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November 7, 2024

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FERC Defends PJM Capacity Performance Before DC Circuit

By Rory D. Sweeney

WASHINGTON — A group of environmentalists, regulators and public power advocates told the D.C. Circuit Court of Appeals on Tuesday that it should overturn PJM’s Capacity Performance construct, saying it was fast-tracked into implementation without proper review and discriminates against renewable generators and demand response (16-1234, 16-1235, 16-1236, 16-1239).

ferc pjm capacity performance
E Barrett Prettyman Federal Courthouse

PJM developed CP in response to increasing generation forced outage rates, which peaked at 22% during the 2014 polar vortex  cold snap, when the RTO had to implement emergency procedures to avoid blackouts. CP phased out seasonal resources and increased both bonuses for overperformance and penalties for nonperformance.

FERC approved PJM’s plan — which was submitted without stakeholder approval — in June 2015, saying the changes were justified by “the combination of deteriorating resource performance and the ongoing change in the resource mix in the PJM region.” (See FERC OKs PJM Capacity Performance: What You Need to Know.)

FERC’s approval is being challenged by a group including the American Public Power Association, National Rural Electric Cooperative Association, New Jersey Board of Public Utilities, Public Power Association of New Jersey, Natural Resources Defense Council, Sierra Club, Union of Concerned Scientists, American Municipal Power and the Advanced Energy Management Alliance.

High Costs, Ignored Alternatives

“The common thread in all of these appeals is that PJM rushed to assemble its Capacity Performance proposal, and FERC rushed to approve it, ignoring any alternative proposals despite the proposal’s high cost to consumers, its discriminatory effect on certain capacity resources and other flaws,” APPA attorney Randolph Elliott said. “This is like getting to the 5-yard line and having the referee push you over the goal line, or hitting a triple and having the umpire wave you home.”

The opponents argue FERC failed to demand sufficient evidence that PJM’s proposal would result in just and reasonable rates, saying that while the increased costs of the new requirements have been estimated, there was no attempt to quantify the reliability benefits it would produce.

They also contend that limiting capacity bidders to year-round resources discriminates against renewables and DR and that FERC unreasonably imposed limits on aggregating resources across locational deliverability areas. Also under dispute are PJM’s default offer cap, its unit-specific operating parameters and the design of its nonperformance penalties.

“It’s undisputed that PJM did not have the authority to make all of these changes unilaterally,” Elliott said. “The proposal was so controversial among the stakeholders that PJM did not even try to get the support they needed to file it unilaterally under [Section 205 of the Federal Power Act], so they elected to file this Section 206 complaint along with the other Tariff changes they filed under Section 205. … FERC said that the unilateral Tariff changes that PJM had made were just and reasonable, but then it turned around and said, ‘Because you did those, you’ve rendered your operating agreement and some other provisions in your Tariff unjust and unreasonable.’ Now how could those both be true at the same time? So they then turned around and granted the complaint, and said, ‘In light of the changes that you’ve made unilaterally, we have no choice but to grant your complaint.’”

ferc pjm capacity performance
Price | Jenner & Block

Judge Janice Rogers Brown asked if it would have been acceptable for FERC to initiate the Section 206 filing. Elliott argued no. But Matthew E. Price, representing CP supporter Exelon, later argued that it’s well within FERC’s purview to also order parallel revisions when an order is issued.

‘Strange Result’

“It would be a very strange result if the law were somehow different because PJM had initiated the 206 proceeding and pointed out to FERC, ‘Hey, here are some areas where you might want to consider making some changes,’ rather than leaving FERC to hunt around in other tariffs and identify changes that might need to be made,” he said.

Carol Banta, an attorney from FERC’s Office of General Counsel, defended the commission’s order approving CP, saying FERC fairly and carefully weighed PJM’s proposal and is entitled to deference in its conclusion. She noted that the commission found the proposal not unreasonably discriminatory toward any stakeholder.

FERC approved the proposal, she said, because it transferred the risk for performance from consumers to suppliers. The 2014 outages were a “conflation of events that really showed a number of weaknesses in the system,” she said. “It showed that we were already paying for reliability that we weren’t getting.

“When we talk about what are the reliability benefits that customers are getting for what they’re paying, it’s also in the context of what they were getting and not getting before,” she said. “A conventional resource, if it’s unable to guarantee its performance, it can fix something: It can upgrade its equipment; it can firm up its fuel arrangements. It has options, and actually this entire market proposal is to put those risks on suppliers. … If you have a wind farm, you can’t order more wind, so the commission agreed that it’s a reasonable accommodation for resources that couldn’t improve their performance just by making investments to allow them to still participate in these markets.”

Dictating Terms

This exemption for intermittent resources, like wind and solar, to aggregate their production so they can also guarantee year-round performance remained a focus throughout the hearing for Senior Judge David Sentelle. He asked why the commission hadn’t allowed conventional resources, like natural gas- and coal-fired plants, to also aggregate.

“PJM is not supposed to be dictating the terms here,” he said. “I can understand why aggregation would be a good thing, but would it not then be a better thing if they were allowed to cross-aggregate with traditional resources?”

Allowing such aggregation would create opportunities for companies to exercise market power, Price pointed out.

The technical aspects of the case appeared to be a challenge for the judges to hash out beyond the legal questions.

