Page 1044 – RTO Insider

September 24, 2020

Calif. to Halt Gas-powered Auto Sales by 2035

California Gov. Gavin Newsom issued an executive order Wednesday that will prohibit the sale of all gasoline-powered automobiles in the state by the middle of the next decade.

The governor’s order will require that all new passenger cars and trucks sold in California be emissions-free by 2035, accelerating the state’s already ambitious goals of electrifying its transportation sector. The state currently has more than 725,000 EVs on the road and accounts for about 50% of the nation’s EV sales.

The move is expected to reduce statewide automobile emissions of greenhouse gases by 35% and NOx by 80%.

The order also directs the state’s Air Resources Board to develop regulations mandating that 100% of all operations of medium- and heavy-duty trucks be emissions-free by 2045, “where feasible,” with the mandate becoming effective in 2035 for all drayage trucks.

“This is the most impactful step our state can take to fight climate change,” Newsom said in a statement.

The transportation sector accounts for more than half of California’s carbon emissions, 80% of smog-forming pollution and 95% of diesel emissions, leaving the Los Angeles Basin and Central Valley with some of the dirtiest air in the country, the statement noted.

“For too many decades, we have allowed cars to pollute the air that our children and families breathe. Californians shouldn’t have to worry if our cars are giving our kids asthma,” Newsom said. “Our cars shouldn’t make wildfires worse — and create more days filled with smoky air. Cars shouldn’t melt glaciers or raise sea levels threatening our cherished beaches and coastlines.”

California gas powered sales — | *California Energy Commission*

Newsom’s order requires state agencies to partner with the private sector to speed up deployment of “affordable fueling and charging options” and to ensure that all Californians have “broad accessibility” to EV markets. The order does not prevent residents from owning gasoline-powered cars or selling them on the used car market.

The governor’s office is assuming that zero-emission vehicles “will almost certainly be cheaper and better” than traditional vehicles by the time the rule goes into effect, according to the statement.

“The upfront cost of electric vehicles are projected to reach parity with conventional vehicles in just a matter of years, and the cost of owning the car — both in maintenance and how much it costs to power the car mile for mile — is far less than a fossil fuel-burning vehicle,” the statement said, citing a BloombergNEF study.

Newsom also positioned the move as an economic opportunity for the state and U.S. automakers. EVs are California’s second-biggest export, Newsom said during a press conference.

“If American manufacturers do not commit to zero emissions, they’re not going to be able to sell their cars globally. They’re not going to be able to sell their cars in China, in India, in Israel, in Ireland, [which] are also committed to similar goals that California is advancing,” Newsom said in a video posted on Twitter.

“This is about strengthening our competitiveness [and] encouraging more manufacturing jobs,” he said.

‘Strong Action’

Newsom’s order met with predictable praise from environmental groups.

“In the midst of a historic wildfire crisis, Gov. Newsom is taking strong action to protect California’s economy and the health of its people,” Environmental Defense Fund President Fred Krupp said in a statement. “His announcement today will not only address the single largest source of climate and air pollution in California, but is a major step toward boosting his state’s economic competitiveness and helping Californians who are suffering extraordinary harms from air pollution.”

Krupp added that the new rules will position California “to win a new generation of jobs building affordable zero-emission vehicles — jobs that Europe and China are also hoping to capture.”

“With this announcement, California has the opportunity to be the center of the global clean transportation industry and once again to lead the nation in addressing climate change,” Annie Notthoff, California director of the Natural Resources Defense Council, said in a statement. “The past years of apocalyptic wildfires, record temperatures and droughts have made climate change and pollution all too real for everyone in the Western U.S. — most of all low-income households and communities of color.”

The move also sparked criticism.

Thomas Pyle, president of the American Energy Alliance, an advocacy group backed by fossil fuel producers, castigated the measure for allowing “bureaucrats in Sacramento” to make buying decisions that families should make for themselves.

“Right now, 97% of Americans decide to buy a car with an engine powered by gasoline. They make that decision for all kinds of reasons, including safety, size, range, comfort and, in many instances, because an electric vehicle is too expensive,” Pyle said in a statement. “The governor knows that today’s engines are cleaner, more efficient and more powerful. He also knows that there is no such thing as an environmentally perfect vehicle. This is not only a bad idea, and a bad deal for the state of California, it’s insulting to consumers and families.”

