Page 1019 – RTO Insider

November 10, 2020February 19, 2025

GOP Senate May Limit Biden Climate Ambitions

“Today, the Trump administration officially left the Paris Climate Agreement,” former Vice President Joe Biden tweeted Nov. 4, the day after the elections. “And in exactly 77 days, a Biden administration will rejoin it.”

There’s no doubt the federal government’s climate policy will change abruptly come January. President-elect Biden’s transition website lists climate change among his four top priorities, promising to “meet these challenges on Day One” of his administration. The new president is expected to quickly undo the environmental rollbacks President Trump accomplished by executive power.

But a Republican-controlled Senate and a narrower Democratic edge in the House of Representatives would likely prevent him from winning approval of his proposed $2 trillion climate plan. His ability to include incentives for renewable energy in a new economic recovery package would also be ratcheted down. (See Biden Offers $2 Trillion Climate Plan.)

Democrats still have a chance at winning effective control of the upper house, with two Senate races in Georgia headed to runoff elections Jan. 5. Winning both seats would result in a 50-50 tie that would be broken by Vice President-elect Kamala Harris.

Failing that, any legislative action will depend on Biden’s ability to cut deals with Senate Majority Leader Mitch McConnell (R-Ky.), who is certain to oppose any bill that threatens what remains of his state’s coal industry.

Author Anand Giridharadas expressed optimism in a New York Times op-ed titled, “Biden Can’t Be FDR. He Could Still Be LBJ.”

“Mr. Biden could turn out to be an improbably deft salesman for progressive priorities, using his disarming, folksy, median-voter-friendly patois, that ‘C’mon, man’ Americana vibe, to make major changes seem like common sense,” Giridharadas wrote.

Former House Majority Leader Eric Cantor | Edison Electric Institute

But former House Majority Leader Eric Cantor (R-Va.) said there are limits to Biden’s powers of persuasion. “With a divided government, with the election turning out the way it is, I’m not so sure there is any incentive to all the sudden make a U-turn and everybody come together,” Cantor said during the Edison Electric Institute’s Financial Conference on Monday. “I think it will take a lot of work on the part of the Biden White House … to make the gestures to really, really want to work with Mitch McConnell.”

With prospects for legislative action uncertain, observers are considering how much Biden can accomplish through his executive power, and how a Democrat-controlled FERC could spur policy changes.

The left-leaning Center for Policy Integrity issued a report in September on its proposed priorities for the commission, including revising its regulations to account for greenhouse gas emissions in its review of natural gas infrastructure projects. It also called for changing its transmission policies to support renewables and for the Department of Energy to delegate its authority to designate national interest electric transmission corridors to FERC.

Paris

The Biden transition site promises the president-elect will “lead an effort to get every major country to ramp up the ambition of their domestic climate targets” under the Paris Agreement. Under President Barack Obama, the U.S. made a “nationally determined contribution” (NDC) to cut U.S. GHG emissions 26 to 28% below 2005 levels by 2025.

Biden could attempt to nudge federal policy through regulations, stimulus provisions and tariffs on carbon-intensive goods. He will also have the support of state and corporate clean energy targets.

President-elect Joe Biden | Biden-Harris Transition

America’s Pledge, launched in 2017 by former New York City Mayor Michael Bloomberg and former California Gov. Jerry Brown, annually quantifies the climate actions of U.S. states, cities, businesses and other non-federal actors. Its September 2020 report said that “bottom-up climate leadership has kept the U.S. on a path of progress” and that “ambitious, expanded action by U.S. states, cities and businesses can reduce emissions up to 37% [below 2005 levels] by 2030.”

“If the federal government re-engages, invests in a green stimulus recovery and works together with states, cities and businesses to enact climate-forward policies, we can cut emissions by 49% from 2005 levels by 2030 and put America back in alignment with the Paris Agreement, reaching net zero emissions by 2050,” the report said.

Mandate?

Despite Democrats’ failure to gain decisive control of Congress, some observers contend Biden will enter office with a mandate for taking action on climate change.

Morning Consult’s exit polling found almost three-quarters of Biden voters said climate change was “very important” to their votes. Exit polling by the Associated Press and Fox News found that two-thirds of all voters support “increasing government spending on green and renewable energy.” A ballot measure requiring Nevada utilities get half of their electricity from renewable sources by 2030 won 57% support in the state — more than either presidential candidate. (See related story, Nevada Clean Energy Amendment Winning.)

Anthony Leiserowitz, director of the Yale Program on Climate Change Communication, told Bloomberg News that Biden will have “an enormous amount of runway to enact a bold climate agenda” and that some voters might even favor him declaring climate change a national emergency. “There’s even strong support among Democrats and independents for that,” he said.

Regulations, Executive Orders

Biden is expected to immediately reverse most of Trump’s executive orders on energy, including ordering government agencies to take actions to cut GHG and reversing a 2017 order directing federal agencies to revoke their climate policies. (The New York Times reported Nov. 9 that Trump had removed the scientist responsible for the National Climate Assessment, a report from 13 federal agencies and outside scientists that the government is required by law to produce every four years.) Activists have called for creation of a White House interagency group like the National Economic Council to coordinate decisions across the federal government.

“Many agencies, like [the Federal Housing Finance Agency, Department of Housing and Urban Development and Department of Transportation] could do a lot to integrate climate into agency actions without new legislation,” tweeted clean energy consultant and attorney Miles Farmer, a former member of New York Gov. Andrew Cuomo’s energy team. “Tackling challenges of realigning institutional priorities now would also position them to go much further if broad climate legislation is ever signed.”

Biden is also expected to order new methane limits on oil and gas wells and increase fuel economy standards and efficiency standards for buildings and appliances. He has also pledged an executive order requiring public companies to disclose climate change-related financial risks and their GHG footprints.

But Biden’s autonomy could be limited by the federal judiciary, half of whom are now Republican-appointed — up from 42% in 2017 — including a 6-3 conservative majority on the Supreme Court. He is not expected to resurrect the Obama administration’s Clean Power Plan, which was stalled by court challenges and discarded by Trump.

Congress

Eliminating carbon from the electric sector by 2035, as Biden has pledged, would require the closing of virtually all gas and coal generation and a huge expansion of energy storage. Efforts to get there could be aided by clean energy research and development funding and an extension of renewable tax credits.

If Biden is unable to work with McConnell, he could seek support from moderate Republican Sens. Susan Collins (Maine), Lisa Murkowski (Alaska) and Mitt Romney (Utah). But Romney made clear Sunday that he would oppose any legislation to institute a “Green New Deal.” And any efforts undermining coal would likely also face resistance from some Democrats, such as Sen. Joe Manchin (W.Va.) and Senator-elect John Hickenlooper (Colo.).

Former Murkowski aide McKie Campbell, now managing partner of the bipartisan energy consulting firm BlueWater Strategies, told The Washington Post he hopes divided government “means we may have a return of people working with each other to work out some solutions. The question is, in the middle, do you have compromise, or do you have stalemate and nothing happens?”

John Gimigliano, a principal with KPMG, predicted progress during a panel discussion Friday sponsored by law firm Norton Rose Fulbright. “I think overall, the climate is going to improve with a Biden White House for all things renewable, even with a Republican-controlled Senate,” he said. “There are always deals to be made.

“The question is, how much do the Democrats have to give up to get some of these things?” he added.