“There are many things in this case I don’t fully understand,” Senior Judge A. Raymond Randolph said. “What exactly is a delivery area, and second of all, why wouldn’t they be allowed to [aggregate] across delivery areas?”

“PJM didn’t provide the level of detail that the commission needs to approve that,” Banta said. “That could still happen.”

Price explained that the delivery areas are defined by transmission constraints, so resources “wouldn’t necessarily be able to deliver energy” to other areas.

Randolph also asked if any stakeholders had challenged that decision, and Banta said that American Municipal Power had made it part of its appeal.

ferc pjm capacity performance
Desormeau | NRDC

Cost vs. Benefits

Also participating in the nearly hour-long hearing was attorney Katherine Desormeau for the NRDC, who focused on CP’s cost versus the value of its benefits.

“PJM has acknowledged from the outset that this proposal will increase costs on consumers, but it did not support its final proposal with any evaluation of the costs,” she said. “And it didn’t attempt to evaluate the reliability benefit that was the purpose of the Capacity Performance proposal. … [FERC concludes] that the costs will be outweighed by benefits, but we have no way of knowing what FERC thought that was.”

Price replied that the proposal was designed to meet PJM’s reliability objective of no more than one outage every 10 years. “That reliability standard is a bedrock principle of capacity market design that goes back many years and is true in all of the regions under FERC’s authority,” he said. “When you hear petitioners complain about the costs of this program, what they’re complaining about are the costs of achieving that standard. What they’re really arguing to you is that standard is problematic because it costs too much and they’re willing to tolerate more risk, but that standard was not litigated in this proceeding. … Petitioners should not be able to make essentially a collateral attack on this well-settled reliability standard by complaining about the costs of the program.”

In their final brief, the challengers noted that the commission approved CP on a split vote, citing former Chairman Norman Bay’s dissent. (See Norman Bay’s Dissent: ‘Two Carrots and a Partial Stick’.)

FERC’s final brief cited precedents in which the agency’s decisions have been given “great deference,” saying its factual findings should be considered conclusive if supported by “substantial evidence” — “more than a scintilla, but … less than a preponderance of the evidence,” the standard in civil trials.

The D.C. Circuit also has pending before it a challenge to ISO-NE’s similar Pay for Performance rules (New England Power Generators Association v. FERC, D.C. Cir. Nos. 16-1023, 16-1024). Banta noted that in both cases, FERC has said it’s reasonable for all capacity resources to be expected to perform year-round “regardless of technology type.”

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SPP First RTO to 50% Wind Energy Penetration Level

By Tom Kleckner

ERCOT may have more wind, but SPP can lay claim to becoming the first North American RTO to obtain more than half of its power from it.

At 4:30 a.m. Sunday, SPP’s footprint generated 11,419 MW of wind energy at the same time its load was 21,919 MW. The wind-penetration mark of 52.1% broke the RTO’s previous record of 48.2%, set last April, and ended a friendly battle with ERCOT to see who could reach the 50% level first.

The two neighboring grid operators sit in the nation’s most wind-rich regions. Texas may top all other states with more than 20 GW of installed capacity — with ERCOT managing more than 17 GW of that — but SPP and its 14-state footprint is not far behind, with more than 16 GW of installed capacity and another 21 GW in the interconnection queue.

In the early 2000s, SPP counted less than 400 MW of wind energy, reporting it as “Other” in its fuel-mix data. Wind now makes up about 15% of the RTO’s nameplate generating capacity, trailing only natural gas and coal generation.

SPP added 4,000 MW of wind capacity in 2016, boosting its maximum simultaneous wind generation peak from 9,948 MW to 12,336 MW. It has set seven peaks for wind generation since last year, the latest coming Feb. 9 at 13,342 MW. Staff has even thrown out a 60% penetration number, saying it expects to crack that level this April.

“Ten years ago, we thought hitting even a 25% wind-penetration level would be extremely challenging, and any more than that would pose serious threats to reliability,” SPP Vice President of Operations Bruce Rew said in a statement. Fifty percent “is not even our ceiling. We continue to study even higher levels of renewable, variable generation.”

Several stakeholder groups are already at work trying to determine how best to add even more wind to SPP’s 550,000-square-mile footprint. The RTO has approved more than $10 billion in transmission infrastructure over the last decade, much of it to connect rural, isolated Midwest wind farms to distant population centers. (See “Stakeholders Try to Grasp Wind Energy’s Implications,” SPP Board of Directors/Members Committee Briefs.)

spp wind energy

The RTO is holding a two-day Variable Generation Integration Workshop this week at its corporate headquarters in Little Rock, Ark. Staff will provide a deep dive on the second analysis it has performed on variable generation resources during the last several years. The study focused on system requirements needed to operate reliably at higher penetration levels while calling on fossil fuel resources to compensate for drops in wind production.

“If we start pushing 12 to 15 GW of output, we’re at the point where we should be concerned,” SPP’s Casey Cathey, manager of operations analysis and support, told the Markets and Operations Policy Committee last month. “We’re not trying to say the sky is falling, but it’s important we have a grip on the traditional resources and that we leverage them, as opposed to manually pushing more resources online in case the wind drops.”