September 24, 2020

Utilities Pledge to Build Largest EV Charging Network

Six Midwestern energy companies have banded together in the hopes of developing America’s largest interstate electric vehicle charging network by the end of 2022.

Consumers Energy, DTE Energy, Evergy, Oklahoma Gas & Electric, Ameren Illinois and Ameren Missouri announced on Tuesday that they had signed a memorandum of cooperation, pledging to construct charging stations across five states. The companies said the network will facilitate clean transportation and bolster range confidence for long-haul EV trips.

The agreement doesn’t say how many charging stations will be built. Ameren spokesperson Jenny Barth said each energy company will “build a program that works best for their area.”

The utilities said more companies could join the effort. They added that network construction is dependent on regulatory approval from each utility’s state.

Largest EV Charging Network — | *Evergy*

“By partnering in the creation of a multistate electric charging network with energy companies outside of our own footprint, we are able to help our customers safely and economically travel to far-ranging destinations,” Ameren Missouri President Marty Lyons said in a release. “Detroit to Oklahoma City or St. Louis to Denver, we are supporting our customers, our communities and our country with cleaner driving.”

Ameren said transitioning to electric transportation can help “dramatically” lower carbon emissions, allowing the utility to meet carbon-reduction goals.

“Our focus in joining this multistate coalition is to develop a charging infrastructure that will help reduce ‘range anxiety’ and lead to broader adoption of electric vehicles,” Ameren Illinois President Richard Mark said.

The Edison Electric Institute estimates that there are more than 1.5 million EVs currently on the nation’s roadways, with just 100,000 public charging stations to support them. The trade association forecasts nearly 19 million electric cars on the road by 2030. To achieve that growth, EEI estimates that 9.6 million public charging stations will be needed.

“Expanding the use of electricity in transportation saves customers money, improves the environment by reducing emissions and enhances quality of life for everyone,” EEI President Tom Kuhn said. “By deploying charging infrastructure and accelerating electric transportation, EEI’s member companies, including Ameren and the other companies collaborating on this initiative, are working together to build a cleaner and stronger economy for the future.”

While there are about 40 EV models today, the Electric Power Research Institute expects automakers to have more than 130 models to choose from in just two years.

“Consumers Energy is committed to building the backbone of the charging network for electric vehicles across Michigan,” Senior Vice President Brian Rich said. “We know we can play an important role in charging the growth of EVs in our state and region, and know that will be good for Michigan’s economy, our communities and the environment.”

DTE Electric CEO Jerry Norcia also said his utility “has a significant role to play in helping make EVs a viable option for many.”

Evergy, which serves portions of Missouri and Kansas and was formed by the merger of Westar Energy and Kansas City Power and Light, tweeted that it was “excited” to partner with the other utilities. Evergy Chief Customer Officer Chuck Caisley said the network will make it “convenient and easy for EV drivers to charge their vehicles no matter where they are throughout the Midwest.”

September 24, 2020

New Study Offers Alternative to Carbon Pricing

Environmental policymakers should abandon the social cost of carbon (SCC) and adopt a more practical metric tied to net-zero-emissions goals, according to a new study.

The study, led by Noah Kaufman at Columbia University’s Center on Global Energy Policy and published in Nature Climate Change, notes that SCC estimates — intended to represent the “optimal” CO₂ price that maximizes net benefits to society — range from “under $0” per ton of CO₂ to more than $2,000/ton.

“The wide range of SCC estimates provides limited practical assistance to policymakers setting specific CO₂ prices,” Kaufman says. Instead, Kaufman and his coauthors recommend what they call the “near term to net zero” (NT2NZ) approach, which they say can eliminate much of the uncertainty, although they acknowledge it “balances benefits and costs only imperfectly.”

carbon pricing alternative — prices in proposals to Congress in 2019. | *Noah Kaufman, et al.*

The authors say the SCC is undermined by the large uncertainties over risk aversion levels, attempts to assign monetary values to noneconomic climate damages and the appropriate discount rates — the value placed on future generations.