“Even with a 50-50 Senate that is notionally Democrat, [Biden] is going to be substantially limited to executive actions,” Christine Tezak, managing director with ClearView Energy Partners, said during the same panel. “He’s going to be fairly constrained to moving forward with massive policy initiatives. Limits on greenhouse gas doesn’t pencil for us. The only thing that might be possible under a 50-50 Senate is a clean energy standard, but not one broadly sketched by Joe Biden’s campaign.

“You might have to bring hydrogen and nuclear along just to start the conversation,” she continued. “The incrementally and substantially more conservative judiciary that has materialized over the last four years of the Trump administration is likely to challenge any administration that tries to pursue the bounds of its statutory authority. Something as ambitious as the Clean Power Plan is kind of doomed.”

Cantor, now vice chairman and managing director for investment bank Moelis & Co., said Biden’s reputation as a dealmaker gives him an opportunity. But he said that after Obama entered office promising bipartisan cooperation, his staff failed to make good on it. “There was just a one-party rule in [2009 and 2010], which made it very, very difficult once we claimed the majority in 2010 to even begin to work together,” Cantor said.

Casey Herman, leader of PwC’s U.S. power and utilities practice, told the EEI conference that Biden’s support for decarbonization, clean energy investments and large-scale electrification “provides potentially an exciting opportunity for the sector.”

“But if the Republicans do hold the majority in the Senate, that’s going to moderate the speed and the size of those policy initiatives,” he said.

FERC

How much impact could a Democrat-majority FERC have?

“It’s really going to be dependent on what McConnell wants,” said Tezak, who noted that Trump’s nominations for two FERC vacancies, Republican Mark Christie and Democrat Allison Clements, have not cleared the Senate and Energy Natural Resources Committee yet.

If they are approved, the Republicans would hold a 3-2 majority, at least as long as Republican Neil Chatterjee, whose term expires in June, remains. Trump replaced Chatterjee as chairman last week with Republican James Danly. (See related story, Trump Demotes Chatterjee; Names Danly FERC Chair.)

“Danly could take his short tenure as chairman and move on to the next thing. If he doesn’t and goes back to being a commissioner, I think it’s intriguing to what extent does Chatterjee become the [Justice] Anthony Kennedy or the [Chief Justice] John Roberts of FERC,” she said, referring to two Republicans who have been swing votes on the Supreme Court. “In terms of carbon pricing, offshore wind, transmission interconnections … he is clearly more aligned with Glick.”

Carbon Pricing

On Oct. 15, Chatterjee joined with Glick in supporting a proposed policy statement inviting states to introduce carbon pricing in wholesale electricity markets to address climate change. (See FERC: Send Us Your Carbon Pricing Plans.)

Tezak said carbon pricing is not necessarily a partisan issue. “We’re seeing the carbon price in wholesale tariffs offered as a bridge,” she said. “There’s a common interest there. I hope that with something like carbon pricing, we can look at it more like SO2 and NOx emissions. That’s part of the conversation we’re looking at now. Carbon has an opportunity to integrate. The conversation is … at least broadening a little bit. If FERC gets a Democratic majority, does the MOPR [minimum offer price rule] even survive?”

Some have suggested Biden could seek to add carbon pricing to a budget reconciliation bill, which would be exempt from filibuster and require only a simple majority vote in the Senate.

Herman said it would be “an aggressive” move. “But there seems to be some level of growing support that a carbon tax might provide some certainty to bolster investment as opposed to scaring people away from investment,” he added.

Infrastructure, Natural Gas

George Bilicic, vice chairman of investment banking and global head of power, energy and infrastructure for Lazard, told the EEI panel that he sees natural gas-fired generation remaining “highly relevant” for the foreseeable future as a supplement to renewables and storage.

George Bilicic, Lazard | Edison Electric Institute

Panel moderator Richard McMahon, EEI’s senior vice president for energy supply and finance, noted that EEI’s Natural Gas Sustainability Initiative with the Natural Gas Association is attempting to reduce mid- and upstream methane emissions. “Hopefully, that will go a long way to satisfying the desire of the [environmental, social and corporate governance] folks and investors.”

Bilicic also said that utilities and other infrastructure spending could find its way into an economic relief package because of their multiplier effects across the economy. “A dollar spent in utilities generates tremendous economic growth,” he said. “To get to the best renewable resources, we’re going to need a lot of investment in transmission and … help on the permitting front.”

“Infrastructure might creep into the top three or four priorities” with a Republican-controlled Senate, Joe Mikrut, a partner with Capitol Tax Partners, said during the Norton Rose Fulbright session.

Democratic political strategist Donna Brazile | Edison Electric Institute

Infrastructure spending was also seen as possible for bipartisan spending during the Trump administration. But it never happened.

Partisan gridlock is a major reason why Americans’ trust in government has diminished since the 1960s, Democratic political strategist Donna Brazile told the EEI conference.

“I hope [those just elected] understand that [voters] want us to get back to work,” she said. “They want us to focus on them and their priorities and not go back to the politics as usual and this whole thing of revenge: ‘I lost so now I’m going to make it hard for you. I won so I don’t have to work with you.’ I’m sick of that.”

November 10, 2020

Vote on PJM Black Start Compensation Deferred

PJM deferred a vote until December on packages dealing with the contentious black start unit testing and compensation issue as stakeholders also delayed a vote on a proposed change of the issue charge approved earlier this year.

Paul Sotkiewicz of E-Cube Policy Associates made a motion for stakeholders to adopt proposed amendments to the black start unit issue charge during its first read at last week’s Operating Committee meeting. The black start issue has been lingering for months, leading to heated discussions. (See Gen Owners Balk at Change to PJM Black Start Rates.)

Tasley, a single-unit 33 MW industrial gas turbine that began commercial operation in 1972 in Tasley, Va., is a black start-capable unit. | *Calpine*

The proposed issue charge language said, “Current black start units receiving the capital cost recovery rate (Schedule 6A) and units already awarded in recent black start [requests for proposals] will continue with the commitment period and capital recovery factor (CRF) rates as documented in the current Open Access Transmission Tariff.”

Sotkiewicz said the black start problem statement passed at the May OC meeting has identical language in a footnote added to the black start CRF section indicating that PJM will not retrospectively make changes in the CRF and compensation. (See “Black Start Issue Charge Endorsed,” PJM Operating Committee Briefs: May 14, 2020.) Sotkiewicz said the idea was to have the black start issue charge reflect the language in the problem statement.

“We would like to make this change to the issue charge and bring this up for a vote at the committee so that we can move forward with a rational discussion of black start,” Sotkiewicz said.

PJM black start — Sharon Midgley, Exelon | © *RTO Insider*

The issue over the language emerged when stakeholders discovered the issue statement, which is officially voted on for endorsement as codified in Manual 34, did not include the footnote, leaving the application of CRF rates up to interpretation in the proposed black start packages.

The Independent Market Monitor’s package calls for updated CRF rates to apply to new and existing black start units. Updated commitment periods would also apply to new and existing black start units.

Sharon Midgley of Exelon seconded Sotkiewicz’s motion to adopt the updated issue charge language. Midgley said black start service is critical to reliability, and proposals retroactively changing the outcomes of an RFP process that has already been conducted “should not be entertained by this committee.”