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IPPs File Challenge to Illinois Nuclear Subsidies

By Rich Heidorn Jr.

Independent power producers on Tuesday filed suit in federal court challenging Illinois’ zero-emission credits for Exelon’s Quad Cities and Clinton nuclear plants, calling the program “illegal and unfair.”

The lawsuit seeks to overturn the Future Energy Jobs Act, which authorized the ZEC program, contending the law violates FERC jurisdiction over the wholesale electricity market.

nuclear subsidies zero emission credits
Exelon’s Clinton Nuclear Plant | Nuclear Regulatory Commission

It was filed in the Northern District of Illinois, Eastern Division, by the Electric Power Supply Association (EPSA), Dynegy, Eastern Generation, NRG Energy and Calpine, naming the Illinois Power Agency and the Illinois Commerce Commission as defendants (1:17-cv-01164).

Jonathan Schiller, a managing partner of the plaintiffs’ attorneys Boies, Schiller & Flexner, said Illinois’ legislation will fail for the same reason that the Supreme Court last year unanimously rejected Maryland’s attempt to subsidize a combined cycle plant. (See Supreme Court Rejects MD Subsidy for CPV Plant.)

“The Hughes [v. Talen Energy] decision clearly stated subsidies tied to wholesale power market prices — such as ZECs — are plainly illegal. The ZEC program is designed to allow Illinois to take actions that directly affect the wholesale electric market in an attempt to replace the federally regulated market prices with costs determined by the state instead,” Schiller said. “The credits are directly tied to the Illinois nuclear plants’ participation in interstate energy markets and are unconstitutional as a result.”

The plaintiffs cite an estimate that the out-of-market payments will total $235 million annually over 10 years.

Separately, EPSA also made two filings with FERC calling for expedited action to reject the ZEC programs in Illinois and New York.  New York’s program also has been challenged, despite regulators’ contention that the program was designed to avoid the jurisdictional problems cited by the court in Hughes.

EPSA said its filings — answers to other parties’ comments — argue “that there is no merit to the procedural or substantive objections raised, urging the commission to act decisively and without delay” (EL16-49, EL13-62).

The commission, however, will be unable to act until a third commissioner is confirmed to restore its quorum.

EPSA noted with alarm that officials in Connecticut, New Jersey and other states are considering ZEC-type supports for their nuclear fleets.

“The commission should not allow opposing parties to obfuscate matters and should remain focused on the issue at hand to address the recognized threat to the markets through imposition of a minimum offer price rule (MOPR) on existing units for the capacity auctions used in New York and PJM to protect consumers and markets,” EPSA President John E. Shelk said in a statement. “FERC should take this corrective action and then work with all stakeholders on fuel-neutral market reforms and state concerns consistent with competitive market principles.”

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Commissioners Ask MISO to Share Tx Project Cost Data

By Amanda Durish Cook and Rich Heidorn Jr.

WASHINGTON — Texas Public Utility Commissioner Ken Anderson and other state regulators sharply questioned MISO officials Monday over its refusal to share with them raw cost data on transmission projects.

miso transmission project cost data closed meeting
Anderson | © RTO Insider

The exchange came during an in-person gathering of the Organization of MISO States Board of Directors at the winter session of the National Association of Regulatory Utility Commissioners.

OMS President and Indiana Utility Regulatory Commissioner Angela Weber, who has been calling for the organization to be more transparent itself, joined Anderson in pressing the RTO.

Anderson was already riled up when he arrived about 10 minutes late for the OMS meeting, having gotten lost looking for the conference room in an interior hallway of the Renaissance Hotel. He burst into the meeting, arms waving and complaining that the session had been scheduled in an unnumbered room. “There is a number outside,” Weber calmly informed him before going on with a discussion of an appeals court brief.

miso transmission project cost data closed meeting
Weber | © RTO Insider

Minutes later, Anderson was steamed up again. Priti Patel, manager of customer and state and regulatory affairs for MISO North, was explaining that the RTO aggregates cost data from transmission developers before sharing the figures with state commissions because it considers them proprietary information.

“This is the problem in MISO … really? Proprietary?” Anderson asked testily.

Weber and other regulators at the Feb. 13 meeting also expressed dismay and called on MISO to provide more visibility on project costs.

The discussion ended when — at the urging of Iowa Utilities Board Member Libby Jacobs — Patel agreed to ask her superiors whether state regulators could sign confidentiality agreements to be privy to the more granular information as the RTO receives it from the developers.

Before FERC Order 1000, Patel had explained, MISO only required “minimal” project information such as facility statuses and in-service dates. New Tariff requirements dictate that developers provide the RTO with regulatory status, right-of-way status, permitting status, and design and engineering status. She said MISO can investigate causes of schedule delays and cost overruns greater than a 25% deviation from the budget.

miso transmission project cost data closed meeting
Patel | © RTO Insider

While MISO’s monitoring could intersect with state regulators, the RTO is not infringing on states’ rights, Patel said, reminding OMS members that MISO does not determine rates. “We’re not there to judge the prudency of a cost,” she said.

MISO gives more weight to operations and maintenance planning than construction costs when evaluating project bids, Patel said. “What we’re evaluating is the actual infrastructure,” she said. Patel added that developers are keenly aware of costs, however, noting that 10 of the 11 bidders on MISO’s competitive Duff-Coleman project wrote a cost cap into their proposals.

