the expanded MOPR needed “to be replaced or significantly modified” because it was “simply unsustainable” because of the disparate energy policies among PJM’s 13 states and D.C. But he called the RTO’s proposal the “flawed and rushed result of an ‘expedited’ stakeholder process.”
“Finding a replacement MOPR that properly accommodates state policies while ensuring a credible capacity market to benefit consumers — one in which competition is real, not a sham — has always been the challenge,” Christie wrote. “PJM’s present proposal simply fails to meet the challenge and, as the pleadings filed by intervenors to this docket demonstrate, the proposal fails to meet the FPA Section 205 standard of being just and reasonable and not unduly discriminatory or preferential.”
Christie said PJM’s Independent Market Monitor was “explicit” in its concerns that the PJM proposal was going to “open the door wide open” to exercises of market power, providing a “devastating critique” that the RTO’s markets “would be better off, more competitive and more efficient with no MOPR than with PJM’s proposed approach.”
“We must do better, and we can,” Christie wrote. “We should not rush into place a grossly inadequate proposal just to meet the artificial deadline of the December Base Residual Auction — an auction PJM itself has already asked to postpone — and do so just because we do not like the current MOPR structure.”
Commissioner James Danly had yet to issue his own statement of the MOPR as of Thursday’s commission meeting, saying he couldn’t meet the “internally agreed upon deadline.” He said it would be published “in the next day or so.”
Developer BlueWave Solar has a vision for Maine’s solar market to support farmland preservation, economic opportunity, healthy communities and access to food, and Drew Pierson, the company’s head of sustainability, sees one strong approach for getting there.
Between dual-use solar incentives, regulatory mechanisms and voluntary approaches, Maine “has a golden opportunity to demonstrate how a voluntary dual-use market could function and what it could look like,” he said in a presentation to the Maine Agricultural Solar Stakeholder Group on Thursday.
The market could go beyond just pairing solar with a single agricultural use to combine a variety of land management philosophies and rooting them in conservation and agriculture to create a multifunctional system, he said. Realizing that vision, he added, requires building “well crafted partnerships that involve a variety of people from different disciplines and sectors.”
The Maine Department of Agriculture, Conservation and Forestry and the Governor’s Energy Office convened the stakeholder group this year to look at solar energy development on agricultural lands and develop policy recommendations for the sector. A report is due from the group in January.
Demonstrations
BlueWave developed its first agrivoltaic project in Maine on a voluntary basis through a partnership with a farmer in Rockport, according to Pierson.
“There’s no [per-kilowatt-hour financial] incentive, but we felt strongly that this was the right tone to set in entering this market,” he said.
A five-year study on 5 acres of the 4.2-MW project will enable the University of Maine to understand the effects of installing and maintaining a solar array in an existing blueberry crop.
“Recognizing that construction comes with costs, we want to get a sense of [how long it takes] a blueberry bush … to recover from the variety of different construction practices,” Pierson said.
The research team also will measure the environmental conditions on the site and look at the physiological responses of blueberries to the presence of the solar array.
In addition, the blueberry grower adjusted his cultivation practices so he could more easily navigate the array, he said.
The company is developing a solar project in Benton that Pierson says would repeat the Rockport model. Of the 32-acre solar field, 5 acres would be for a crop trial and 27 would be for sheep grazing.
“We’re hopeful that we can create an on-ramp for a farmer who is willing to test and demonstrate what a profitable and scalable farm plan could look like,” Pierson said.
BlueWave has another project that demonstrates the agrivoltaic development approach through an incentive structure in Massachusetts. The company developed a 3.1-MW solar array on a family farm in Grafton to qualify for the Solar Massachusetts Renewable Target program, which offers a 6-cent/kWh adder for solar projects on land designated for agricultural purposes.
“The project is going to be hosting research ground crops and rotational grazing of cows for beef,” he said. “We’re building on-site infrastructure, including water, an irrigation system, an animal shelter and fencing to facilitate the operation.”
Welcome Mat
If Maine sets standards for solar and agricultural practices, the standards could support the growth of a volunteer market approach in the state.
The Maine Department of Environmental Protection could establish a solar grazing standard, for example, and it could “influence how solar grazing happens across the industry,” Pierson said.
And a standard for solar project design, he added, could ensure that farmers are allowed on the site property under certain conditions.
“Maybe they just need a welcome mat,” he said. Strategic farm plans that are “locally relevant, profitable and scalable” would encourage farmers to take on a certain amount of risk.
