FERC on Wednesday allowed MISO to edit its tariff to clear up performance rules for load-modifying resources (LMRs).
MISO’s ruleset now more clearly states that LMR performance is evaluated on an individual basis, not on the aggregate performance of a market participant’s entire portfolio (ER21-693). Market participants can operate several LMRs across multiple local balancing authorities.
The tariff revisions, which the commission approved without comment, don’t change existing MISO policy. The new language is considered effective July 1.
The RTO said it discovered a need for the clarification following a maximum generation emergency in early 2019, when an extreme cold snap forced MISO’s first LMR use in its North and Central regions. (See Cold Snap Halts DER Talk as MISO Calls Max Gen Event.)
MISO control room | MISO
MISO said while market participants were able to supply 93% of the megawatts it requested to manage the emergency, only 21% of the deployed LMRs met the grid operator’s performance measurement and verification throughout the emergency. MISO penalized and even disqualified some LMRs after the event, leading their owners to seek alternative dispute resolution with staff.
“Ultimately, the information gathered through these disputes highlighted the need for the clarifications to the tariff,” MISO said.
Market participants were confused by the process, the grid operator said, and some were unaware that they needed to update their LMRs’ individual availability in the RTO’s communication system from default summer values to a daily offering.
The revised tariff language states that market participants are responsible for communicating to MISO “when the status or availability of an LMR changes.” When MISO calls up LMRs, scheduling instructions are sent to the owning market participants, not to individual resources.
The RTO also wrote that LMRs that “fail to perform in accordance with its market participant’s response to MISO’s scheduling instructions will be subject to a penalty and will not receive credit for its deployment.”
MISO said Wednesday it is close to completing a proposal to create a four-season capacity market after floating a rudimentary plan with stakeholders, who remain skeptical over stricter accreditations.
While the RTO expects to file the plan with FERC by the end of the second quarter, seasonal auctions won’t become a reality until the 2023/24 planning year at the earliest. MISO is currently leaning toward the idea of simultaneously conducting four seasonal auctions with separate zonal clearing requirements.
“MISO’s inclination is to go forward with one auction but monitor it closely and have further discussion about modifying that,” Director of Research and Development Jessica Harrison said during a Resource Adequacy Subcommittee teleconference.
Independent Market Monitor Michael Chiasson said monitoring staff continues to feel “quite strongly” that the design should include a spot auction prior to each season to complement the annual auction.
The RTO said it is “monitoring the pace of changes and evaluating needs for additional spot or true-up auctions.”
As part of the seasonal approach, the grid operator will likely require resources to demonstrate their minimum capacity capabilities. MISO will also likely use a three-year average of historical data to define “resource adequacy hours,” or the system’s tightest hours of the year for reserve margins when resources should make sure to be available. (See MISO Intends to Add Seasonal Capacity Auction.)
“If we’re going to have reduced capacity credits throughout the year, we have to make sure they’re available,” Harrison said.
She added that MISO must still determine how to treat capacity resources that take long-term outages. The RTO’s draft plan stands to reduce capacity accreditation for resources on long-term outages during the predefined tight hours, even if MISO has already approved the planned outages.
Stakeholders seemed most preoccupied with the potential for capacity resources to be penalized through accreditation reduction for planning extended outages during RA hours. Stakeholders said those hours would probably be difficult to predict and avoid when planning generation outages months in advance.
“Why would anyone bother to get permission for outages if they’re going to be penalized by MISO?” Customized Energy Solutions’ Ted Kuhn asked. “There is no benefit to providing this information. You’re basically going forward with an accreditation process that says, ‘I don’t care if you’re approved; you’re going to be penalized anyways.’”
Kuhn said the move might disincentivize resources from providing the data that MISO relies on for system reliability and to define tight margin hours.
“There is room for outages to be planned effectively and avoid these hours,” Harrison countered.
Harrison said the proposal focuses on individual unit behavior instead of socializing the risk across several capacity resources.
“I think we’re moving away from a process that penalizes everyone by focusing on individual units’… ability to meet capacity requirements,” she said.
“It seems incongruous of MISO to say, ‘Sure, you can take an outage, but the risk is on you,’” MidAmerican Energy’s Greg Schaefer said. He said the proposal seems to rely on resources’ “sheer luck” of not scheduling outages during RA hours.
“We all agree to pay a small premium to avoid people getting hammered,” he said, likening resources’ shared risk to a health insurance pool.
Kuhn asked MISO to consider implementing less severe repercussions for resources that aren’t available in light-risk seasons, when the RTO can only identify a few RA hours. Harrison said MISO would consider the idea.
Senior Manager of Resource Adequacy Coordination Lynn Hecker argued the availability-based accreditation proposal that takes the riskiest hours into account is “outage agnostic” by taking a true measure of resources’ availability.
MISO Executive Director of Market Operations Shawn McFarlane said it rewards the “more available portfolios” and reduces the accreditation of “less available portfolios.”