Midgley said the updated issue charge was meant to codify what Exelon believed was the initial intent of the black start work effort when it was endorsed in May.

Monitor Joe Bowring said the issue charge language presented by Sotkiewicz read as a proposed solution and not an issue. Bowring questioned whether the language fit under the definition of an issue charge and if it was appropriate to retroactively change an issue charge.

PJM’s Darlene Phillips, chair of the OC, said she did not consider the updated issue charge language to be a solution and that it deals with the scope of the issue charge. Phillips said stakeholders can make a motion to modify an issue charge and believed the status of the black start issue is “in good standing in accordance with the process” to officially update it.

Stakeholder Debate

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said it seemed like the updated issue charge was “curtailing discussion” among stakeholders regarding the proposed black start packages. Poulos said a first read would be helpful so that he could discuss the implication of the language with the advocates instead of passing it on the same way.

“If Supply, which has the majority vote, decides that they’re going to ram this thing through, it’s hard to want to do a further discussion on this,” Poulos said.

Sotkiewicz said he took exception with Poulos’s characterization that the issue charge was being “rammed through” the stakeholder process. He said the problem statement was very clear that updated CRF rates would only apply to new black start units.

Sotkiewicz said the issue charge language was not taking off the table the idea that CRFs can be adjusted on a forward-looking basis in the black start packages. But he said that because the black start RFP has already been conducted and units are already in service, to make retroactive changes “flies in the face” of what is conducted in other PJM markets where changes have always been prospective and not retrospective.

“Now we have a reputational problem, and who’s going to want to put their resources forward in the next black start RFP?” Sotkiewicz said. “It’s only going to increase cost for load.”

David Mabry of the PJM Industrial Customer Coalition made a motion to defer the vote on the updated issue charge until December. Mabry said there have been some discussions with stakeholders in attempting to understand the issues from both sides, and by deferring the issue charge for a month could allow time to craft a compromise.

“Clearly there are two sides at this point, and both had a different understanding of what the scope of the initiative was,” Mabry said.

Phillips told stakeholders that a vote deferral on the issue charge would effectively push back the overall voting on the black start packages until the December OC meeting.

“We don’t want to vote on packages when the issue charge is still up in the air,” Phillips said.

Stakeholders ultimately voted to defer consideration of the amended issue charge until the December OC meeting, passing the measure with 58% in favor, including 132 “yes” votes.

Sotkiewicz said he has yet to have a stakeholder identify a retroactive action in PJM markets similar to what is being discussed with black start CRF.

“I think this sets a really bad precedent overall for PJM in terms of governance and people’s interests,” Sotkiewicz said.

November 10, 2020

PJM Moves Closer to Endorsing SATA

Stakeholders received a look at the design components of PJM’s proposal to develop rules for how storage should be considered in the Regional Transmission Expansion Plan (RTEP) process.

During last week’s Planning Committee meeting, PJM’s Michele Greening discussed work conducted on storage as transmission assets (SATA). Stakeholders approved an issue charge at the PC meeting May 12, and they have been working on the issue at special sessions since June. (See SATA Issue Charge Moves Forward in PJM.)

Greening said the Phase 1 effort of the issue explored existing transmission planning criteria, including the performance measurement methodology and where there were gaps in planning. She said work at the special sessions developed additional criteria to be used in evaluating SATA to address reliability, market efficiency, operational performance and public policy.

PJM also examined reliability aspects of SATA and establishing clear and transparent criteria, Greening said, while receiving education on current business rules, regulatory background and FERC precedent on the issue. It also looked at the development of criteria for modeling SATA and evaluating proposals in relation to traditional transmission projects.

Greening said the RTO stayed away from examining SATA participating in the energy or ancillary services markets. She said those issues would be reserved for a Phase 2 process.

“We wanted to make sure that we have the necessary criteria in place that would allow stakeholders some transparency into how PJM would evaluate and incorporate such assets into the RTEP process,” Greening said.

In nonbinding poll results, Greening said 77% of respondents indicated they would support the PJM package proposal “to ensure existing planning rules provide sufficient clarity regarding how SATA should be evaluated and incorporated into the RTEP process.”

An additional 72% of poll respondents said they would support continued discussions following Phase 1 to explore SATA market participation and the resulting process and tool changes.

Jeff Goldberg of PJM presented the first read of the RTO’s package, saying it would establish requirements to ensure implementation maintains system reliability consistent with NERC standards. The SATA evaluation approach also seeks to ensure there are no adverse impacts to the generation interconnection queue, Goldberg said.

Nick Dumitriu of PJM discussed the market efficiency aspects of the package, saying the RTO does not recommend any SATA-specific rule changes. Dumitriu said an evaluation of PJM rules found that the current tools and analysis techniques are already sufficient to study and assess SATA.

Greening addressed the next steps in the SATA process, including a vote on the package at the Dec. 1 PC meeting and a first read at the January Markets and Reliability Committee meeting with the supporting Operating Agreement language. After endorsement at the February MRC meeting, Greening said, the package will be submitted to FERC for approval.

PJM’s intention is to wait to see FERC’s response to the filing prior to drafting manual language revisions, Greening said.

Stakeholder Responses

Independent Market Monitor Joe Bowring said he questioned the logic of SATA and noted that discussions have assumed it to be a good idea, with talks focusing on implementation rather than if it is wise. It seemed as if the issue was “being brushed over at the moment,” he said.

“We don’t think that storage should ever be considered to be a transmission asset,” Bowring said. “It’s already a market asset.”

Greening said the PJM package specifically limits SATA to being transmission and cannot be listed as a market asset if it’s brought online for transmission purposes.

Aaron Berner of PJM noted that initial discussions held in the special sessions indicated support to move ahead on the issue, with the RTO receiving no “pushback” from stakeholders to abandon the dialogue.

Carl Johnson of the PJM Public Power Coalition pointed out one of PJM’s design components in the package regarding cost elements in the reliability category: “SATA will not participate in its markets but will use the appropriate settlement mechanisms to settle the charging and discharging functions to offset the rate of recovery.”

Johnson asked how PJM envisions the rate of recovery offset occurring. He said if a SATA is charging and discharging, it could potentially be making a profit on that action.

Berner said an entity proposing use of SATA would need to demonstrate they have established mechanisms that the net positive benefits of the energy flow would flow back to an offset mechanism to achieve the rate recovery. Berner said PJM is not anticipating making changes to how the settlements occur.

Johnson said PJM may want to establish a procedure in the Tariff and make it uniform rather than having it be a “one-off, untraceable rate filing” with FERC.

“These things are very hard to track on a uniform basis,” Johnson said. “There really isn’t any way to make sure these things are being properly accounted for across the system.”

Sharon Segner, vice president of LS Power, asked at what point stakeholders would be able to see the Operating Agreement language for the PJM package.

Greening said the language would be presented at the January MRC meeting, provided the PC supports moving forward with the PJM package.

Sharon Segner, LS Power | © *RTO Insider*

Segner said the “guts” of a solution and issue is in the OA language, with stakeholder discussions and support difficult before seeing what is crafted. Segner said the process is “optimized” when the OA and governing language is seen at the lowest possible committees so that discussions can start early.

“At the end of the day, the words do matter, and they especially matter when it comes to Operating Agreement language,” Segner said. “It sounds a little bit premature.”