If farmers understand the economic model of agrivoltaics and they see it working in existing projects, Pierson said his hope is that they wouldn’t need a subsidy to convince them to enter a solar partnership.
The Agricultural Solar Stakeholder Group will meet again on Nov. 18 and Dec. 16 before delivering its final report to the Maine Legislature.
The electric grid faces a “range of evolving and complex threats,” from climate change to cybersecurity, Energy Secretary Jennifer Granholm warned Wednesday during the second day of NERC’s GridSecCon 2021 conference.
But those dangers should also be seen as opportunities to build a more robust bulk power system for the future, she said.
“This image is so burned in our minds, this image of a transmission tower knocked over after Hurricane Ida across the Mississippi River,” Granholm said. “It sends this really clear message that our power infrastructure has to be hardened for the future of these worsening climate impacts that we have ahead.”
Granholm added that along with the frequency of severe weather events, “the costs of these disasters are escalating.” She noted that over the past three years, the U.S. has spent around $120 billion per year cleaning up from natural disasters, compared to “about $18 billion a year” in the 1980s.
Robb said that in addition to the rising impacts of climate change, the past year has seen an apparent explosion in cyberattacks originating from foreign nations, perpetrated by groups affiliated with nation-states along with more traditional criminal gangs. He mentioned the hack of the SolarWinds Orion platform and Microsoft Exchange, along with the ransomware attack this summer on the Colonial Pipeline that caused the company to shut down its entire network that carries almost half the supply of gasoline, diesel and other fuel products to the U.S. East Coast. (See Experts Call for Cyber Shift in Response to Colonial Hack.)
“We’ve seen a number of risks that we knew were out there come to life, and unfortunately, we got to see them with a front row seat and in Technicolor,” Robb said. “The supply chain attacks — SolarWinds, Microsoft Exchange, [etc.] — really demonstrate the sophistication of our adversaries, and they [show] the bad guys are bad, not dumb.”
New Generation, Transmission Investments Needed
Rather than dwelling on the risks to the grid, Robb and Granholm focused on what NERC and the Department of Energy can do to help strengthen it.
Granholm said preparing for climate change requires the U.S. to “deploy, deploy, deploy clean power sources, so that we don’t continue to aid and abet” the buildup of atmospheric carbon. Along with this, the U.S. must expand and reinforce transmission lines so that electricity can get from these new generating units to where it is needed, while upgrading control systems to allow greater resilience in emergencies.
“That kind of integrated resource planning — not just on a one utility scale or one state scale, but really on a countrywide scale — is absolutely necessary, which is another reason why I’m so happy to be head of a department that has 17 national laboratories … [that] are eager to help out,” Granholm said, noting that the infrastructure bill still winding its way through Congress includes billions for grid improvements and electric vehicle charging. (See Bipartisan Infrastructure Bill Offers Funding for Grid, EVs.)
Robb agreed with Granholm’s support for new transmission, a stance he has repeatedly championed. (See Glick, Robb Call for Tx Build in West.) He also cited NERC’s work with its counterparts in other countries on strategies to common problems: for instance, the organization has studied the response of authorities in Australia and South Africa to wildfires.
Praise for Information Sharing
NERC CEO Jim Robb | NERC
Turning to cybersecurity, both Granholm and Robb praised utilities for their willingness to share information about cyber incidents through initiatives like the Cybersecurity Risk Information Sharing Program, operated by NERC’s Electricity Information Sharing and Analysis Center. Granholm acknowledged that publicizing a successful attack might “look like a bad reflection” on a utility, but reminded the industry that “if we don’t know what’s going on, we can’t talk to one another and prevent the next one.”
The secretary also highlighted DOE’s “100-day sprint” to improve cybersecurity at critical electric infrastructure, which the Biden administration announced in April. (See Biden Reinstates Trump Supply Chain Order.) Granholm said the program had gained commitments from 150 utilities, covering almost 90 million customers, to install monitoring sensors and technologies to “enhance visibility into the networks that operate the system.”
Robb reminded viewers that the problems facing the grid require “21st century solutions” and challenged utilities to rethink old assumptions.
“There are no shortage of challenges facing the electric grid as we go forward. I like to think of it as, we’re leaving behind our grandfather’s electric grid, and we’re building our grandchildren’s electric grid. And it’s going to be very different than what we’ve had in the past,” Robb said.
Texas regulators are expected to release a draft blueprint for a redesigned ERCOT market Thursday in response to February’s winter storm that will likely focus on increasing the amount of dispatchable generation.