OMS Executive Director Tanya Paslawski said ratemaking power ultimately lies with FERC, and both MISO and states “are limited in what they can do.”

Weber said state access to developer information varies from state to state, pointing out that commissioners in Indiana do not have access to cost information.

OMS Reviewing Own Transparency

OMS is also reassessing the appropriateness of using closed sessions during its meetings.

The topic came up in early February after some OMS members requested a closed session to discuss MISO and PJM’s FERC filing to implement targeted market efficiency projects (TMEPs). Weber said some members wanted a closed session to discuss different state viewpoints of the TMEP. She questioned whether OMS should use closed sessions for simple disagreements.

miso transmission project cost data closed meeting
The Organization of MISO States Board of Directors had an in-person meeting Monday at the NARUC winter session in Washington. | ©  RTO Insider

“I felt that … it’s a very broad interpretation of closed meetings. Once you get into that broad interpretation, there are going to be more and more closed meetings,” Weber said at a Feb. 2 OMS Executive Committee meeting.

OMS bylaws dictate that meetings be generally open because they are composed of public commissions.

Weber said the organization could clarify the language that permits closed sessions only when strategy on a FERC filing is discussed.

OMS should not enter closed session every time a legal issue comes up in discussion, she said. “Almost everything we do touches on legal” proceedings.

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MISO to Take Case-by-Case Approach on BTM Generators

By Amanda Durish Cook

CARMEL, Ind. — MISO has taken another shot at explaining how behind-the-meter generation will function in its markets, this time focusing on how those resources can participate in the upcoming capacity auction.

miso btm generators behind-the-meters
Harmon | © RTO Insider

BTM generators identifying as load-modifying resources will be able to demonstrate deliverability for excess capacity in the 2017/18 Planning Resource Auction by meeting with staff for a case-by-case review, John Harmon, MISO manager of resource adequacy, said during a Feb. 8 Resource Adequacy Subcommittee meeting.

“We’re going to need to talk with folks and work with them to determine [if] they have excess capacity and how do they go about demonstrating deliverability of power,” Harmon said.

American Electric Power’s Kent Feliks asked if staff had any idea how many reviews it might conduct and what they might entail. “It seems a little black box-esque,” he said, adding that in some zones, a small amount of additional megawatts could impact clearing prices.

Harmon declined to comment on the scope or scale of the reviews, but he did say staff would review a generator’s proof of deliverability of any excess capacity to determine an “interconnection service equivalency.” If cleared, generators could then acquire transmission service for delivery.

For future planning years, MISO will require BTM generators to enter the interconnection queue and attain network resource interconnection service before entering the auction, Harmon said. The RTO will also schedule a discussion on possible “alternative deliverability” methods for BTM generation during May’s RASC meeting.

Last month’s educational workshop on BTM generation definitions raised questions about excess capacity deliverability and how generators could register in MISO’s Open Access Same-Time Information System (OASIS), the first step in procuring transmission service. (See MISO Behind-the-Meter Generation Definitions Create Confusion.) The RTO allows BTM generation to register as a capacity or load-modifying resource to participate in the auction.

Harmon said BTM generators could be included in OASIS by adding their commercial pricing nodes to the system. Generators would have to take the extra step of contacting MISO to submit their existing nodes, he said.

Customized Energy Solutions’ David Sapper asked if BTM generators would be guaranteed a reservation after contacting MISO. Harmon replied that they would enter MISO’s system impact studies like any other generator entering OASIS.

Sapper also asked if MISO would let BTM generators create new commercial pricing nodes for OASIS recognition, claiming some generators might encounter a snag if they could not. MISO staff rejected that idea.

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PJM Operating Committee Briefs

VALLEY FORGE, Pa. — A simulated performance assessment hour last summer would have produced nearly $13.5 million in nonperformance charges, resulting in approximately $1,283/MWh bonus payments for overperforming units, PJM’s Joe Ciabattoni said at Tuesday’s Operating Committee meeting. (See PJM Generator Notification Plan Gets Mixed Review.)

The simulation, which was requested by stakeholders, was simplified to exclude bonus capping and excusals for shortfalls. “Just remember it’s a simulation,” PJM’s Mike Bryson cautioned.

PJM used the 3-4 p.m. hour on Aug. 11, a $1,896.30/MWh penalty rate and Tariff formulas to determine the expected and actual performance. Of the 528 capacity resources, 176 combined for a total shortfall of 7,093 MW, while 306 exceeded their promised output by a combined 10,485 MW. There were 46 resources with neither a shortfall nor a bonus.

Fifteen resources would have been charged more than $250,000 each, with the highest individual charge calculated at almost $1.2 million. Twenty-five resources would have received more than 100 MW worth of bonus payments, with the largest individual credit equaling 601 MW. PJM also calculated separate numbers for just the Mid-Atlantic territory.

Stakeholders felt the broad focus left too much ambiguity. “To me, there are so many details left out that it raises more questions than it does provide answers,” American Electric Power’s Brock Ondayko said.

On some levels, PJM agreed. “I don’t know if we consider this a good predictor of what to expect or not,” PJM’s Adam Keech said.