The NT2NZ approach proposes a four-step methodology:

Select a net-zero CO₂ emissions date.
Select an emissions pathway to the net-zero target that balances the risks of even higher temperature changes with the additional costs of decarbonizing faster.
Estimate CO₂ prices consistent with the emissions pathway in the near term (e.g., next decade).
Periodically update steps 1-3 using an “an adaptive management strategy.”

“Focusing on the near term means that CO₂ price estimates should not be unduly influenced by assumptions about the highly uncertain long-term evolution of technologies and behavior,” Kaufman said. “Adaptive management can enable jurisdictions to stay close to the desired emissions pathway without making policy details contingent on assumptions about highly uncertain long-term variables.”

To illustrate the approach, the study looked at three straight-line emissions pathways from 2020 levels to net-zero CO₂ emissions targets in 2060, 2050 and 2040. It resulted in benchmark prices in 2025 of $32, $52 and $93 per metric ton (in 2018 dollars), respectively. The price roughly doubles by 2030, “reflecting a much higher annual growth rate than typical CO₂ price estimates based on the SCC or rising at the rate of interest,” the authors write.

Complementary policies such as more aggressive energy efficiency measures and regulations that lead to higher coal retirements could lower the 2050 CO₂ price by $10 to $20/ton, with the price rising by the same amount with less aggressive policies.

The authors acknowledge that uncertainties present in the SCC approach — such as near-term clean energy innovation and fossil fuel prices — also impact the NT2NZ method. “But the NT2NZ approach avoids much larger uncertainties, including assigning monetary values to climate change damages,” they say.

The Climate Leadership and Community Protection Act (CLCPA) signed by Gov. Andrew Cuomo last year requires the Department of Environmental Conservation (DEC) to establish a carbon price — based on either abatement or damage cost estimates — that state agencies can use to consider the societal value of actions to reduce GHG emissions in their decision-making.

The DEC this summer provided draft regulations on the value of carbon to fulfill the CLCPA requirements. The comments that the department receives will be part of the public record.

“It’d be great if the state took a look at our method when developing its [emissions] plan,” Kaufman told RTO Insider.

Pricing emissions, however, should not be conflated with spending on climate change, he said.

Speaking at a Sept. 9 webinar about the possibility of a green stimulus package from Congress after the presidential election, he said, “There’s a pretty big caveat: Spending on clean energy is a really ineffective way to reduce emissions, at least by itself.”

Kaufman recommended keeping expectations low for progress toward deep decarbonization.

“When you look at the data on the impacts of the nearly $100 billion in spending on clean energy from the 2009 stimulus, or the quarter-trillion dollars worldwide, you can find some really good outcomes for clean technology projects. But on emissions? No real evidence that it moved the needle,” Kaufman said.

Throwing money at clean technologies is not a climate strategy, he said. The core of climate policy strategies are policies that directly address emissions, such as regulatory standards and prices.

“The surest way to drive a climate policy analyst crazy is to describe a climate plan based on how much it’s spending,” Kaufman said. “Spending can be a great complement to climate plans, making them cheaper, more effective, more equitable. That’s what Europe is doing right now. But if you want to reduce emissions, regulate emissions.”

September 24, 2020

MISO Sets Candidate Slate for Board Elections

MISO’s Board of Directors has three seats up for grabs in December, though the new board is only guaranteed one new face.

The RTO’s Nominating Committee advanced current Directors Theresa Wise and Robert Lurie for member consideration, along with newcomer Jody Davids. Formerly chief information officer for PepsiCo, Davids has also served as CIO for Agrium, Best Buy and Cardinal Health. She currently sits on the board for Premier, a Charlotte, N.C.-based health care improvement company.

MISO board elections — Jody Davids | *Premier*

Wise and Lurie are both rounding out their first terms and applied for reappointment. Lurie served the one-year remainder of former Director Thomas Rainwater’s term, which expires at the end of December.

Longtime Director Baljit Dail will not make a reappearance at MISO’s U-shaped board table next year. Dail spent 12 years on the board — three more than technically allowed — through a special waiver that allowed him an extra term so the board could retain a person with technology expertise.