The American Council for an Energy-Efficient Economy (ACEEE) has countered by saying rather than build new power plants or taking other measures, Texas could avert future blackouts at a lower price by instead improving the energy efficiency of its homes and using technologies to shift electricity usage away from peak demand periods.
In a new report, the council said the state could deploy seven residential energy efficiency and demand response retrofit measures over five years that could serve about 9 million households and offset about 7.7 GW of summer peak load and 11.4 GW winter peak load at a cost of $4.9 billion. That is below separate proposals by Berkshire Hathaway Energy and Starwood Energy Group Global to build 10 to 11 GW in gas plants for $8 billion.
“That should be one of the first things the commission does,” said Stoic Energy consultant Doug Lewin, who moderated an ACEEE panel discussion Tuesday previewing the Public Utility Commission’s open meeting Thursday.
Lewin said Texas was the first state to adopt an energy efficiency resource standard in 1999. Nearly 30 states have now instituted similar standards, he said, but Texas now stands dead last.
“We have not increased energy efficiency programs even a smidge since 2011,” Lewin said, adding that demand continues to grow in the state.
“Does [ACEEE’s proposal] solve everything?” he asked rhetorically. “One of the biggest criticisms of energy efficiency is that it doesn’t solve the whole problem. Nothing solves the whole problem. We aren’t looking at silver bullets here. There’s a lot of silver buckshot.”
Alison Silverstein | ACEEE
Alison Silverstein, an independent consultant with a career that includes stints with the PUC, FERC and the U.S. Department of Energy, agreed with Lewin. She said she expects more discussion among the four commissioners, who have been in a “learning mode” since their appointments during the last eight months.
“There’s so much ground to cover and a lot of space between the commissioners to explore,” Silverstein said. “There’s no single solution here. What the commission needs to adopt is many measures for a layered approach. … How do we put all these pieces together rather than think one specific recommendation is going to solve all the problems?”
Noting the commission’s goals include improving resource adequacy, Silverstein said the market’s new design elements should focus on operational reliability and market considerations.
“Let’s make sure we have long-term and short-term solutions … to keep the lights on day-to-day,” she said. “The commission is under a lot of pressure. The legislature has already reminded them very explicitly that winter is coming. Don’t spare the horses. Let’s keep the pedal to the metal.”
The PUC has conducted four market redesign workshops since the summer to gather ideas and input from market participants on how to prevent a reoccurrence of the days-long blackouts that followed February’s winter storm. During last Thursday’s workshop, the commission heard from The Brattle Group, which called for fixes through the market, and Potomac Economics’ David Patton, who said increasing ERCOT’s capacity margin would not have effectively addressed last winter’s outages.
Suzanne Bertin, Texas Advanced Energy Business Alliance | ACEEE
Suzanne Bertin, managing director for the Texas Advanced Energy Business Alliance (TAEBA), pointed out that most of the proposals brought forth have come from the market’s largest players who have proposed increasing dispatchable generation “by raising revenues to fossil fuel generators in particular.”
She divided the proposals into three major categories: paying certain plants to stay online instead of retiring because of market economics (Vistra); providing backup service by paying specific generators to run 24 hours straight (Lower Colorado River Authority); and mandatory forward procurements or load obligations of three years (NRG Energy). (See Study Suggests Texas LSEs Can Provide Reliability.)
“We’re interested in focusing on those types of solutions that would directly address the problems we faced in February,” Bertin said, using rooftop solar, home batteries and electric vehicles as examples. “The cost of electricity grid failure is so high that we need to be thinking about building a whole suite of resources and rules that provide layers of protection for Texans going forward. We also need to be thinking about how we make sure the costs borne by customers in Texas — because they ultimately pay for whatever policy decisions are made … are bearable.”
Bertin compared the result to an orchestra, with all the instruments playing their parts “to draw out the characteristics that make a symphony work.”
“Any market design changes made over the next couple of months need to incorporate the best available technologies … necessary for Texas to retain its energy leadership role and maintain confidence in the electric system,” she said.
PUC Chair Peter Lake said during the last workshop that any design decisions will be made quickly and without giving thought to protecting business models.
That is small comfort to Silverstein, who said she is hoping the commission will look at “performance-based, technology-neutral solutions” rather than favoring fossil-fired plants.
“I’m hoping they’ll layer multiple options. … I think they’ll pick a few favorites, and I think they’ll pick a bunch of them,” she said. “I agree [ERCOT] needs a lot of fossil plants in the short-term, but that doesn’t mean fossil plants can deliver every solution that we need. They cannot deliver, in fact, many of the solutions we need for operating responsiveness and capacity, as they painfully showed us last February.”