Later, PJM staff reviewed member responsibilities for several other components of Capacity Performance, including inputting real-time values such as minimum and maximum run times to reflect operational capabilities when the resource cannot operate according to its unit-specific parameters. The deadline for changing unit parameters for delivery year 2017/18 is Feb. 28.

“This is your opportunity to give us the rest of the story,” Ciabattoni said.

The D.C. Circuit Court of Appeals is scheduled to hold oral arguments Feb. 14 on environmentalists’ challenge to FERC’s approval of CP. (See Clean Energy Advocates Appeal FERC’s Capacity Performance Rulings.)

Stakeholders Debate Replacing Second Ramapo PAR

Stakeholders expressed concern over the costs of replacing a phase angle regulator that failed at Consolidated Edison’s Ramapo substation last June.

That leaves just one PAR at the facility, but Con Ed is waiting for certainty on cost allocation before replacing the second one, PJM said. Without it, PJM’s transfer capability into NYISO is limited by about 300 MW. The situation is complicated by the fact that Con Ed is ending its PJM membership in May with the termination of the Con Ed-PSEG “wheel.” (See NYISO Members OK End to Con Ed-PSEG Wheel.)

The grid operators are considering modifications to their joint operating agreement to develop a cost recovery mechanism for replacing the PAR. The methodology would be used for future cost sharing as well.

The PARs were added in 1988 to control loop flows that had undermined the reliability benefits of the Branchburg-Ramapo 500-kV line, which was built in response to the 1965 Northeast blackout. The current agreement splits costs of the two PARs 50-50 between NYISO and PJM.

Stakeholders were quick to question the financial implications of the proposal, including how much it would cost and what PJM’s thoughts were on a likely cost allocation agreement.

“We do not have any preconceived notions of how that would work,” PJM’s Stan Williams said, adding that the replacement would cost $10 million to $20 million. He confirmed PJM’s plan to consider the changes through a problem statement and issue charge.

Williams also acknowledged that some of the PARs’ main benefits have been “muted” since they were initially implemented. The second PAR reduces the risk of sustained customer outages during severe weather, but that happens “rarely,” he said. Additionally, the loop flows that originally necessitated the PARs have been reduced.

PJM has conducted modeling both for the operational baseflow that will replace the wheel with one PAR, or two PARs, PJM’s Paul McGlynn said. However, PJM’s current planning parameters for the upcoming Base Residual Auction assumes two PARs, he said.

The grid operators are planning joint stakeholder meetings on the issue, likely beginning in March, Williams said.

New Regulation Rules Improving ACE Control

Recent changes to regulation signals and operational requirements are improving area control error (ACE) statistics, PJM’s Eric Hsia said. (See “Regulation Requirement Changing from ‘Peak’ to ‘Ramp,’” PJM Operating Committee Briefs.)

The average of the median daily ACE has been cut in half since the new signal was implemented and the monthly average mileage ratio has more than doubled. That indicates a larger utilization of Regulation D resources and better alignment of Regulation A signals with unit ramps, PJM said.

“We’re moving the Reg-D resources more aggressively,” Hsia said.

Modeling Improvements Reducing Balancing Congestion

PJM’s efforts last year to improve the alignment between its day-ahead and real-time modeling has reduced balancing congestion, PJM’s Nicole Scott said.

The RTO calculated impedance differences to compare the planning model versus the model used by operators, Scott said, and used summer 2015 peak base cases as a benchmark. Staff has worked to improve the parity between the models by correcting errors, increasing mapping of transmission facilities, refining processes and providing additional training, she said.

The goal is “normalizing the two models to get them to look the same,” PJM’s Mark Sims said. “If we tried to do this five years ago, we would [have struggled], but everything lined up [now].”

Among additional initiatives for 2017, PJM plans to create an alarm warning when a model is out of compliance.

Committee Endorsements

The Operating Committee endorsed by acclamation:

– Rory D. Sweeney

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Electric Cars – Three Ugly Facts

By Steve Huntoon

One would have to live under a rock to not know about the Second Coming of electric cars.[1] (The First Coming 100 years ago is pictured.)

Virtually every auto maker has announced plans, and the media have anointed their inevitability. As The Wall Street Journal proclaimed recently, “The car of the future will be electric …”

But to paraphrase Thomas Huxley, the great tragedy of reality is the slaying of a beautiful hypothesis by an ugly fact.

In the case of electric cars there are not one but three ugly facts. First is that they cost a lot more than gasoline cars and that’s not going to change for a long time. Maybe never.

Second is that they tend to contribute to global warming more than gasoline cars.

Third is that they cause more death and disability than gasoline cars.

Let me walk you through this great tragedy of reality.

First ugly fact: Electric cars are and will be much more expensive — indefinitely. Ignore the media hype and consider peer-reviewed academic articles, like one by researchers from the University of Chicago and the Massachusetts Institute of Technology in the Journal of Economic Perspectives last year, showing that electric cars are far out of the money for customers on a total cost of ownership basis.[2] Basically, the high cost of batteries trumps (sorry, couldn’t resist) the lower cost of electricity relative to gasoline.