November 10, 2020February 18, 2025

Heat Waves Spur Record EIM Benefits

Benefits for participants in CAISO’s Western Energy Imbalance Market surged past $119 million in the third quarter of 2020 — a record amount driven by savings during the heat waves of August and September, the ISO told the EIM’s Governing Body on Wednesday.

“We saw a higher level of benefits in this quarter than we normally have seen because of those conditions and the resultant high prices, especially in the Southwest,” CAISO COO Mark Rothleder said.

EIM benefits topped a record high of $119 million in the third quarter. | CAISO

The benefits were mainly from savings; utilities paid less for electricity in EIM transfers than they would have otherwise paid during times of tight supply and soaring prices, the ISO reported.

Load-serving entities in the Southwest and California were pressed to meet high demand during the heat events in mid-August and over Labor Day weekend. CAISO ordered rolling blackouts for two days in August and barely avoided additional outages in September. (See CAISO Avoids Blackouts amid Brutal Heat, Fires.)

More than half the third-quarter benefits, $66 million, came in August.

The Western EIM has 11 active participants and 11 pending participants. | CAISO

Of the 11 active EIM participants, CAISO said it saved the most, reaping $23.7 million in benefits. Arizona Public Service was able to avoid $22.6 million in additional costs by procuring electricity through the EIM, and the Salt River Project, also in Arizona, saw $17.4 million in savings, CAISO reported.

“The quarterly benefits have grown over time as a result of the participation of new balancing authority areas in the market, which results in additional benefits for both the individual BAAs but also compounds the benefits to adjacent BAAs by enabling further transfers,” CAISO said in its third-quarter report.

The savings bring the EIM’s total benefits to $1.1 billion since it started operating in November 2014.

Current EIM entities also include NV Energy, PacifiCorp and Seattle City Light. Eleven more entities are scheduled to join in 2021 and 2022, including the Bonneville Power Administration, the Los Angeles Department of Power and Water, and Public Service Company of New Mexico.

November 10, 2020

NEPOOL Participants Committee Briefs: Nov. 5, 2020

ISO-NE CEO Gordon van Welie last week shared the RTO’s “vision for the future” with the NEPOOL Participants Committee, which he presented as “our long-term intent” that “guides the formulation of our strategic goals.”

The RTO included a forward-looking statement that van Welie said seeks “to harness the power of competition and advanced technologies to reliably plan and operate the grid as the region transitions to clean energy.”

Publication of ISO-NE’s vision comes on the heels of recent calls for reform by the New England States Committee on Electricity (NESCOE), which wants increased transparency from the RTO and a more prominent role in the decision-making process. (See States Demand ‘Central Role’ in ISO-NE Market Design.)

The RTO’s five “strategic goals” are responsive market designs; progress and innovation; operational excellence; stakeholder engagement; and attracting, developing and retaining talent.

When it comes to the first goal, van Welie said ISO-NE wants to improve the current market structure and continue to evolve and reposition its design to accommodate the states’ transition to high levels of renewable and distributed resources. The RTO also wants to maintain a robust fleet of balancing resources and preserve the market’s ability to attract new entry.

The progress and innovation goal includes a push to evolve capabilities to support the grid as the region transitions to clean energy. It also includes improving power system and market modeling and supporting investments in transmission infrastructure to enable renewable energy, as well as a call for integrating distributed energy resources and providing data and information-based services.

According to van Welie, stakeholder engagement requires collaboratively understanding and anticipating needs, thought leadership through high-quality analysis and communication, and nurturing productive relationships with FERC, the states and market participants.

Amended DDBT Passes

The committee voted to support an amended proposal from ISO-NE to recalculate the dynamic delist bid threshold (DDBT) for Forward Capacity Auction 16.

Calpine, NESCOE and Vistra’s Dynegy offered a combined amendment to the RTO’s proposal to lower the DDBT upper bound to 75% of the net cost of new entry (CONE) and set the DDBT at the RTO’s estimated clearing price plus a margin adder calculated using 75% of net CONE.

NESCOE said it remains concerned that the ISO-NE proposal does not balance design objectives and can result in the DDBT being set too high when capacity prices increase. The organization added that the risk of the DDBT being higher, especially as it approaches net CONE, could have cost implications for consumers.

Calpine and Dynegy said the RTO’s design interferes with competitive price formation, adds significant administrative burden and risks to existing suppliers, and creates an unnecessary barrier to market exit. The amendment allows a modest margin adder to low prices when supply curves are typically flat, with the adder diminishing as expected prices increase, which preserves at least some of the benefit of the DDBT.

Previously, NESCOE presented two amendments at the Markets Committee meeting in October. One would have lowered the upper bound to 85% of net CONE and add an upper bound set at 125% of the prior auction clearing price. The second would have limited the maximum rate of change in the DDBT from auction to auction to 30% of net CONE.

Calpine and Dynegy also presented amendments at the MC that would set the DDBT at ISO-NE’s estimated clearing price plus a scaled margin that starts 75 cents above the RTO’s estimated cost of $2/MWh, decreasing to $0/MWh at net CONE, or, as an alternative, from a fixed bid to a cap price.

At the RTO’s request, the committee considered, but did not approve, the unamended DDBT proposal. The vote failed to pass with none in favor and noted abstentions.

Pathways Process Continues

Frank Felder and Frank Wolak each made presentations on “Potential Pathways to the Future Grid,” with Felder returning for “Focus on Energy Only Market and Alternative Resource Adequacy Constructs” and Wolak discussing “Long-Term Resource Adequacy with Significant Intermittent Renewables.”

Felder, a professor at Rutgers University and an expert in energy policy and electricity markets, told the committee that whether the minimum offer price rule (MOPR) applies to a forward clean energy market or integrated clean capacity market determines the potential for “double payment” for clean energy and price suppression. He said an energy-only market addresses the double payment issue and maintains a regional market, even more so with added carbon pricing. Additional changes to the ancillary services markets may be needed, however, to ensure sufficient balancing resources.

According to Felder, some alternative resource adequacy constructs could address the MOPR issue. He added that anticipated replacement of large generating resources throughout New England with new capacity with very different operating characteristics suggests the region will need to strongly consider changes to transmission planning and cost allocation to avoid costly investment decisions.

Wolak, a Stanford University economics professor and director of its program on energy and sustainable development, said that in a low-carbon world, the electricity supply sector would consist of more than 50% intermittent renewables.

Wolak said the growing share of renewables will also require investments in both grid-scale and distributed storage and active demand-side participation by customers with interval meters using dynamic retail electricity prices, in addition to automated distribution network monitoring and on-site load-shifting technologies. He added that market design should support business models that lead to efficient investments in those technologies.

Winter is Coming

In his report to the committee, ISO-NE COO Vamsi Chadalavada said that the energy market’s value was $193 million in October, down $14 million from revised September figures and $9 million from October 2019.

Chadalavada also delivered the winter outlook, including a 40% probability of above-normal temperatures for New England from December through February. There is also an equal chance for above- or below-average precipitation in the region.

In terms of winter capacity, Chadalavada said ISO-NE is projecting the lowest 50/50 operable capacity margin of 2,574 MW and a 90/10 capacity margin of 1,232 MW for the week beginning Jan. 2, 2021. The capacity outlook will be adjusted if there are extended periods of cold weather.