A coalition of 24 ERCOT stakeholder groups, including Silverstein, ACEEE and TAEBA, filed a document with the PUC Tuesday offering their “broadly applicable foundational principles” to guide the commission’s redesign efforts and their recommendations for prioritizing reforms most likely to prevent sustained load-shed events (52373).
The coalition’s principles include protecting customers, fostering competition, and promoting high-quality infrastructure. Its members recommend a phased-in approach by taking “low-hanging fruit” measures to improve operational responsiveness first before expanding low-cost energy efficiency and demand response to buffer bills against unknown future costs for the supply-side proposals.
As Lake promised, the PUC will move quickly after Thursday’s meeting. It will hold a fifth workshop on Nov. 4, with stakeholder comments on the draft plan due Nov. 12. A final work session will be held Dec. 9 before the commissioners’ target completion date of Dec. 19.
It was a dull Tuesday for FERC watchers, as President Biden’s first nominee to the commission, Willie Phillips, faced few questions from members of the Senate Energy and Natural Resources Committee at his confirmation hearing.
Those he did receive were mostly vague, nonspecific queries about ensuring reliability and affordability. Though asked several times about transmission planning and operations, Phillips cited FERC’s ongoing Advance Notice of Proposed Rulemaking on those topics, a broad inquiry that required him not to prejudge or take any specific positions, he said.
When asked by Sen. John Hickenlooper (D-Colo.) what he could do to improve transmission planning and alleviate transmission congestion, Phillips responded, “You’re asking the right questions, senator.” He noted that the commission had posed more than 200 questions about its transmission planning process rules and other related topics. “And I do share your concerns. … If we are going to meet our [climate] goals, I believe that electric transmission will play an important part in doing that.”
In response to Sen. Maria Cantwell’s (D-Wash.) question about whether “we need to do more” to encourage interregional transmission projects, including DC interties, Phillips simply answered, “Yes, absolutely.”
And though ranking member John Barrasso (R-Wyo.) used his opening comments on Phillips’ nomination to lambast Democrats’ proposed provisions in the House of Representatives’ pending budget reconciliation bill, he never asked Phillips anything about those provisions. In a previous hearing that featured all four current commissioners, Republicans took it as an opportunity to criticize the Biden administration’s energy policies. (See Senate Hearing on FERC Jurisdiction Focuses on Everything Else.)
Instead, Barrasso “commended” Phillips, chair of the D.C. Public Service Commission, for “putting reliability first” in his job and opening remarks, and emphasizing a balance among reliability, affordability and sustainability.
Biden announced his choice of Phillips last month. (See Biden to Nominate Phillips to FERC.) In Phillips’ opening statement, he highlighted his experience not just at the D.C. PSC, but also as assistant general counsel at NERC.
“I worked with some of the sharpest legal minds in the industry to draft reliability standards for the bulk power system, including Critical Infrastructure Protection standards,” he said. “I have a keen awareness of the cybersecurity and physical security threats that we face as a nation. And, as the effects of climate change and extreme weather increasingly challenge the reliability of our grid, it is imperative that we work to ensure that our nation’s energy infrastructure is resilient. Reliability depends on our vigilance against these threats.”
If confirmed, Phillips would break the 2-2 partisan makeup at the commission that has led to several tie votes and high-profile proposals that have become effective by operation of law, including a new minimum offer price rule for PJM and the creation of the Southeast Energy Exchange Market.
Historic NPS Director Pick
It was not just the nature of the questions that kept Phillips brief: The committee was simultaneously considering two other nominees, including Charles Sams, who if confirmed would not only be the first official director of the National Park Service since January 2017, when Barack Obama was still president. He would also be the first person of Native American descent to ever serve in that position.
Former President Donald Trump nominated David Vela to the post in 2018, and the committee soon after advanced him to the Senate floor, but he was never confirmed. Then-Interior Secretary David Bernhardt appointed Vela as director on an acting basis; he served until late 2020.
The unique nature of his nomination led senators to focus on Sams for most of the two-hour hearing, with many seeking commitments about national parks in their home states. The service is understaffed, and parks have been inundated with visitors after COVID-19 restrictions were lifted and more people got vaccinated.
The committee also considered Brad Crabtree, vice president of carbon capture for the Great Plains Institute and director of the Carbon Capture Coalition, to be assistant secretary of energy for fossil energy and carbon management. Though he received more attention than Phillips, he was likewise overshadowed by Sams.