And here’s the killer — it ain’t going to get much better for the next 10 years — if ever. Even if battery costs drop precipitously from the current $325/kWh to $125/kWh (an Energy Department “target”), oil prices would still need to rise to $115/barrel for electric cars to make sense. There is a fascinating chart in the Chicago/MIT paper (pictured) showing the break-even relationship between battery costs and oil prices.

Neither battery costs nor oil prices are likely to align for electric cars. Battery costs seem to be plateauing above $300/kWh. Tesla’s Powerwall 2 has debuted at $321/kWh even if one generously gives its inverter a $1,000 value.[3]

As for oil, the futures price is below $60/barrel through 2025, about half of what oil would need to cost in order for a battery cost of $125/kWh to break even.

To summarize, the electric car propulsion system is 400% out of the money, with little prospect of making that up any time soon, if ever. And the recharging time and location problems still need to be solved.

So, yes, Tesla and others will sell their electric cars as Veblen goods — commodities for which demand is high because of their high prices and perceived status — in the hundreds of thousands. But tens of millions of cars sold every year will continue to run on gasoline.

Second ugly fact: Electric cars exacerbate global warming. Surprised? It’s important to remember a couple things. One, converting raw fuels to electricity is inefficient. Two, the fuels generating electricity when an electric car is charging tend to be the worst from an environmental perspective.

There is only one study I can find that was sufficiently “granular” to do carbon emission analysis on this hard reality basis. It is a paper published in another obscure periodical, the Journal of Economic Behavior & Organization, with the engrossing title: “Spatial and Temporal Heterogeneity of Marginal Emissions.”[4]

Buried in excruciating detail is the hard reality. The average rates of carbon dioxide emissions on an apples-to-apples kilowatt-hour basis are:

      • Electric car: 2.10 lbs/kWh.
      • Comparable gasoline car: 1.79 lbs/kWh.
      • Comparable hybrid: 1.13 lbs/kWh.

So if you buy an electric car instead of a comparably sized gasoline car, you will most likely make global warming worse.  And an electric car instead of a hybrid would be twice as bad.

Third ugly fact: Electric cars cause much more death and disability (euphemistically, “human toxicity potential”) from the mining of heavy minerals and graphite. This has received anecdotal attention in The Washington Post and other media, but there is an empirical study by Arthur D. Little showing that the aggregate “days of life impact” in terms of death and disability are 30 for an electric car (with a 50-kWh battery in 2025) versus six for an equivalent gasoline car.[5]

So to sum up, electric cars cost more, contribute to global warming more and hurt more people than gasoline cars.

May I make a modest proposal if you care about the environment and don’t want to hurt people? Take the money you would have overspent on an electric car and spend it on (1) a renewable energy supply option from your utility or other electric supplier, (2) a hybrid car and/or (3) high efficiency appliances and lighting such as LED bulbs.

You may not have the coolest toy in the neighborhood, but the planet and your fellow humans should thank you.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel LLP.

[1] Here we mean battery-powered electric cars, not driverless cars or hybrid cars.

[2] http://pubs.aeaweb.org/doi/pdfplus/10.1257/jep.30.1.117.

[3] $5,500 minus $1,000 divided by 14 kWh is about $321/kWh. The inverter value may be high; Tesla isn’t charging anything less if you get the DC version without the inverter.

[4] http://environment.yale.edu/kotchen/pubs/cars.pdf.

[5] http://www.adlittle.us/uploads/tx_extthoughtleadership/ADL_BEVs_vs_ICEVs_FINAL_November_292016.pdf.

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Nuclear Industry Seeks to Remain Relevant

By Rich Heidorn Jr.

Though its generators emit no carbon, the nuclear industry finds itself — like coal — struggling to remain relevant in the electric business.

The U.S. has lost eight plants totaling almost 4,800 MW since 2013, and at least three more (3,500 MW) are expected to retire by 2025. Any boost that the industry hoped to get under the Clean Power Plan likely evaporated with the election of Donald Trump.

But at the Nuclear Energy Institute’s briefing to Wall Street last week, CEO Maria Korsnick insisted things are getting better — or are about to. The industry is “reaching a tipping point as policymakers have come to appreciate the risk of losing nuclear plants,” she said. Last year, she added, “we began to see the ocean liner change its bearing.”

Mixed metaphors notwithstanding, 2016 did bring some welcome news, as New York and Illinois approved zero-emission credits that will provide billions in additional revenue for Exelon’s James A. FitzPatrick, R.E. Ginna, Clinton and Quad Cities plants — assuming the state plans withstand legal challenges. Korsnick also talked about “policy opportunities” for similar supports in Connecticut, Ohio, Pennsylvania and New Jersey. (See Connecticut Lawmakers to Draw Up Millstone Rescue Plan.)

The Tennessee Valley Authority’s 1,123-MW Watts Barr 2 went into service in June, the first new nuclear plant in two decades. Combined with South Carolina Electric & Gas’ Summer Units 2 and 3 and Southern Co.’s Vogtle Units 3 and 4 — which are expected to go into service by 2021 — the new plants will add 5,500 MW of nuclear capacity.

In addition, six proposed nuclear units received licenses from the Nuclear Regulatory Commission last year: Austin Energy, CPS Energy and NRG Energy for South Texas Project Units 3 and 4 (February 2016); Duke Energy Florida, for Levy Units 1 and 2 (October 2016); and Duke Energy Carolinas, for William States Lee III Units 1 and 2 (December 2016). This followed DTE Electric’s May 2015 license for Enrico Fermi Unit 3.