The 50/50 winter peak demand forecast of 20,166 MW is 310 MW lower than the 2019/20 forecast, while the 90/10 winter peak demand forecast of 20,806 MW is down by 367 MW.

Chadalavada added that unknown societal factors would likely continue to impact demand throughout the season. He said forecasting staff are continuously evaluating load trends and frequently retraining forecasting models.

The RTO also recently hosted a Generator Winter Readiness Seminar and distributed a survey to all regional generating resources. It said survey results will enhance its understanding of winter preparations across the region, temperature-specific limitations on real-time capabilities and specific protocols followed during extreme cold-weather events.

ISO-NE will continue to perform a weekly 21-day look-ahead of forecasted conditions, which provides an opportunity for generators to act in advance of an energy emergency. In addition to the Winter Generator Readiness Survey, the annual natural gas critical infrastructure survey process has been incorporated into Operating Procedure 21 before winter.

Other Action

The committee also acted on consent agenda items.

Without objection, the PC removed sunset of the forward reserve market (FRM) from the consent agenda following FERC’s Oct. 30 order rejecting the Energy Security Improvements (ESI) proposal on which the FRM sunset was contingent. (See FERC Rejects ESI Proposal from ISO-NE.)

The remainder of the consent agenda was approved with two abstentions and two oppositions because of concerns about the installed capacity requirement (ICR) and related values for Forward Capacity Auction 12’s three annual reconfiguration auctions (ARAs) set for 2021.

The PC approved net ICRs of 32,925 MW for ARA 3, 32,765 MW for ARA 2 and 32,980 MW for ARA 1. The HQICC value is 958 MW for ARA 3, with the amount rising to 969 MW for ARA 2 and down to 941 MW for ARA 1.

November 10, 2020February 13, 2025

NARUC Session Discusses EV Rates, Customer Views

Research scientist Andy Satchwell of Lawrence Berkeley National Lab had a caveat for the audience at the beginning of his presentation last week on electric vehicle rate designs and utility programs.

“The questions about what rate design and utility programs will drive EV adoption are unanswered,” he told the National Association of Regulatory Utility Commissioners’ Annual Meeting and Education Conference. But as a researcher, this does not make him unhappy. “This is an emerging and dynamic — and therefore really exciting — topic,” he enthused.

Satchwell was joined by Patty Durand, CEO of the Smart Energy Consumer Collaborative, which has been asking consumers the same questions annually for more than seven years. “We have probably the longest longitudinal study of residential consumers in the nation,” she said.

Clockwise from top left: Andy Satchwell, Lawrence Berkeley National Lab; moderator Zeryai Hagos, New York Department of Public Service; and Patty Durand, Smart Energy Consumer Collaborative | NARUC

In a second panel, Chris Budzynski, director of utility policy for Exelon; Lydia Krefta, Pacific Gas and Electric’s manager of regulatory, compliance and pilots for clean energy transportation; and Kelli Newman, senior marketing analyst for Georgia Power, discussed their utilities’ EV programs.

Durand sa id her group uses customer segmentation as the “backbone” of its research, breaking residential consumers into four groups. The “most engaged” segments are the Green Innovators, who care about sustainability, and the Tech Savvy Proteges, who embrace the “cool” factor of new technology, Durand said.

Next comes the Movable Middle: “They care a little bit about sustainability; they care a little bit about technology. They’re probably not going to do anything unless there’s an incentive, a program, marketing — some kind of thing that hooks them and gets them engaged. They will engage with the right program and messaging.”

Last, Durand said, are the Energy Indifferent. “They’re probably not going to engage. They generally are not interested in anything to do with energy. … We recommend just leaving them alone and focusing on the majority of consumers who do care or would engage.”

Clockwise from top left: Kelli Newman, Georgia Power; moderator Jamie Barber, Georgia Public Service Commission; Lydia Krefta, Pacific Gas and Electric; and Chris Budzynski, Exelon | NARUC

While only 1% of consumers currently own an EV, about 16% report they are very interested in acquiring one, and 29% are somewhat interested, Durand said. The numbers are higher for Green Innovators (29% very interested, 33% somewhat interested) and Tech Savvy Proteges (25/37%).

The segments are reflected in consumers’ willingness to pay more for an EV: A 10% increase in cost reduces interest among Green Innovators by 4 percentage points — from 51% to 47%. Interest from Tech-savvy Proteges also drops by 4 percentage points, from 40% to 37%. Interest among the Movable Middle drops 3 points from 27% to 24%.

EV Rate Design

Awareness of EV-specific rates is “extremely low” between 5 and 6% of the whole population, with even 91% of Green Innovators unaware, Durand said.

“We asked consumers, ‘If you have an EV, are you on an [EV] rate plan or would you sign up for a rate plan?’ And most consumers either didn’t answer the question or said ‘no,’” she said. “So, these are really terrible numbers for those who want EVs to be more common [and] want beneficial electrification to include transportation.”

She added: “It’s an easy-to-overcome barrier. Education is one of the easiest things to do. But this does show a problem with residential consumer awareness.”

Satchwell said some states have adopted “advanced” rate designs, including the unbundling of service costs (e.g., energy, capacity and ancillary services); hourly or sub-hourly marginal prices (vs. average utility costs); and include feeder-level or more granular marginal prices (vs. rates applied regardless of grid-specific locations).

The major debate in designing EV rates is whether they should be based on demand charges or time-of-use (TOU) rates, he said. “Demand charges can impact public charging by penalizing fast chargers, but they may, arguably, better match cost causation depending on how they’re designed,” he said. “EV supporters believe time-of-use rates are better for customer economics and better reflect that hourly marginal value.”

There are also multiple flavors of TOU rates, with some utilities offering multiple rate periods with mid-peaks and some offering super off-peak periods with significant discounts. The latter “sometimes have been referred to as matinee pricing — the same way that theaters … used to try and fill seats during the middle of the day with a huge discount,” he said.

Utilities have multiple flavors of time-of-use rates, with some offering super off-peak periods or “matinee” pricing. | Lawrence Berkeley National Lab

Some utilities offer flat “all-you-can-charge” monthly fees, such as Austin Energy, which charges $30/month but prohibits charging during peak hours.

There are also differences in metering requirements for home EV chargers. For example, Georgia Power’s whole home rate applies to all household electricity usage, which eliminates the need for additional equipment or changes to data collection and billing systems. But it can be a disincentive to EV charging if the rate is tiered with inclining block rates.

In contrast, Austin Energy’s EV-only rate requires a separate sub-meter and dedicated circuit, adding costs, but can allow clearer cost-based price signals.

Rates for commercial customers — such as fleet owners and public charging stations — are more likely to include locational and temporal specificity. San Diego Gas & Electric’s Power Your Drive program charges customers based on the CAISO day-ahead market price, with an adder for the top 200 distribution feeder load hours.

San Diego Gas & Electric’s Power Your Drive program for commercial customers is based on the CAISO day-ahead market price, with an adder for top distribution feeders. | San Diego Gas & Electric

PG&E’s Business EV rate, which took effect Oct. 1, replaced demand charges with a monthly subscription charge, which the company said lowers charging costs by 40% on average. The subscription fee, based on whether consumption is above or below 100 kW, is combined with TOU rates.

PG&E also is seeking regulators’ approval for a pilot project using dynamic hourly rates for commercial customers, also based on CAISO day-ahead prices.