Thursday’s meeting of NERC’s Member Representatives Committee (MRC) saw the unanimous re-election of Trustees Robin Manning and George Hawkins, as well as the approval of two new board members: former American Public Power Association CEO Sue Kelly, and Larry Irving, president and CEO of consulting firm The Irving Group. The new and returning trustees will serve three-year terms expiring in February 2024.
NERC Board Chair Kenneth DeFontes | NERC
The Nominating Committee selected Kelly and Irving to fill the position of departing Trustee Jan Schori, who has served on the board for 12 consecutive years and is therefore ineligible for renomination. Kenneth DeFontes, who chaired the committee, said it decided to add an extra trustee in light of the “substantial work NERC will face over the next few years.”
DeFontes also replaced Roy Thilly as chair of NERC’s Board of Trustees at its meeting the same day, with Trustee Bob Clarke taking over from DeFontes as vice chair. Because Thilly will reach 12 years on the board in 2023, enlarging the class of 2024 will also ensure the additional trustee gains experience ahead of his departure. In addition, the board welcomed Kelly Hanson as NERC’s new senior vice president and chief administrative officer.
Presenting a resolution to honor Schori at the MRC meeting, Thilly joked that “it’s not surprising that Ken and his committee decided to find two people to fill Jan’s seat.”
Standards Actions
The board agreed unanimously to the following actions in accordance with Project 2018-03 (Standards efficiency review retirements):
adopt reliability standard FAC-008-5 (Facility ratings) and file it with FERC;
FAC-008-5 is a replacement for the proposed standard FAC-008-4, which was submitted to FERC in 2019 but remanded by the commission last year because of its planned retirement of FAC-008-3 Requirement R8. (See “Retirements to Streamline Standards,” FERC Accepts Removal of 18 NERC Requirements.) The new standard retains R8 but retires R7 as planned in FAC-008-4 and approved by FERC.
In addition, the board voted to withdraw the proposed CIP-002-6 (BES cyber system categorization). The withdrawal leaves the currently effective CIP-002-5.1 in place.
This standard was already before FERC, having been approved by the board last year. (See “Other Approvals,” NERC Board of Trustees/MRC Briefs: May 14, 2020.) However, NERC staff believed that “recent cybersecurity events and the evolving threat landscape” justify removing it from consideration to re-evaluate its impact on cybersecurity preparedness — in particular, its change to the criteria for categorizing control centers as medium-impact bulk electric system cyber systems.
Committee, RE Changes Accepted
Board members also accepted several actions by the board’s committees:
approval of the 2021 work plans for the Standards Committee and the Compliance and Certification Committee;
submittal of the 2020 year-end unaudited statement of activities from the Finance and Audit Committee (FAC);
amendments to the mandates of the FAC and the Corporate Governance and Human Resources (CGHRC), Technology and Security, and Enterprise-Wide Risk Committees; and
approval of the CGHRC’s policy on internal audit and corporate risk management.
The board also approved amendments to the bylaws of Texas Reliability Entity. The new bylaws are intended to provide greater scheduling flexibility for Board of Directors meetings and clarify member voting, and add an emergency governance section to allow for a smaller quorum of voting directors during an emergency. Changes to SERC Reliability’s Regional Reliability Standards Development Procedure were accepted as well.
Decisions Deferred on May, Aug. Meetings
Outgoing NERC Chair Roy Thilly | NERC
Board and MRC members will have to wait until March 10 to find out whether their next meeting will be held online or in person, as the COVID-19 pandemic continues to impact organizations’ travel arrangements. The event is currently scheduled to take place May 12-13 in D.C.; Thilly said the board has yet to determine whether “any portion of it” can be done in person.
A decision on the third meeting of the year, planned for Aug. 11-12 in Vancouver, Canada, has also been delayed until “some time in spring.” In addition to pandemic concerns, Thilly said the “international location may create some additional complications.”
The board and MRC have not met in person since their February 2020 gatherings in Manhattan Beach, Calif. Earlier this year CEO Jim Robb said the successful shift to remote work over the past year has inspired NERC to consider a partially online format for future meetings, in which the February and August events would be open to stakeholders and accompanied by in-person meetings of the MRC, while the May and November meetings would be open to in-person attendance by board members only. Stakeholders could listen online, while the MRC would hold its meetings virtually. (See NERC Considering Long-term Virtual Board Meeting Format.)
The board asked for industry feedback on this straw proposal ahead of Thursday’s meeting. Robb admitted that the responses in the policy input package showed “no great consensus” on this specific plan but added that it was “clear that stakeholders recognize” the potential benefits of more virtual meetings, including flexibility in scheduling and the ability for a wider range of participants to take part.
California may have the most electric vehicles in the nation (803,816), but Vermont has the most DC fast chargers per 100,000 residents (36.5) and Ohio offers some of the highest incentives ($50,000 to $2 million) to help companies trade in their diesel 18-wheelers for electric trucks.
These facts and figures appear in the American Council for an Energy Efficient Economy’s (ACEEE) first-ever State Transportation Electrification Scorecard, released Feb. 3. Like ACEEE’s annual state scorecard on energy efficiency, the new report rates states on their efforts to spur electric vehicle adoption. Predictably, California took the top spot, followed by New York and the District of Columbia, while West Virginia, Arkansas and Mississippi were at the bottom of the list.