Last month, NuScale became the first company to apply to NRC for a small modular reactor (SMR) design certification. NuScale has its first SMR customer, Utah Associated Municipal Power Systems, and should be able to put plants into service by the mid-2020s, NEI said. “These are designs that use their smaller size to maximize safety and rethink how nuclear plants could be configured. They will offer flexibility in deployment and operation,” she said.

‘A Very Good Business Proposition’

Getting licensing approval isn’t easy or cheap. But the bigger challenge will be convincing regulators and financiers that nuclear plants can be built in the future without long construction delays and massive cost overruns — and that they can compete against combined cycle plants during a period of near-record low gas prices.

Nuclear power still provides almost one-fifth of U.S. electricity production. And it will certainly have a role for years into the future. Virtually all of the reactors in the U.S. have received license extensions to boost their lifespans to 60 years and some plants may seek another 20-year extension.

But with the expected loss of Pilgrim and Oyster Creek in 2019 and Diablo Canyon by 2025, the U.S. will have lost a net 2,800 MW since 2013.

“The static, top-heavy, monstrously expensive world of nuclear power has less and less to deploy against today’s increasingly agile, dynamic, cost-effective alternatives,” wrote Jonathon Porritt, former chairman of the U.K.’s now defunct Sustainable Development Commission, in the forward to the 2015 World Nuclear Industry Status Report.

“It may seem strange to think about the construction of more nuclear plants at a time of low natural gas prices and slow load growth,” Korsnick acknowledged. “But like other major infrastructure investments, it is critical to anticipate gaps with long-term planning and early investment.”

Korsnick defended cost overruns at the Summer and Vogtle projects, saying the first generation Westinghouse AP1000 models are providing “lessons learned” for future development and that “schedule challenges are not unusual.”

She cited as an example the placement of the 1,000-ton CA20 module in the AP1000. “It took over 15 hours to place it in position for Vogtle 3,” she said. “The same task took less than an hour for Unit 4.”

And thanks to a lucky circumstance — a lower cost of capital than assumed — Summer and Vogtle are “still a very good business proposition, and a better proposition than promised to the customer,” she insisted.

Yet one analyst in the audience noted that Toshiba — which purchased Westinghouse in 2006 hoping to capitalize on a nuclear “renaissance” — has indicated it is quitting the nuclear construction business because of its experience in its current projects. The company is expected this week to announce a write-down of as much as $6.1 billion to cover cost overruns — more than it paid for Westinghouse.

Korsnick responded with a glass-half-full view, noting the company has not indicated it will quit nuclear engineering or procurement.

The Long Game and Short Game

Korsnick said the industry must play “the long game and the short game” — both preserving existing capacity and ensuring the U.S. has the talent and infrastructure to remain a player in the future.

The 2016 World Energy Outlook from the International Energy Agency forecasts an 80% increase in nuclear power generation worldwide by 2040. But nearly two-thirds of the plants currently under construction are using Russian or Chinese designs — largely because the two countries are host to 27 of the 39 plants now being built.

What the U.S. industry could use is something like the carbon tax proposed by what The Washington Post called “senior Republican statesmen” including former secretaries of state George Schultz and James Baker III. Under the proposal, carbon would be taxed at $40/ton, with proceeds returned to citizens: about $2,000 annually in dividends for a family of four, the group says.

Policy Initiatives

Even supporters of a carbon tax don’t expect it to happen any time soon, however. As a result, the industry’s best near-term hope may be to seek support for additional revenue streams in recognition of its lack of carbon emissions, as the states have begun to do, or its “resiliency” value — nuclear plants’ ability to run for more than a year without refueling; the price hedge it provides as an alternative fuel against a natural gas price spike.

NEI pointed to FERC’s actions to improve price formation. “Accurate price formation in the energy markets is particularly important, because a baseload nuclear plant derives most of its revenue from the energy markets,” Korsnick said.

The group is also looking to RTOs such as PJM, which is planning to release a white paper on resiliency in March that should provide encouragement to the industry. The PJM effort, like New England’s Integrating Markets with Public Policy initiative, is an attempt to get ahead of, or at least catch up to, states looking to take action.

Jobs

For state legislators and regulators, the appeal of retaining an at-risk nuclear plant goes beyond climate change concerns.

According to NEI, a two-unit plant creates the equivalent of 1,000 jobs for 60 years. “When a nuclear plant closes because the markets do not fully value the services they provide, the negative economic consequences of these shutdowns cascade. In many areas, the local nuclear power plant is the economic anchor of the community.”

The 2014 shutdown of Entergy’s 630-MW Vermont Yankee pinched the economy of Vernon, Vt., a town of 1,200, with housing prices and sales in the region falling.

Entergy had paid about $1.1 million in annual property taxes to Vernon, nearly half the town’s tax revenue. Entergy’s “tax stability payments” to aid the transition ratchet down before ending after 2022.

Dominion’s Kewaunee plant had provided $350,000 in annual utility tax revenues for Carlton, Wis., more than half of its budget. The closure of the plant triggered a tax hike on residents and a fight over the tax assessment of the 900-acre plant site on Lake Michigan.