MISO’s 139 voting-eligible members can begin casting ballots for candidates beginning 8 a.m. Thursday. The electronic polls will close at 5 p.m. Oct. 30. Board elections require a minimum 25% participation rate to achieve quorum.

Members can vote for or against any of the candidates, or abstain. Candidates must earn a majority of votes cast to be installed. MISO will announce election results in mid-November.

The board voted unanimously during its Sept. 17 meeting to retain Phyllis Currie as its chairman in 2021.

September 24, 2020February 25, 2024

Indiana City Wins Ruling on Station Power

FERC ruled last week that generating facilities that are not online and producing energy must pay for their station power at retail rates subject to state jurisdiction and directed PJM to consider changing its Tariff accordingly (EL20-30).

The commission said an offline generator that requires power to operate its lighting, air conditioning and other facilities “is consuming electricity as an end user and thus, consistent with the boundaries of the commission’s jurisdiction under the [Federal Power Act], the provision of station power is a retail sale subject to state jurisdiction.”

The commission’s ruling came in response to a complaint filed by Lawrenceburg, Ind., and the Indiana Municipal Power Agency against the RTO, American Electric Power Service and Lawrenceburg Power seeking to void the power self-supply monthly netting provisions of the RTO’s Tariff.

The city’s Lawrenceburg Municipal Utilities has an exclusive franchise for supplying electricity within city limits and says Lawrenceburg Power’s 1,160-MW combined cycle plant in the city must take station power service from the city because Indiana law does not allow it a choice of retail supplier. The plant is interconnected with AEP transmission facilities under PJM’s operational control.

FERC approved the netting rules in 2001, saying station power can be supplied to a generating plant in three ways: on-site self-supply (from behind-the-meter generation); remote self-supply (from another generator owned by the same company); or third-party supply.

| Lawrenceburg Municipal Utilities

While the commission disclaimed jurisdiction over the supply of station power, it rejected the petitioners’ request for a declaratory order finding the station power monthly netting provision in section 1.7.10(d)(i ) of the PJM Tariff null and void.

Instead, FERC instituted a new proceeding, requiring PJM to propose changes to its Tariff consistent with the order or show cause why changes are not necessary (EL20-56). The RTO has 60 days to respond.

FERC said PJM’s proposed revisions should clarify that the monthly netting provision in section 1.7.10(d)(i) “does not determine whether a retail sale of station power has occurred in that month.” It also said Tariff provisions should clarify that PJM has no responsibility for the determination of any state-jurisdictional retail rates.

“Because the PJM Tariff’s self-supply monthly netting provision can be read to — and indeed has been relied on by certain PJM generators to assert the right to — determine whether a retail sale of station power has occurred and avoid the retail purchase of station power, which is inconsistent with the commission’s jurisdiction, we find that PJM’s Tariff may be unjust, unreasonable, unduly discriminatory or preferential,” FERC said.

Lawrenceburg Power told FERC that Lawrenceburg Municipal Utilities has attempted to charge the generator a minimum of $845,000 annually “even if Lawrenceburg Power does not consume any station power in the entire year” and that it prefers self-supplying its station power under the PJM Tariff.

“Arguments about the justness and reasonableness of the retail rates, and about what entity within the state of Indiana has authority to provide retail service, are more appropriately raised before the relevant state regulatory body,” FERC said. “The commission does not have the authority to determine when, and on what terms, a retail sale of station power is made.”

The ruling is likely to have impacts on other merchant generators.

Among the intervenors in the case were Buckeye Power, which said it and one of its member cooperatives, Washington Electric Cooperative (WEC), are involved in a dispute with Waterford Power, a merchant generator located within WEC’s service territory, regarding WEC’s right to supply Waterford’s station power.

September 24, 2020January 26, 2025

Few Obstacles Remain for Cybersecurity Standards

The standard drafting team (SDT) working on revising NERC reliability standards CIP-004-7 (Cybersecurity — Personnel and training) and CIP-011-3 (Cybersecurity — Information protection) will review the latest round of comments on the proposed changes in hopes of submitting them for approval this year. (See NERC Opens Comments on Standards Plan.)