State scores from ACEEE’s Transportation Electrification Scorecard |
Rounding out the top 10 were, in descending order, Maryland, Massachusetts, Washington, Vermont, Colorado, Oregon and New Jersey. ACEEE found 27 states offer financial incentives for EVs, 36 states have lower electric rates for EV charging and 48 states are using federal funds to buy electric buses.
In other words, states are providing the momentum for transportation electrification, filling the void in federal leadership created by the last four years, said Bryan Howard, ACEEE’s state policy director and lead author of the report. Strong policy coupled with collaboration with utilities and the transportation sector, are moving the market, he said.
Beyond the overall ratings, ACEEE’s granular approach to scoring each state shows the wide spectrum of policies and programs that will be necessary to cut the millions of tons of carbon emissions produced each year by autos. The transportation sector now accounts for 28% of the country’s greenhouse gas emissions, edging out the electric power system — at 27% — as the nation’s top source of GHGs, according to figures from the EPA.
Electrifying transportation could cut emissions almost in half by 2050, according to the report, but the nearly 1.8 million EVs currently on the road represent only 2% of the U.S. vehicle market.
Although overall car sales stagnated in 2020 because of the COVID-19 pandemic, EV sales as a percentage of all car sales in California “are higher than they’ve ever been,” said Patty Monahan, a member of the California Energy Commission.
“We’re seeing this play out, not just in California, but globally,” Monahan said during an ACEEE webinar on the new report. “EV sales in the [European Union] are higher than they’ve ever been; China is a major market. This is an inevitable movement to electrify transportation. The question is how fast?”
California is setting the pace with Gov. Gavin Newsom’s (D) recent executive order requiring all light-duty cars and trucks sold in the state to be zero-emission vehicles (ZEVs) — either electric or hydrogen-fuel cell — by 2035. (See Calif. to Halt Gas-powered Auto Sales by 2035.)
State programs to promote EV sales are focused on lowering major barriers to EV adoption — what Monahan called “the three C’s” — cost, convenience and customer awareness.
For example, California offers rebates not only for new EVs, but also for used EVs, to support the second-sales market, which often serves as the entry point for low-income consumers, Monahan said. The state is also working with automakers, such as GM, to allow consumers to take advantage of the state’s tax credit for EVs at the point of sale, which is “particularly important for folks with the need to accrue that benefit immediately rather than carrying the cost,” she said.
Identifying the Gaps
The report and its exhaustive appendices provide a deep dive into state policy, with ACEEE’s 100-point scoring system accounting for each state’s individual policy and program measures. For example, separate incentives for light-duty electric cars and heavy-duty trucks are worth 4 points each, as are state EV programs targeting low-income or disadvantaged “environmental justice” communities.
Who’s moving state EV policies forward — the governor, the legislature or the regulatory commission |
The report also tracks which branches of state government are the prime movers in enacting and implementing EV-friendly policies — the governor, legislators or utility regulators. Not surprisingly, in the leading states, all three branches are significantly involved, and in California, New York and Massachusetts, they are equally influential.
The benchmarking provides a clear view of the most impactful policies as well as identifying the gaps where better and more innovative approaches are needed. Howard was surprised that only five states have updated their building codes to require new construction to be “EV-ready.”
“Specifically, with multifamily buildings, there are a lot of opportunities to ensure we’re getting access and benefits to those parties,” he said.
Decarbonizing the electric system was also called out as an essential corollary so that EVs are manufactured with and can charge up on clean power. Here the role of utilities comes to the fore, whether they are investing in EV charging infrastructure, decarbonizing their own power supplies or offering lower rates or managed charging programs for EVs.
Equity and Electric Trucks
The role of equity and the need for all states to step up their efforts in this area was another major takeaway from the webinar. New York’s aggressive EV programs — aimed at putting 850,000 ZEVs on the road by 2025 — include a requirement that 40% of all funds be spent in disadvantaged communities, said Zeryai Hagos, a deputy director at the New York Department of Public Service.
The state is launching an “$85 million prize competition to solicit ideas and implement them to reduce emissions in communities that are impacted by transportation emissions,” Hagos said, noting that community engagement will be a core requirement for any proposal.
In Colorado, equity means ensuring chargers are installed between population centers and in small and rural communities, said Shoshana Lew, executive director of the state’s Department of Transportation. Initiatives aimed at electrifying medium- and heavy-duty trucking are another priority.
“There’s a lot of heavy trucking in low-income communities,” she said, so the state wants to “double down on increasing the availability of clean trucking. We’re taking a sort of place-based approach about how we do emission reductions in some of those areas.
| California Energy Commission
Doing it Right
Another gap includes the things ACEEE says it could not measure, in particular, initiatives addressing customer awareness. While acknowledging their importance, the report notes that reliable and measurable data were not available on such public education programs.