The company powers more than 303,000 EVs in its service territory and offers $800 rebates. EVs’ share of new vehicle sales in the territory peaked at 14% in 2018 before the federal Tesla tax rebate expired. It dropped to 12% in the first quarter of 2020 before falling to 6% in the second, when the coronavirus pandemic hit the state.

In Georgia, EVs’ share of new car sales peaked at 3% in 2015, when the state offered a $5,000 tax credit. After the credit expired, the share dropped to less than 0.5% but has neared 1.5% since mid-2019. “We’ve now started to see more organic growth, and we attribute this to the affordability of some Tesla models now,” Newman said. “People who got familiar and comfortable with EV driving back in 2015 are now starting to buy electric vehicles again.”

Georgia Power’s rates range from 1 cent/kWh for super off-peak charging (11 p.m.-7 a.m.), 7 cents for off-peak (which varies by month and weekdays vs. weekends) and 20 cents for on-peak (2-7 p.m. June through September). It said drivers that spend $170/month on gasoline would pay only $19/month in charging fees if they limited their charging to the super off-peak period.

Satchwell discussed how customers respond to EV rates, based on a review of 11 evaluation reports of offerings published between 2013 and 2020, most of them short-term pilots. Most of the pilots had at least a 2:1 peak-to-off-peak price ratio, with a small number having a ratio of 4:1 or greater. Not surprisingly, higher peak-to-off-peak ratios result in more off-peak charging, he said.

PVs and EVs

But customers who owned a PV system were significantly less responsive to prices than their non-PV counterparts, according to a review of an SDG&E residential EV rate pilot. “This maybe suggests that PV customers place a higher value on [selling PV electricity back to the grid] than the increased electric costs for EV charging,” he said. “Certainly, there’s more here to unpack.”

Durand said she was shocked by her group’s finding that 50% of those with rooftop solar also own an EV.

“The interest was very high,” she said. “If as a stakeholder, you’re interested in more EV purchasing or finding customers interested in EVs, pursuing the consumers who have solar … or having policies that help consumers get solar, is a way to accelerate the transition to EV ownership.”

Government, Utility Incentives

Satchwell said that although some utilities encourage adoption of EVs through small rebates in partnerships with car dealers, federal and state tax credits have been the primary financial incentive to reduce that upfront cost of EVs to customers.

Satchwell’s review of 30 proceedings in 19 states found that about 85% of capitalized utility costs are for EV charging infrastructure on the customer-side of the meter, which addresses “range anxiety” and allows customers to participate in retail and wholesale market opportunities to sell power back to the grid, where available.

Some utilities’ investments have been to modernize their distribution grid, which can provide benefits for all customers, not just EV owners, he added.

Georgia Power is offering business customers $500 rebates on Level 2 chargers on 240-V circuits for workplace and customer charging. It is offering residential customers $250 rebates on Level 2 chargers and offering builders $100 rebates for installing 240-V garage outlets in EV-ready homes.

Car Dealers’ Lackluster Support

Durand said car dealers could encourage EV sales by pointing out that while their purchase price is higher than gasoline vehicles, they are cheaper over the long-term due to lower maintenance and fuel costs.

Dealers “don’t know enough about [EVs]; I usually come in knowing more than they do,” she said. “They are underwhelming in their endorsement of an EV. The total cost of ownership (TCO) is something that consumers don’t understand. Utilities could work with dealers and have TCO stickers on the cars so that customers can browse the lot and see: ‘Oh, this costs a little more upfront but then by year two I’m really saving money. Or the stickers could include state and federal incentives, which consumers don’t understand or know much about.”

November 10, 2020

PJM MIC Briefs: Nov. 5, 2020

PJM stakeholders last week endorsed the RTO’s package of updates to real-time value (RTV) market rules that call for additional penalties for generation operators that abuse the rules.

The RTO’s package was endorsed with 73% support at last week’s Market Implementation Committee meeting. In a nonbinding poll, the package received 55% support over maintaining the status quo.

Laura Walter, senior lead economist for PJM, provided an update on the work completed during the MIC’s special sessions on the rules and reviewed the proposed packages from the solutions matrix.

The special sessions have been taking place since January, after stakeholders endorsed an issue charge at the Markets and Reliability Committee’s meeting in December. (See “Real-time Values,” PJM MRC Brief s : Dec. 19, 2019.) The problem statement said observations indicated RTVs were being used to consistently override unit-specific parameter limits or parameter-limited exceptions.

The original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources could not meet their unit-specific parameter limits or exceptions, Walter said. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.

The PJM package would require that market participants repeatedly failing to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. A market participant would be required to enter a forced outage ticket into PJM’s Generator Availability Data System (eGADS) for the period of increased notification, start-up time and/or minimum downtime.

For the timeline of an RTV submittal, Walter said, the package would require that the requested time period not exceed one market day. She said that when an RTV is requested, it would be available for that one day; then the entire schedule would revert to the previous day’s values.

The package also calls for adding RTVs to the Tariff. Currently, RTVs are mentioned only in the manual, Walter said.

In a nonbinding poll conducted in August, 55% of stakeholders said they supported the PJM package, and 10% gave support for a package by the Independent Market Monitor, while 71% said they were satisfied with the status quo.

Details of the Monitor’s package were also presented. In a vote held after the PJM package, the Monitor’s only garnered 8% support.

The Monitor’s proposal included removing minimum run time from the list of eligible parameters with RTV submissions. It also said units that choose to run longer could self-schedule beyond the minimum run time, with PJM operator notification.

The proposal also would have aimed to prevent withholding by using longer minimum run times. Any penalties collected would have been allocated to daily real-time load.

The PJM package will now move on to the MRC in December for a first read.

Manual 11 Revisions Endorsed

Stakeholders unanimously endorsed updates to Manual 11 designed to increase transparency and conform to the current PJM process for calculating LMPs as part of the problem statement regarding five-minute dispatch and pricing.

Vijay Shah, senior engineer in real-time market operations for PJM, reviewed the proposed updates to Manual 11: Energy & Ancillary Services Market Operations. The changes include an added reference to the day-ahead and real-time sections in section 2.2: Definition of Locational Marginal Price and change “LMP verification” to “price verification” throughout section 2.10: Verification Procedure, as verification includes review of real-time and ancillary service prices.

In section 2.11: Price-Bounding Violations, language was updated to state that all interval prices will be posted, Shah said, and any intervals that do not pass an output consistency check will be indicated on PJM’s website. The section was not included in the first read of the changes at the MIC meeting in October.

Shah said the changes are not related to the five-minute dispatch and pricing short-term changes that were filed with FERC in July. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)

Public Distribution Microgrids

Natalie Tacka, an engineer in PJM’s applied innovation department, reviewed a proposal and provided a first read of updates to Manual 11: Energy & Ancillary Services Market Operations and Manual 18: PJM Capacity Market regarding business rules for public distribution microgrids.

Tacka said work on the issue first began last year in the former Distributed Energy Resources Subcommittee (DERS) and has continued into the new DER and Inverter-Based Resources Subcommittee (DIRS).

A microgrid is defined as a system of generating facilities and load that can operate both while connected to and off the main grid, Tacka said. PJM is looking to define a public distribution microgrid as a microgrid that contains a PJM generating facility that can generate while connected to and “islanded” from the broader grid and uses public utility distribution wires.