NERC posted the standards for comment on Aug. 9, along with planned reliability guidelines on winter weather readiness and supply chain procurement. (See “Project 2019-02 Nears Completion,” Reliability Guidelines, Standards Posted for Comment.) Respondents were asked whether they agree that:

the revisions to CIP-004-7 properly clarify the requirements for managing provisioned access to bulk electric system cyber system information (BCSI) when using third-party solutions such as cloud storage services;
CIP-004-7 explains clearly that entities are only required to manage physical access to physical BCSI and electronic access to electronic BCSI;
CIP-011-3 explains the protections expected when using third-party solutions; and
the 18-month implementation plan proposed by the SDT is reasonable.

The results of the industry ballot that accompanied the comment period are not available yet, but SDT members have indicated they expect stakeholders to ultimately approve the revisions. However, the comments indicate there are some kinks to work out before industry gets fully on board with them.

Concern over Ambiguous Access Terms

Regarding the first question, a number of commenters complained about the insertion of the term “provisioned access” in CIP-004-7 without a definition. Anthony Jablonski of ReliabilityFirst asked that the term be either defined in the standard or removed entirely lest it “lead to misunderstanding [and] inconsistent audit results.”

“If you take ‘provisioned access’ to mean only intentionally created individual accounts, then administrative access to BCSI will not be governed by any standard,” Jablonski warned.

In a comment endorsed by several other stakeholders, Mark Gray of the Edison Electric Institute noted that a requirement to “authorize provisioning of access to BCSI based on need” is ambiguous and could be read to mean that entities are required to authorize access by anyone who asks, or have no discretion over which information can be accessed. He suggested that the phrase “process to” be added to the requirement, to clarify that each entity is responsible for defining its process for granting access.

| Shutterstock

Ambiguity was also a problem for respondents to the second question, with an anonymous commenter representing the Tennessee Valley Authority objecting that the “proposed language is too ambiguous and obligates entities to protect BCSI in any form, even [those] beyond [their] control.” For example, utilities could be held responsible for access to information being held by FERC or NERC. The commenter recommended that the language be “rescoped” to focus on managing access to information repositories, rather than the data themselves.

Mark Ciufo, writing for Hydro One Networks, also criticized the requirement for lack of clarity, observing that the standard “only [requires] managing physical access to BCSI,” while not explicitly stating that electronic access should be managed as well. Bruce Reimer of Manitoba Hydro agreed, pointing out that the standard’s requirements around the provisioning of physical access also seem inconsistent.

“If all unencrypted BCSI [is] stored on a server, does the server need to have authorized physical access? Obviously, the answer is ‘yes,’” Reimer said. “However, if using the provisioned access language, the BCSI server physical access control would be ignored. The provisioned access to BCSI is not clear.”

General Agreement on Cloud Services

Responses to the question about CIP-011-3 generally agreed that the most recent revisions “add clarity for protections expected when utilizing third-party solutions such as cloud services for storage purposes,” in the words of Jonathan Robbins of Seminole Electric Cooperative. However, many commenters felt the language could still be made more specific; for example, Jablonski and Russel Mountjoy of Midwest Reliability Organization called for the SDT to ensure that terms such as “data governance” and “data sovereignty” are fully defined in the text.

The 18-month implementation time frame likewise received widespread support, though some commenters supported a longer span: Richard Jackson of the U.S. Bureau of Reclamation called for a 24-month deadline, while TVA requested an extension to 36 months. By contrast, Jablonski said the revised standard would create “no significant new compliance requirements” and that, therefore, a six-month window would be more appropriate.

September 23, 2020

NRG to Mothball Petra Nova CCS Plant

NRG Energy advised ERCOT on Monday that it plans to mothball its Petra Nova Power plant, centerpiece of the world’s largest carbon-capture facility.

NRG issued a notification indicating that the plant will shut down on Dec. 20 but will be available for annual seasonal operations between June 1 and Sept. 30. ERCOT market participants have until Oct. 12 to file comments on any possible reliability effects from the suspension.

Operations at the plant have been suspended since May 1. NRG cited the global economic downturn and the low price of oil.