The report also highlights, but does not specifically score, interregional efforts such as the Transportation and Climate Initiative, an effort by Northeast and Mid-Atlantic states to reduce GHG emissions from the transportation sector. Massachusetts, Connecticut, Rhode Island and D.C. are working on a program that would require transportation fuel distributors to buy allowances to offset their emissions, with the money going to support low-carbon transportation. (See NE States, DC Sign MOU to Cut Transportation Pollution.)
ACEEE recommends states lagging on EV adoption begin with planning and setting goals for transportation electrification. Step 2 is collecting extensive data, not only on how many electric cars and trucks are being sold, but the demographics of who’s buying them and where chargers are being installed. This data should be regularly reported and publicly available to ensure policies and programs are having intended impacts, the report said.
The goal, Monahan said, is to provide a steady stream of incentives and other programs to create a virtuous cycle for EV adoption. “We do it right; consumers buying electric have much lower costs,” she said. “We do it right; that money gets recirculated back to our economy and continues to generate benefits for the state. We’re seeing this as an opportunity for keeping money in consumers’ pockets and the state and not exporting it to other countries.”
The Biden administration is aiming to support the work states are already doing to eliminate harmful emissions by filling in funding gaps and strengthening climate policy, according to White House National Climate Adviser Gina McCarthy.
A major focus will be delivering on Biden’s promise to create jobs in the clean energy industry, McCarthy said during the National Association of State Energy Officials 2021 Energy Policy Outlook Conference on Wednesday.
The federal government can “bring hope again to individual communities, those that have been left behind and those that are worried about this transition” by working with state authorities, McCarthy said.
Gina McCarthy says the Biden administration is not seeking to duplicate states’ efforts on building climate policy over the last four years. | Gray Watson, CC-BY-SA-3.0 via Wikimedia Commons
A lack of leadership at the federal level on addressing climate change during former President Donald Trump’s administration left state governments to create their own alliances and initiatives for sweeping change, most notably the U.S. Climate Alliance. McCarthy said the Biden administration is not seeking to duplicate these efforts, but to “make investments of federal dollars” into those ongoing efforts.
Craig Altemose, executive director of environmental advocacy organization Better Future Project, told RTO Insider that federal funding to support existing state and regional efforts, such as the Renew New England Alliance, will “employ a bunch of people to help solve the climate crisis.”
One of the organization’s top priorities in the upcoming Massachusetts legislative session is to promote the Massachusetts Renews Alliance, which will launch later this month with a goal of coordinating the retrofit of 1 million homes in the state within the next decade.
The group has been a couple years in the making, Altemose said, but the state of Massachusetts alone may not have the financial resources to make it a reality, and the COVID-19 pandemic has further slowed progress. But support from the federal level could help the state achieve its energy goals while offering employment opportunities.
“You can’t take a house, ship it to China, have them retrofit it and ask them to ship it back,” Altemose said. “It needs to be humans from this area.”
McCarthy said the climate targets under the Biden administration will be challenging to meet, but the major transitions “are not anything fundamentally to object to if it [means] better jobs — more jobs — and a stable economy.”
Working with Unions
Commenting during the conference session, attendee Kerry Campbell, manager of the Energy Policy and Technology Deployment Division within the Pennsylvania Department of Environmental Protection, said the office does not have strong engagement from unions on transitioning to clean energy, though unions are critical in the implementation of new climate initiatives.
McCarthy said the administration has started discussions with unions on how to make the transition to clean energy without leaving communities that rely on carbon-emitting industries behind the curve.
“We cannot think that the shift to clean energy is going to mean that people who are working in the coal mines now happily take $9/hour jobs or $10/hour jobs putting solar on roofs,” McCarthy said. Creating high-quality renewable energy jobs at the local level will ensure families who have lived in one place for generations won’t need to move to find employment opportunities, she said.
Like any utility executive worth his salt, Tri-State Generation and Transmission CEO Duane Highley enjoys looking at LMP contour maps.
“It’s just a fascination of mine,” he said during a virtual press conference Tuesday to discuss SPP’s new Western Energy Imbalance Services (WEIS) market.
Duane Highley, Tri-State | SPP
The only drawback for Highley these days is that WEIS’s contour map is staying a cool blue, an indicator of low prices. No swatches of orange or red, signs of congestion and high prices.
“It’s been non-exciting,” he said. “Every time I’ve looked at it, it’s all been blue. That tells me the market is working right now.”
Bruce Rew, SPP’s senior vice president of operations, interjected to say the infant market’s prices have been averaging around $24/MWh since the Feb. 1 launch of the five-minute, real-time balancing exchange. (See SPP Successfully Launches Western Market.)
“Price transparency. We didn’t have that before,” Highley said. “We’ll be able to develop financial tools that help us manage that price. Just lots of benefits like that coming this way.”
In addition to lower wholesale prices, those benefits include greater access to renewable energy, reduced congestion, elimination of rate pancaking and better reserve margins.
For Tri-State, the WEIS market’s most attractive attribute is the access it offers to more renewable resources. Under the cooperative’s 20-year, $21.3 billion Responsible Energy Plan, it will reduce its CO2 emissions by 80% from 2005 levels by 2030 by adding more than 1.8 GW of renewable capacity, more than double its currently contracted solar and wind resources.