PJM’s public distribution microgrid concept | *PJM*

Tacka said a public distribution microgrid would not include any NERC bulk electric or transmission facilities. The electric distribution company will determine if the public distribution microgrid is wholesale or retail when islanded.

The Manual 11 language includes provisions for reflecting islanded conditions in a resource’s availability for energy and ancillary services, Tacka said, while Manual 18 language adds clarification for performance assessment interval treatment of public distribution microgrids serving as generation capacity resources.

The committee will be asked to endorse the manual changes at the MIC meeting in December.

UTC Uplift Changes

Ray Fernandez, manager of market settlements development for PJM, provided a first read of updates to Manual 28: Operating Agreement Accounting to conform with changes ordered by FERC regarding uplift charges on up-to-congestion (UTC) transactions (EL14-37).

In its order issued in July, FERC determined that PJM’s current uplift allocation rules are unjust, unreasonable and unduly preferential because they do not allocate uplift to UTCs. (See FERC Orders Uplift Charges on PJM UTCs.)

PJM was directed by the commission to submit a replacement rate that revises the RTO’s current uplift allocation rules to allocate uplift to UTCs “in a manner that treats a UTC, for uplift allocation purposes, as if the UTC were equivalent to a [decrement bid] at the sink point of the UTC.”

Fernandez said UTCs will now be allocated in both real-time and day-ahead uplift.

PJM is seeking stakeholder endorsement of the manual changes at the December MIC meeting.

November 10, 2020

PJM Operating Committee Briefs: Nov. 6, 2020

PJM stakeholders last week unanimously endorsed proposed changes to the 2021 day-ahead scheduling reserve (DASR) requirement that saw small changes from last year.

David Kimmel, PJM senior engineer of performance compliance, reviewed the preliminary proposed changes at last week’s Operating Committee meeting, along with updates to Manual 13.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year averages of both the under-forecasted load forecast error (LFE) and eDART forced outages.

Kimmel said the final 2021 DASR requirement is 4.74%, slightly lower than the 2020 requirement of 5.07%. He said the number comes from the LFE component of 2.16%, which is up 0.01% from last year, and the forced outage component of 2.59%, down 0.33% from last year.

The final 2021 DASR value will be incorporated into Manual 13 changes and be implemented in January.

Winter Weekly Reserve Target

The committee also unanimously endorsed changes to the 2020/21 winter weekly reserve target, which changed slightly from last year’s.

2020/21 winter weekly reserve targets | *PJM*

Patricio Rocha Garrido of PJM reviewed the results of the winter weekly reserve target analysis. The targets for December, January and February are 23%, 27% and 23%, respectively, compared to 22%, 28% and 24% last year.

“These increases and decreases are based on the load uncertainty we have in our most recent reserve requirement study case,” Rocha Garrido said. “However, the values are very close, so it doesn’t make much of an impact.”

Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling and cover against uncertainties by ensuring that the loss-of-load expectation (LOLE) for winter is “practically zero,” Rocha Garrido said. For the entire year, PJM sets the LOLE at one occurrence in 10 years.

The winter weekly reserve target for each month is the highest weekly reserve percentage, Rocha Garrido said, rounded up to the next integer value.

Manual Endorsements

Stakeholders also unanimously endorsed several minor manual changes.

Maria Baptiste of PJM reviewed updates to Manual 3A: Energy Management System Model Updates and Quality Assurance. Baptiste said the changes include correcting grammatical mistakes and updating references to the behind-the-meter generation rules that took effect in September 2019. (See “Non-retail BTM Generation Rules Endorsed,” PJM MRC/MC Briefs: Sept. 2 6, 2019.)
Lagy Mathew of PJM reviewed updates to Manual 3: Transmission Operations. Mathew said the changes featured minor clarifications, including defining extra-high voltage lines as those equal to or greater than 345 kV.
Kevin Hatch of PJM reviewed updates to Manual 12: Balancing Operations to address changes from the Market Implementation Committee’s special sessions on five-minute pricing and dispatch. Hatch said the RTO has been working with the Independent Market Monitor to identify sections of Manual 12 to be updated and to improve transparency on the dispatch process. Hatch said the changes include updated terminology for “day-ahead market” instead of the outdated “two-pass system.”

November 10, 2020

Texas PUC Approves ERCOT Board Members

Texas regulators last week approved the election of Michigan Public Service Commissioner Sally Talberg and two others to three-year terms on ERCOT’s Board of Directors.

“I’m not trying to pick favorites, but I’m so excited to have Sally Talberg back,” Texas Public Utility Commission Chair DeAnn Walker said during the commission’s open meeting Thursday. “I’m glad to have her back in the ERCOT group.”

Walker said that Talberg approached her recently and asked her advice about joining the ERCOT board.

“I said absolutely,” Walker said. “I’m glad to have her back in the ERCOT group.”

Talberg advised the PUC from 2000 to 2004 during Texas’ transition to retail competition. Pat Wood III chaired the PUC at the time and would go on to also chair FERC under President George W. Bush. Judy Walsh, due to cycle off ERCOT’s board after this year, also served on the commission then.

While working on a master’s degree in public affairs from the University of Texas at Austin, Talberg also worked at the nearby Lower Colorado River Authority.

Talberg told RTO Insider she had expressed her interest in joining the ERCOT board some time ago, “initially thinking it would be some far-off prospect after serving on the MPSC.”

“But these spots were opening, so it happened earlier than I anticipated,” she said.

Talberg was first appointed to the PSC in 2013, serving as chairman from January 2016 to July 2020. Her term expires next July, but she has said she will step down from the commission once her appointment to the ERCOT board is official. (See “Michigan PSC’s Talberg Among Director Nominees,” ERCOT Board of Directors Briefs: June 9, 2020.)

The PUC also approved the elections of retired ISO-NE General Counsel Raymond Hepper and incumbent Director Terry Bulger to the ERCOT board. All three will serve as unaffiliated directors.

The board’s Nominating Committee has put forward former Consolidated Edison CEO Craig Ivey for the final vacant seat. Ivey will be presented to members during their virtual annual meeting in December.

D’Andrea Jumps the Gun

During the PUC’s open meetings, Walker typically opens discussion of a docket by saying she has written a memo with suggested changes. Commissioners Arthur D’Andrea and Shelly Botkin then usually express their agreement and approve the order.

The practice caught D’Andrea off-guard last week as Walker opened discussion of Oncor’s request for a limited code-of-conduct waiver from the commission’s affiliate reporting and affiliate transaction rules (50893).

ERCOT — Commissioner Arthur D’Andrea agrees with Chair DeAnn Walker’s nonexistent memo. | *Texas PUC*

“I agreed with your memo…” D’Andrea began.

“I didn’t have a memo. Arthur, why are you making it harder?” Walker responded, teasing D’Andrea. The few staffers in the socially distanced hearing room erupted in peals of laughter.

The commissioners agreed they had no concerns with the affiliate issue and approved the order.

Nuke Decommission Fund Remanded

The commission remanded back to docket management the Comanche Peak nuclear power plant’s requested review of its decommissioning cost study and funding analysis, finding that they do not include evidence required by Texas ’ a dministrative c ode (50945).