NRG Petra Nova — NRG intends to mothball its Petra Nova carbon-capture project. | *NRG Energy*

The plant, which has a summer capacity of 71 MW, was retrofitted at a cost of $1 billion to capture carbon from one of the nearby W.A. Parish Generating Station’s coal-fired units. Post-combustion carbon-capture technology reduces Petra Nova’s carbon emissions by 90%. The captured carbon is funneled through an 80-mile pipeline to a nearby oil field.

Petra Nova became operational in December 2016, on budget and on schedule. NRG said the plant delivered more than 1 billion tons of captured CO2 within its first 10 months. Power Engineering honored the project in 2017 as its Coal-Fired Project of the Year. Industry analysts don’t expect the plant to return to operation until oil prices stay consistently above $50 or $60/barrel.

Despite the project’s carbon-capture pedigree, NRG has remained a target of environmentalists. Chrissy Mann, the Sierra Club’s Beyond Coal Campaign representative, said that even when the Petra Nova project was operational, the Parish facility was the No. 1 source of particulate matter and No. 2 source of sulfur dioxide in the state of Texas.

“As NRG seemingly ends its carbon-capture project, NRG needs to take steps to address its dangerous air and water pollution,” Mann said. “It definitely makes economic sense that NRG is moving away from this continued investment in coal.”

September 23, 2020

SPP SPC Takes on Congestion Hedging Issues

With SPP stakeholders unable to reach consensus on how to modify the RTO’s congestion-hedging practices, the Strategic Planning Committee has taken matters into its own hands and will see if it can come up with a solution.

At issue is the Holistic Integrated Tariff Team’s recommendation last year to add counterflow optimization (CFO), limited to excess auction revenues, to SPP’s market mechanism that hedges load against congestion charges. (See SPP Board Approves HITT’s Recommendations.)

The Market Working Group took up the charge, reviewing 11 different proposals, including the status quo. Seven of those received support from either the RTO, the MWG or the Market Monitoring Unit, but not enough to reach consensus. The remaining four proposals were not supported by anyone.

“We’ve been informed by the MWG that, while [it] worked diligently to address this issue, [it] has concluded [it] can’t bring specific issues back to the table with broad-based support,” SPP Board of Directors Chair Larry Altenbaumer said during a Sept. 16 meeting of the Strategic Planning Committee, which he also chairs.

“My sense is we may be at a point where rather than trying to put this forward for an immediate answer,” he said, “we have a chance to step back and take an overall assessment before stepping forward.”

SPP congestion — SPP Board Chair Larry Altenbaumer (left) and SPC Vice Chair Mike Wise during a November 2019 meeting | © *RTO Insider*

To do so, Altenbaumer will be relying on Director Graham Edwards, who served on the HITT; Dogwood Energy’s Rob Janssen, who was the team’s vice chair; and NextEra Energy Resources’ Holly Carias, who chairs the Markets and Operations Policy Committee. Altenbaumer told the SPC that he has asked the three to further study automated counterflow. They will be assisted by SPP staff and receive input from the MMU.

Altenbaumer said the group’s only charge is to maintain the HITT’s recommendation. They are to present their findings to the board and MOPC in January.

“If the sense is we come back and say the status quo is unbalanced, that’s an OK answer. If they say it’s good for now, that’s an OK answer,” Altenbaumer said. “This situation is not unique to SPP. At least one other RTO is working through this process at the same time. Whatever can be gained in conversations with them can be a benefit to us as well.”

SPP’s current congestion-hedging practice is to allow market participants to nominate counterflow on a voluntary basis. Because it is a charge, participants are less likely to nominate, staff said.

The grid operator has been working since 2016 with participants, who are split over the system’s effectiveness, on changes to the market design. SPP supports automated counterflow to solve the current practice’s inequity, while the MMU said it is supportive of the status quo only over a solution that uses CFO.

The Monitor broke down the various proposals into two boxes: those using CFO and those not. In the former category, American Electric Power put forth a pre-auction, direct assignment of counterflows with opt-in/opt-out flexibility, while Oklahoma Gas & Electric suggested earmarking CFO dollars from the previous year, with the CFO method to be determined later.

In the non-CFO bucket, Nebraska Public Power District proposed partially modifying the excess auction revenue distribution method. The MMU opted for a more-than-partial modification of the revenue.