“We don’t believe it’s possible to get there without integrating these massive amounts of renewables across our footprint,” said Highley, who led a group of Arkansas cooperatives before taking over the reins at Tri-State.
SPP’s RTO footprints in the Western and Eastern Interconnections | SPP
“I’m very familiar with SPP’s governance model. … It’s very similar to the cooperative model. It’s member-driven with member input,” he said. “Sometimes it’s been described as painfully collaborative, but it gets results.”
Highley was joined by Mark Gabriel, the Western Area Power Authority’s (WAPA) CEO, and Tom Christensen, Basin Electric Power Cooperative’s senior vice president of transmission, engineering and construction, in extolling the benefits of the WEIS market. WAPA and Basin Electric’s Eastern systems are both full members of SPP’s Integrated Marketplace.
“We’ve certainly seen benefits as well. Those savings and economics have benefited us and our membership,” Christensen said. “There are better economics with day-ahead congestion management [and] coordinated [transmission] planning processes. But some of SPP’s best work is what they’ve done with resource adequacy. They’ve got a method, with increasing levels of wind at 32% [of the fuel mix], yet they run a reliable system.”
All three men referred to the WEIS market as just a preliminary step to full RTO membership. Highley said Tri-State is projecting $2 million in benefits, net of cost, in the market’s first year of operation. A SPP Stakeholders Dig into WEIS Market Study.)
The WEIS market is offered on a contract basis, as is the RC service SPP also provides in the Western Interconnection. Most of the market’s members have indicated to the grid operator that they are interested in pursuing full RTO membership.
“We think [this WEIS market] is the first step,” Christensen said. “We would like to, and we believe we need to, advance to a full RTO in the West. The governance model, the stakeholder process all leads to a logical choice for us. It’s a realistic path forward.”
Mark Gabriel, WAPA | SPP
“The fact we’re talking about markets in the West is a major change,” Gabriel said. “Markets are coming to the West hard and fast. It’s necessary for reliability, resilience and the ability for power to flow back and forth much more freely. The WEIS market is really just the first step in what we’re going to see over the next two to three years.”
SPP is currently working with the prospective members in evaluating potential changes to the RTO’s governing documents. Assuming board approval of the changes, it would be another two years from the entities’ commitment to becoming full members, Rew said.
“This is just the beginning of these partnerships in the West,” SPP CEO Barbara Sugg said. “We have an opportunity to partner with these entities to help them, and help their customers, to meet their financial and renewable goals. I know things are a little different in the West, but we’re highly confident the benefits we provide the entities in the East are available in the West.”
But Sugg expressed confidence in SPP’s ability to compete in the West.
“The key to more entities having an interest in SPP is seeing the success their neighbors have,” she said. “They say if you build it, they will come. Well, we’ve built several things for smaller groups. The more people that come, the more everyone benefits from it.”
Electricity demand will return to pre-COVID levels by 2025 while total energy consumption will likely lag until at least 2029, the Energy Information Administration said Wednesday.
Energy demand from the residential, commercial, transportation and industrial end-use sectors dropped by 10% from 2019 levels to 2020 — faster than the drop in gross domestic product — because of the coronavirus pandemic. The drop in demand was about 70% larger than that following the 2008 financial crisis and the speed at which it rebounds “remains uncertain,” EIA said.
“In a case that assumes low economic growth, energy consumption does not return to 2019 levels until 2050,” the agency said in releasing its Annual Energy Outlook 2021 (AEO), which projects energy trends to 2050.
EIA’s reference case, or baseline projection, does not include the effects of proposed legislation or regulations. The report also includes sensitivities assuming high and low levels of economic growth and high and low oil and renewable prices. The high renewables cost case, for example, assumes no cost reduction from learning for any renewable technologies.
The AEO also projects that U.S. energy-related CO2 emissions will drop through 2035 before increasing.
Industrial energy consumption is projected to rebound faster than other sectors, although EIA noted “specific industries will return to 2019 levels at different rates.”
Electric Demand and Generation
The AEO’s reference case projects an annual average electricity growth rate of less than 1%, as economic growth is partially offset by efficiency improvements.
Generating capacity is projected to increase 52 to 84% through 2050 across the scenarios considered. The reference case foresees renewables accounting for almost 60% of the 1,000 GW of capacity additions.
“Although capital costs for both wind and solar continue to decline throughout the projection period, without additional policy intervention, wind is not as cost-competitive as solar,” EIA said. “More than two-thirds of cumulative wind capacity additions from 2020 to 2050 occur before the [production tax credit] expires at the end of 2024. The steadier pace of solar additions in part reflects the continued availability of a 10% investment tax credit, which continues in perpetuity after 2023 when the current 30% phases out.”
Projected electric generating capacity additions and retirements between 2021 and 2050 (GW) | EIA
Natural gas-fired generators account for most of the remaining capacity increase — almost evenly split between combined-cycle plants and combustion turbines — but its share of the generation mix will remain at about one-third. Gas capacity factors for existing combined-cycle units are projected to drop by nearly half from a peak of 60% in 2020.