Walker noted in a memo that the study and analysis were not accompanied by a report or supporting testimony and the requested annual funding amount; the decommissioning trust fund’s administrator did not demonstrate the funds are being invested prudently and in compliance with their investment guidelines; and the administrator did not demonstrate efforts to achieve “optimum tax efficiency.”

Comanche Peak Power Co. (CPPC) administers the decommissioning fund. It wants to continue the fund’s annual contribution of nearly $20.1 million through 2025, split between the plant’s two units on a 72.3/27.7% basis. The current approved allocation amount is on a 57.1/42.9% split.

CPPC said the two units have a net after-tax value of $1.32 billion. It says according to a May decommissioning cost analysis, it will cost $1.73 billion in 2019 dollars to decommission and completely dismantle Comanche Peak. The analysis shows about a -2.5% difference between the $19.4 million required funding levels and the five-year average decommissioning-fund collections of $19.9 million annually from 2015 to 2019.

In other actions, the PUC:

authorized Southwestern Electric Power Co.’s (SWEPCO) and El Paso Electric’s (EPE) adjustments to their energy efficiency cost recovery factors. SWEPCO will be allowed to recover $5.2 million (50805) and EPE $5.9 million during the 2021 program year (50806).
allowed EPE and Entergy Texas to issue fuel refunds following settlement agreements. EPE will refund $9.4 million (50940) and Entergy $25.5 million (51037) to ratepayers.

November 10, 2020March 9, 2025

Soapbox: It’s Time for Transparency in the Grid

Mike Jacobs | UCS

By Mike Jacobs

Replacing the fossil-fueled energy supply with renewable energy requires unusual focus and substantial investment in the electricity sector. Our ability to meet these needs — elevated by climate change and the COVID-19 crisis — depends on the success of RTOs and ISOs. We at the Union of Concerned Scientists work to make these institutions more transparent, understood and responsive to science and democratically established laws.

The RTOs/ISOs evolved over decades and matured in the 1990s through a combination of electric utility industry and government regulatory desire for cooperation and efficiency. Coordination in the utility industry through competition and innovation becomes harder when the RTOs/ISOs ignore the public interest in further decarbonizing energy. The conflict between an energy market system that ignores external costs and a society and its policymakers that see the health and climate impacts of pollution from energy can’t be ignored.

These organizations have demonstrated they can deliver savings and integration of high levels of renewables.

Utilities are Different

The difference between RTOs/ISOs and better known trading platforms, such as Lyft, Uber, eBay and Amazon, is that the grid operators were established by existing monopolies. But those monopolies did not anticipate renewable energy growth driven by policy, economics or carbon limits. The influence of the incumbent players in making the rules is not found in the better known platforms. How much do the existing asset owners influence new energy technologies in the market? We can take a look at how open, transparent and interested in emissions these grid operators are.

We Have Work to Do

The RTOs/ISOs are at varied and different places on transparency and consideration of climate impacts. Broadly, the RTOs/ISOs provide regional coordination and sharing reserves through power pools that benefit consumers, allow competition and further cost savings and technology innovation. But how well does this structure, set up with advantages for the owners of existing power plants, serve to protect the climate and implement state carbon-reduction policies? When policymakers push the external costs of carbon and health into decisions that can lower carbon emissions, RTOs/ISOs should not counteract those policies and raise costs to consumers.

Transparent and Open?

Transparency builds trust. Stakeholders have to know how decisions are influenced. The public needs to know what decisions are being made.

How well members, stakeholders or even the public follow the decision-making depends in large part on the posting of meetings scheduled, agendas and the minutes of what was discussed. UCS was quick to support press access to NEPOOL when access was denied. But a wider look at the mere posting of meeting dates and agendas for the RTOs/ISOs’ governing boards differ sharply from one regional grid to the next.

In PJM, there is no schedule of board meetings available and no minutes, leaving stakeholders unsure of discussions or changes to items on which members had voted. The ISO-NE board’s meeting dates and bare agenda are available, but minutes are not. At NYISO, board meetings can be open to regulators upon request, and minutes and future dates are published. MISO mails out notices of board meetings, and even the committees of the board hold open meetings. SPP posts meeting notices and extensive minutes and materials. CAISO holds open meetings with video recordings posted on YouTube!

Carbon-aware?

The RTOs/ISOs operate in parallel (and lately in conflict) with state laws that regulate utilities and provide consumer protections, as well as with health and safety protections that address environmental externalities. The New England States Committee on Electricity’s recent vision for the grid connected the lack of transparency in stakeholder and ISO-NE board processes with the need for market reforms suited to “the New England states’ legal requirements, policy imperatives and associated consumer interests.”

New York state CO2 emissions by sector | NYISO, using U.S. EIA data

There is a wide range in how the RTOs/ISOs keep informed and share data about emissions from power plants. Ten to 15 years ago, some ISOs developed a report of average marginal emissions for the evaluation of pollution savings from state energy-efficiency programs. Today, climate change driven by accumulated greenhouse gas is a bigger concern. Reporting totals of emissions over a year and by month or season will help decision-makers facing a wider variety of options to change fossil fuel use and cumulative emissions.

NYISO established an Environmental Advisory Council in 2004 that provides it with reports that include average marginal emission rates from its generation, as well as the cumulative CO2 emissions in New York from all sectors (drawing data from the U.S. Energy Information Administration). PJM reports only the average marginal rate of emissions, released each spring, and it is impossible to determine if this report is shared with the RTO’s board because there is no transparency. ISO-NE has, since 1993, made a similar annual report of marginal rates of emissions, though with an 18-month delay from the end of the year. CAISO makes monthly reports of emissions. SPP makes none.

Changed Energy Mix

Reporting on the energy mix is another measure of improvement on climate-harming emissions. SPP does post data showing enormous use of wind energy. In the spring and fall, SPP’s energy supply mix is routinely as high as 50% wind. All the other RTOs/ISOs also display their current energy mixes on their websites. These kind of data on the resources meeting electricity demand are fundamental to the RTO/ISO function. Such displaying and archiving of energy data is a minimal level of transparency not found from utilities outside the RTOs/ISOs.

The accumulation of CO2 in the atmosphere comes from the cumulative emissions from combustion (and other biological sources). A decent comparison and metric for RTO/ISO boards to monitor would show total greenhouse gas emissions from power plant operations, along with the sort of data EIA provides on fuel-burning emissions in other sectors of the economy in their regions. That reporting would allow RTO/ISO boards to monitor changes as members and utilities pursue electrification and electricity replaces fossil fuel in building and transportation. RTO/ISO boards should receive a report annually on how the grids they manage are affecting the climate.

What We Need from RTOs

Regional cooperation to meet energy demand requires transparency and openness now, as the public, leaders and utility industry members meet the challenge of climate change and decarbonize energy. Leaders of all these organizations need metrics reflecting their own operations and markets, both for daily business and for addressing climate-damaging emissions of carbon and methane.

People in government need the informed cooperation of citizens and corporations to implement policy on climate. With all the decision-making ahead, the RTOs/ISOs are going to be key for people, their polices and utilities to work together in new ways to move off climate-damaging fuels.

The New England states are asking for change from their RTO. The Mid-Atlantic states are in court over their RTO’s objection to renewable energy policy. We have to decide: Are these organizations up to the task?

Mike Jacobs is a senior energy analyst for the Union of Concerned Scientists with expertise in electricity markets, transmission and renewables integration work.