“Without addressing the underlying issues, the MMU believes the solutions being discussed today are really treating the symptoms,” the Monitor’s John Luallen said. “They have little to do with congestion patterns. They all represent a redistribution of congestion-hedging revenues between participants.”

Luallen said all congestion-hedging products derive their value from the day-ahead market’s congestion rent, which is unchanged by automated counterflow. He warned that the HITT’s proposed framework creates risk because load-serving entities, as a whole, will receive less revenue than they would without the counterflow.

Two factors determine whether automated counterflow creates value for LSEs, Luallen said: the change in the congestion rent received, net of cost, and the change in the auction revenue received.

Altenbaumer agreed with Luallen, saying both proposal categories “may be trying to address the symptoms rather than the underlying issues.”

“My desire is to come up with a solution that creates greater overall value or a situation or outcome that produces better efficiency in our markets or creates greater overall fairness in our market,” Altenbaumer said.

September 23, 2020

IPPNY Talks Methane Emissions, Carbon Price

The elimination of coal-fired electric generation means that New York’s battle against climate change must now focus on natural gas, Columbia Law School’s Michael Gerrard told the Independent Power Producers of New York (IPPNY) in the keynote address at the organization’s 35th annual Fall Conference last week.

IPPNY methane carbon — Michael Gerrard of Columbia Law School delivered the keynote address at the 35th annual IPPNY Fall Conference on Sept. 15. | *IPPNY*

“Far and away the largest source of greenhouse emissions in New York state is natural gas, and more of it comes from electricity production than anywhere else,” said Gerrard, a member of the Climate Leadership Council (CLC) and the founder of Columbia’s Sabin Center for Climate Change. “This is a blinking red light.”

The state’s last coal-fired generator, the Somerset plant on Lake Ontario, ended production in March. But while New York has banned fracking within its borders, more than half of its generating capacity is at natural gas-fired power plants, and a recent study concluded that its GHG emissions in 2015 were virtually unchanged from 1990 levels when considering upstream impacts and the role of methane from drilling sites producing the state’s fuel. Methane is about 80 times as potent at trapping heat as CO2 in its first 20 years. (See NY Study Highlights Rising Methane Emissions.)

“The climate reality is that global temperatures will continue to go up until we achieve net-zero [GHG] emissions,” said Gerrard, who spoke in place of his friend and colleague, CLC founder and CEO Ted Halstead, who had died in a hiking accident in Spain the previous week.

Economywide Carbon Tax?

The CLC’s 2017 climate change proposal called for an economywide fee on CO2 emissions starting at $40/ton and increasing by 5% every year, with all the revenue distributed to people in quarterly dividends.

But Congress hasn’t made a serious attempt to address GHG emissions since the failure of the Waxman-Markey cap-and-trade bill in 2009, leaving New York and other states to ratchet up their own efforts to address climate change.

The Climate Leadership and Community Protection Act (CLCPA) signed by New York Gov. Andrew Cuomo in July 2019 set ambitious clean energy goals — 100% zero-emission electricity by 2040 and an 85% cut in emissions by 2050 from 1990 levels — but did not include all the measures that will be needed to reach them.

A bill introduced in the state legislature last year that would impose a $35/ton carbon tax, rising after 11 years to $180, has not made it out of committee after previous failed attempts dating back to the legislature’s 2015-16 session (S3608).

“I’m not holding my breath that we’ll have either a nationwide or a New York state economywide carbon tax,” Gerrard said. He said the most promising initiative in the state may be the joint task force on carbon pricing created by NYISO and the state’s Public Service Commission in 2017, which resulted in a proposal published last December that would have the commission set the social cost of carbon to be used in any state policy.

Electrifying Everything

Gerrard said that while there is no unanimity on this issue, he thinks that FERC has the authority to consider climate change when acting on matters like the NYISO carbon pricing proposal.

“FERC makes its decision based on its view of the public interest, a phrase that appears about 50 times in the Federal Power Act. In the words of current FERC Commissioner Richard Glick, ‘climate change must factor directly into the commission’s permitting responsibilities, which generally require the commission to determine whether the relevant facilities are consistent with the public interest.’ Simply put, it is hard to imagine a consideration more relevant to the public interest than the existential threat posed by climate change,” Gerrard said.