Most of the coal-fired generating capacity retirements assumed in the reference case occur by 2025, but the report notes that the baseline includes the Trump administration’s Affordable Clean Energy (ACE) rule, which was vacated by an appellate court on Jan. 19. (See DC Circuit Rejects Trump ACE Rule.)
Rooftop PV systems and combined heat-and-power systems are projected to total more than 7% of total generation by 2050, almost double the current share.
Transportation
Energy consumption for transportation is projected to remain below 2019 levels through 2050 as improvements in fuel economy will offset a resumption in travel growth. The reference case sees air travel demand returning to pre-COVID levels in 2025, with bus travel demand rebounding in 2031 and light-duty vehicles returning by 2024.
While aviation’s energy consumption (excluding military use) will hit 2019 levels by 2030, energy consumption by light-duty and heavy-duty vehicles is forecast to be lower than 2019 levels through 2050.
While transportation has the greatest potential for increased use of electricity, demand from the sector is expected to remain below 3% of economy-wide electricity demand. “Current laws and regulations are not projected to induce much market growth, despite continuing improvements in electric vehicles through evolutionary market developments,” EIA said. “Both vehicle sales and utilization (miles driven) would need to increase substantially for EVs to raise electric power demand growth rates by more than a fraction of a percentage point per year.”
However, motor gasoline consumption will peak before the middle of this decade, EIA said, because fuel economy improvements will partially offset travel growth.
Speaking Wednesday during an Energy Storage Association Policy Forum session, panel members were cautious to place climate and energy policy issues behind the need to help the American people though the COVID-19 crisis.
Katherine Monge, senior counsel to House Speaker Nancy Pelosi (D-Calif.), said that, while Pelosi’s staff is thinking about immediate needs stemming from the pandemic, the climate crisis is a conversation that is always present.
“We’re looking at how to decarbonize this economy and how to use the levers that are out there, like regulation and tax incentives, to encourage more deployment and reduce emissions,” she said during the panel on where storage fits into the 117th Congress’ agenda.
This year, Monge said, House will try to build on its passage of the Moving Forward Act last July, a $1.5 trillion infrastructure bill that failed to get a vote in the Republican-controlled Senate.
Monge said the bill had significant investment in clean energy, including both spending and tax breaks.
How a new package comes together this year will depend on context and branding, she said. For example, it could be framed as a recovery package, an infrastructure plan or a climate bill.
“This green economy has lost 400,000 jobs to COVID-19, and that’s just one sector of the economy,” Monge said. “If you look at how we did the Recovery Act in 2009, it was very focused on green energy incentives.”
Congress will have to balance support for energy storage with recovering from the COVID-19 pandemic. | Maxwell Technologies
Under any context, however, the policies that will be moved forward in the House must support the Biden administration’s plan for carbon neutrality by 2035. Those policies, Monge said, will be far more stable with bipartisan support in Congress. (See Biden Signs Sweeping Climate Orders.)
Robert Andres, senior policy adviser to Senate Finance Committee member Ron Wyden (D-Ore.), agreed that bipartisanship will be important to supporting economic recovery, and climate-related issues can be a part of that.
He said that investments in the technologies that address climate change are a key pathway to recovery from the pandemic.
“As we think about infrastructure and climate, our [committee] members, a lot of them, view those two things in conjunction … but we’ll have to see what the scope of any new package will look like,” he said.
Brie Van Cleve, a Senate Energy and Natural Resources Committee (ENR) staff member serving incoming chair Joe Manchin (D-W.Va.), said there were many policy areas that did not make it into the Moving Forward Act last year.
“We’ll want to revisit some of those policy areas where we had a very good, robust bipartisan package,” she said, citing workforce development, electric vehicles and cybersecurity.
“[Manchin] recognizes that the energy mix is transitioning, and he would like to do what we can to make sure that we have the clean technologies that we need in place or coming down the pike,” she said.
ENR staffer Jacob McCurdy said revisiting cybersecurity will be important in considering any new energy bill.
“Cybersecurity is not isolated to the bulk power system, and we’ve seen a lot of movement on the distribution side with FERC Order 2222 aggregating [distributed energy resources] into the wholesale markets,” he said.
North Carolina Environmental Secretary Michael Regan, President Biden’s nominee for EPA administrator, appeared well on his way to confirmation Wednesday after coasting through an easy Senate Environment and Public Works Committee hearing.
Sens. Richard Burr and Thom Tillis, both Republicans and fellow North Carolinians, set the tone for the hearing by introducing Regan, praising him for his work at the state’s Department of Environmental Quality. Both said he was a fair, transparent regulator who kept residents in mind when making decisions.
“Secretary Regan was able to find the right balance by reaching out to stakeholders and ensuring that the department’s relationship with rural communities, whose lifeblood is agriculture, was constructive and not adversarial,” Burr said. Agriculture associations that support Regan’s nomination “understand that they’re not always going to agree with decisions handed down by the EPA. But they know and trust that they’ll receive a fair hearing.”
“Michael distinguished himself as someone who listens and someone who tried to take in input from both sides and come up with a fair outcome,” Tillis added. “We have to understand that the election produced a different leader down in the White House, and we can’t imagine that as Republicans, the president is going to have the same priorities as ours. But what we can hope for are people in the administration who have a track record of listening.”
North Carolina Environmental Secretary Michael Regan | PBS
Regan highlighted his previous work as an air quality specialist at EPA, from 1998 to 2008, before he became environmental secretary. When he assumed his current role, the state had elected Democrat Roy Cooper over incumbent Republican Gov. Pat McCrory.
“Throughout my career, I’ve learned that if you want to solve complex challenges, you must be able to see them from all sides, and you must be willing to put yourself in other people’s shoes,” Regan said in his opening statement. “I’ve also learned that we simply can’t regulate our way out of every problem we face. This approach has proven to be effective during my tenure as secretary of DEQ. …
“Our priorities for the environment are clear: We will restore the role of science and transparency at EPA,” he continued. “We will support the dedicated and talented career officials. We will move with a sense of urgency on climate change. We will stand up for environmental justice and equity. And we will do that in a collaborative manner.”
Republicans did not question his credentials, nor did they challenge him on any statements he made in the past, signaling he will not receive much opposition. They mostly complained about the president’s recent executive orders — particularly his ban on new oil and gas drilling leases on federal lands — as hurting jobs in their states. They also used their time to criticize Biden’s two “climate czars,” John Kerry and Gina McCarthy.
Much like Biden’s nominee to head the Energy Department, former Michigan Gov. Jennifer Granholm, did last week, Regan pledged that the administration would not leave any workers in the fossil fuel industries behind in the transition to a net-zero-emission economy. (See Granholm Attempts to Placate Coal State Senators.)
But he also did not get into specifics about Biden’s climate agenda. Sen. Shelley Moore Capito (R-W.Va.), asked him several times about the Clean Power Plan, the Obama administration’s regulation for meeting the emission-reduction targets under the Paris Agreement on climate change. Regan responded by saying he did not want to “look backward, but to look forward,” and that Biden would implement his own strategy for reducing emissions from power plants.
Sens. Thom Tillis (left) and Richard Burr, both Republicans of North Carolina, delivered the customary introductory remarks at Regan’s confirmation hearing. | PBS
Later, when Capito asked him whether Section 111(d) of the Clean Air Act — the legal foundation for the CPP — allowed EPA to regulate emissions “outside the fence line,” Regan said he would have to consult with staff and study recent court rulings on the law. But he did say there was “opportunity for a clean slate” after the rejection of the Trump’s administration Affordable Clean Energy Rule. (See DC Circuit Rejects Trump ACE Rule.)
Republicans were also concerned that Regan would be influenced or even overruled by Kerry and McCarthy. Regan asserted that he would answer only to the president and that he alone would be responsible for what EPA does.
When Capito asked him what he would do if he had a disagreement with the czars, Regan responded, “With any complex issue, we anticipate healthy debates. And I believe the reality is we serve different positions within the administration. So I have no reason to believe that the positions of the EPA and the positions of the White House will not get equal [consideration], and hopefully we will have robust discussions in a manner that will yield the best results for the president to achieve his ambitious climate goals.”
Granholm Approved for Senate Floor Vote
Earlier Wednesday, the Senate Energy and Natural Resources Committee voted 13-4 to advance Granholm for a floor vote.
Despite praising her for her confirmation hearing performance last week, Barrasso and Sen. Mike Lee (R-Utah) joined fellow Republicans Bill Cassidy (La.) and Cindy Hyde-Smith (Miss.) in voting against Granholm. Both cited Biden’s recent spate of climate-related executive orders, including his ban on new oil and gas drilling leases on federal lands.
“Gov. Granholm stated multiple times that she didn’t want to see anyone lose their job or get left behind,” Barrasso said. “But this is precisely what the Biden administration is doing. … The president will throw thousands of Americans out of work. Their livelihoods are being sacrificed in the name of the Biden agenda.”
“She’s capable; she’s confident; she’s sincere,” Lee said. “I wish I could vote for her. I would like to be able to vote for her. I so strongly disagree with this administration’s energy policies and what it’s done already through executive order … which in my state are already having dire economic consequences.”
Musical (Committee) Chairs
Before the vote on Granholm, Sen. Lisa Murkowski (R-Alaska) joked that it was fitting that it was the day after Groundhog Day, as she had said that last week’s hearing would be her last as chair of the committee, and yet she was still in the position.
That was because Senate leaders had not agreed to an organizing resolution between the parties. Democrats have a narrow majority, with Vice President Kamala Harris holding the tie-breaking vote. The stalemate left committee positions in a state of flux, with each committee conducting business its own way. Though Murkowski opened and closed Wednesday’s meeting, she deferred to the incoming chair, Joe Manchin (D-W.Va.), to conduct it. Later, outgoing EPW Committee Chair Barrasso left it to Capito to chair the Regan hearing, though Sen. Tom Carper (D-Del.) will ultimately be the chair.