Extreme heat kills more people than does extreme cold, he said, showing a National Weather Service heat index map that indicated extreme danger at 40% humidity and 110 degrees Fahrenheit, the highest temperature on the map.

“They don’t go higher than that, but we’ve seen actual temperatures in the last month that go literally off the charts,” Gerrard said. “The appropriately named Death Valley, Calif., experienced 130 degrees just a couple weeks ago, which may have been the warmest temperature ever recorded on the planet.”

Preventing the atmosphere from warming more than 1.5 degrees Celsius above pre-industrial levels, as recommended by the U.N. Intergovernmental Panel on Climate Change, will require electricity decarbonization, energy efficiency, carbon capture and electrification of transportation and everything else run by fossil fuels, Gerrard said.

Matt Schwall, IPPNY director of market policy and regulatory affairs, asked what the regulatory chances are of FERC approving a New York carbon pricing plan.

“I think it only happens if we have a change in administrations, and a change therefore in the composition of FERC,” Gerrard said. “I think it only happens with strong support from New York state. … If there is all of this support, and it’s clear we’re not going to have federal carbon pricing, there’s a good chance that FERC would approve it.”

Such a ruling could withstand an appellate challenge, he said, “because there is lots of precedent within FERC for considering [GHG] in a variety of contexts.”

Still, he added, surviving the challenge “depends in part on what panel is randomly drawn at the D.C. Circuit [Court of Appeals] to hear it.”

September 23, 2020January 30, 2024

FERC Again Rejects LG&E-KU Mitigation Exit

FERC last week denied LG&E and KU’s request for rehearing of its order rejecting the company’s proposed transition for exiting from market power mitigation measures, though it did alter the terms of its exit (ER19-2396, ER19-2397).

The commission imposed rate de-pancaking provisions to resolve horizontal market power concerns after Louisville Gas & Electric and Kentucky Utilities merged into a single company in 1998 and left MISO in 2006. In March 2019, the commission agreed the provisions could be removed because loads located in the LG&E/KU market would have access to enough competitive suppliers.

FERC conditioned the removal on a transition mechanism to protect Kentucky municipal customers that had relied on MISO transmission service. In its original September 2019 rejection, it identified several of these customers, including the city of Falmouth, located in the north of the state near its border with Ohio. (See FERC Orders Expanded Mitigation for LGE-KU.)

LG&E/KU, however, argued that Falmouth had joined East Kentucky Power Cooperative, a PJM member, in 2018 and thus should not be included in the transition mechanism. FERC acknowledged that it had erred and ruled that the city “should not be a transition customer.”

The commission otherwise rejected all of LG&E/KU’s numerous arguments, including that it ignored evidence that charges under certain MISO schedules are not pancaked charges, and that it erred by rejecting the company’s proposal to eliminate de-pancaking for exports to MISO.

“We find that LG&E/KU’s arguments overly simplify the context of this proceeding,” FERC wrote in its ruling.

In a separate but related ruling on rehearing, the commission also clarified its use of the “initial term” framework regarding the transition mechanism to Kentucky Municipal Power Agency’s (KMPA) ownership in the Prairie State Energy Campus project and the “take or pay” power sales agreements between it and its members (EC98-2-002, ER18-2162-001).

FERC had ruled that the transition mechanism would be “limited to the initial term of the power purchase agreements entered into by customers in the LG&E/KU market in reliance on the de-pancaking mitigation prior to the issuance of the March order.” But it said the agreements between KMPA and its members have no readily apparent “term” in the “same sense as the power purchase agreements discussed by the commission in the September rehearing order.”

It determined that the Prairie State agreements will be subject to the transition mechanism for a period of 10 years.

“We find a 10-year framework to be appropriate for the transition mechanism for power purchase or sales agreements with no initial term because, otherwise, the de-pancaking mitigation would continue in perpetuity in contrast to the March order, which directed that the de-pancaking mitigation can terminate,” the commission said. “We find that 10 years from the date of the issuance of the March order is a reasonable period of time to allow KMPA to plan for alternative supply choices before its power supply agreement is no longer subject to the transition mechanism.”