Before the Regan hearing, news broke that Majority Leader Chuck Schumer (N.Y.) and Minority Leader Mitch McConnell (Ky.) had come to an agreement. The details of the deal were not made public as of press time, but it appears McConnell withdrew his objections once Manchin and Sen. Kyrsten Sinema (D-Ariz.) pledged they would oppose any efforts to end the filibuster, denying Schumer the votes needed to change the rules. The Senate passed the organizing resolution by unanimous consent shortly after the hearing.
How soon Regan and Granholm will be confirmed is unclear. The Senate will need to halt all other business Feb. 9 when it begins the second impeachment trial of former President Donald Trump.
The Desert Southwest (DSW) region is at risk of failing to meet loads during its peak hour this year even under the most optimistic assumptions — with risks rising to seven hours next year — according to a new report from WECC.
WECC’s Desert Southwest subregion contains Arizona, most of New Mexico, and small areas in Southern California and West Texas. | WECC
Potential RA shortfalls have been a growing concern in the West as states have mandated the closure of fossil fuel generators while requiring buildout of variable renewable resources. The issue took on new urgency last August when an extended and severe heat wave prompted rolling blackouts in California and grid emergencies in neighboring regions.
“In the heat wave of last year … we just didn’t have enough reserve margin going into those hours. The variability hit us, with the high demand throughout all of the interconnection,” WECC Manager of Performance Analysis Matt Elkins said Tuesday during a webinar to discuss the report.
The report focuses on an area that largely covers Arizona and New Mexico but also extends into the service territories of the Imperial Irrigation District in Southern California and El Paso Electric in West Texas. Over the next month, WECC will release additional reports for California and Mexico and the vast area served by the Northwest Power Pool.
In its assessment, WECC applied two scenarios to the five subregions to examine a broad range of future resource possibilities and factor in known and expected resource retirements. Scenario 1 — referred to as the “standalone” scenario — assumes that each subregion will be responsible for meeting its load with internal resources, while Scenario 2 allows for imports.
WECC then overlaid each scenario with three variations of resource availability. Variation 1 includes all resources currently in service and expected to be operable in future forecasts. Variation 2 includes existing resources and those under construction and expected to run in the forecast year (Tier 1 resources). Variation 3 — which represents the most “optimistic” assumptions — includes existing and Tier 1 resources as well as those currently in licensing or siting phases but not yet under construction (Tier 2).
‘We Just Can’t Use Fixed’
WECC found that demand in the DSW subregion is expected to peak in early July around 25,700 MW, although there is a 5% probability the peak could hit 29,100, equating to a 13% load forecast uncertainty. The subregion’s coincident peak is expected to occur at 4 p.m. that day, with the lowest demand occurring at 4 a.m.
“Overall, the DSW subregion should expect a 100% ramp, or 12,800 MW, from the lowest to the highest demand hour of the peak demand day,” the report said.
The analysis finds that the DSW should have about 29,300 MW of resources available to meet the expected peak demand, but based on historical analysis, there is a 5% probability that only 24,300 MW will show up, requiring “significant imports” to provide relief.
A standalone situation would translate into chronic problems for the DSW this year. Under Scenario 1 (no imports), the subregion is at risk of not meeting the ODITY threshold for 415 hours, translating into 624 MW of unserved demand for each hour.
WECC estimates the Desert Southwest subregion’s load will peak at 25,700 MW this year, but its report allows for a 5% probability of 29,100-MW peak. | WECC
While that scenario is unlikely given trading patterns in the West, even under the most optimistic assumptions (Scenario 2, Variation 3), the DSW still confronts the potential of falling short of the threshold for one hour this year, WECC found. In 2022, at-risk hours increase to seven under that situation, and rise even more sharply under a scenario that assumes imports plus only Tier 1 resources (14 hours) and imports with only existing resources (44 hours).
While WECC said imports reduce the probability that the DSW will become resource inadequate, it also warned that the growing variability in supply and demand across the Western Interconnection “increases the risk that imports may not be available when needed.”
The problem becomes especially acute with the increased adoption of solar resources, which all fall off the system around the same time in the evening, prompting the need for sharp ramps from other resources.
“One of the things we need to realize, and I think the heat wave event was a prime example, is that if variability hits everybody at the same time, there could be less available out there for assistance for the Desert Southwest,” Elkins said.
The increasing bent toward system variability means that Western utilities should revisit the practice of maintaining fixed planning reserve margins (PRMs) on an annual or seasonal basis, and instead consider dynamic margins to fit hourly needs, WECC contended in its December assessment.
Elkins raised that point again Tuesday, saying the need for dynamic PRMs becomes even more evident during the shoulder seasons of spring and fall, when demand is even more variable than during the peak seasons. Maintaining the standard of 15% margins used in much of the West just won’t suffice, he said.
“When you get into the springtime or in the fall and you’re doing planned maintenance … if you’re taking resources out, you’ve got to understand this is a very variable time in the system, so [you] need to make sure [you] hold more than 15%,” Elkins sad.
“With variability growing in the system, the [PRM] percentage has to be variable. We just can’t use fixed,” he said.