New Role for Nukes

While the industry seeks to prevent more plant closings, it also is looking at changing its role to complement intermittent renewables.

“Some [plants] will make electricity around the clock. Others will produce electricity when it’s needed, then produce other products when it is not,” Korsnick said. “Some will supply the transportation market. Nuclear electricity will charge batteries, and nuclear process heat will make alternative fuels. Some reactors will make fresh water. Some will drive industrial production. Some reactors might even produce energy from today’s used fuel, reducing the disposal burden.”

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PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — PJM’s Jen Tribulski explained the rulemaking implications of FERC’s lack of quorum at Wednesday’s Market Implementation Committee meeting, using the RTO’s seasonal capacity proposal as an example.

In January, PJM filed a response to questions from the commission. “The response resets the 60-day time clock for that proceeding,” Tribulski said.

If FERC doesn’t act by March 24, the proposal will go into effect and be implemented for the Base Residual Auction in May. The commission, which was already shorthanded with two open seats, lost its quorum when former Chairman Norman Bay resigned Feb. 3. However, in one of their last actions before Bay left, the commissioners issued delegation authority to staff.

That gives staff several alternatives “to keep that rate before the commission review instead of letting it go into effect by law,” Tribulski explained. One of those options is letting the rules go into effect but suspending their implementation, she said. That suspension can last up to five months.

Later, staff gave updates on several other FERC matters impacted by Bay’s resignation, including a Notice of Proposed Rulemaking on uplift, implementation of Order 831, which doubles the “hard” offer cap for day-ahead and real-time markets to $2,000/MWh, and the commission’s rulings on fuel-cost policies and financial transmission rights allocations and forfeitures.

Meter Correction Initiative OK’d

Stakeholders approved by acclamation a problem statement and issue charge proposed by the North Carolina Electric Membership Corp. that could result in a monthly meter correction for pseudo-tied generation and dynamic schedules. The intent is to develop a process through which the unit owner’s calculation for the amount of power that flows over its pseudo-tie can be aligned with PJM’s calculation every month.

Unlike generators connected directly to the PJM system, there is no mechanism for meter correction at the end of the month for pseudo-tied generators and dynamic schedules, creating the risk of incorrect compensation, NCEMC said.

The proposal that had initially been introduced focused only on pseudo-tied generation, so American Municipal Power’s Ed Tatum questioned how dynamic schedules would be treated. “Is there a thought we’d be treating dynamic schedules like pseudo-ties?” he asked.

PJM’s Ray Fernandez acknowledged that the RTO is “trying to treat them in a manner as pseudo-ties” but said it was seeking the approval so the Market Settlement Subcommittee could begin analyzing it.

PJM Looking to Avoid Lump-Sum Billing on New Black Start Units

The RTO is working with the Independent Market Monitor to develop a consensus proposal on annual revenue requirements for new black start units, PJM’s Tom Hauske said.

“The whole intent here is we’re trying to minimize the billing impact on the load from having this new unit come in,” he said.

The collaboration received support from members. “I like when you guys get together and talk, so thanks,” Old Dominion Electric Cooperative’s Steve Lieberman said.

“As [a load-serving entity], our guys are getting tired of getting hit with these big lump sums,” Tatum said.

The collaboration has resulted in the addition of a new design criteria concerning fuel tanks at the request of Monitor Joe Bowring. All oil-fired generating units have a “minimum tank suction level”. PJM’s accounting method would allow for recovery of fuel storage costs for the full tank’s minimum suction level, but the black-start unit only requires a small fraction of that. Bowring’s proposal would be to reduce the cost recovery to just the amount needed for the black start unit.

The IMM’s explanation of how minimum tank suction level should work for black-start units

GT Power Group’s Dave Pratzon argued that discussion was out of the scope of the revenue requirements. “We’re not talking about changing the cost components,” he said. “It’s totally worthy of discussion, but it shouldn’t be in this because it’s going to delay customers getting the black start they need.”

Calpine’s Dave “Scarp” Scarpignato agreed.

Reviewing new black start unit revenue requirements is an annual process that happens every May, Hauske said. The determinations go into effect on June 1. There’s only one unit currently having its costs reviewed, he said, but PJM plans to offer an RTO-wide request for proposals for new units at the end of the year. The last such RFP added 20 units, he said, but PJM expects about three this time. (See PJM: Black Start Sources Ready to Replace Retiring Coal.)

No New IARRs this Year, but Con Ed’s to be Redistributed

PJM’s annual analysis found that there are no incremental auction revenue rights to be awarded this year, PJM’s Xu Xu said. However, with Consolidated Edison terminating its PJM membership, the company’s IARRs need to be reallocated by May 1.

IARRs are awarded when regional or lower-voltage facilities are upgraded after the annual ARR process is completed.

PJM’s Tim Horger said the reallocation of Con Ed’s IARRs will be based on the Schedule 12 regional cost allocation process. “It will be a small value, but it’s a value that has to be reallocated,” he said. “Everyone will automatically get another slice of the ARRs with Con Ed gone.”

– Rory D. Sweeney

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MISO Market Subcommittee Briefs

CARMEL, Ind. — MISO Executive Director of Market Design Jeff Bladen called FERC’s recent storage order “very narrow in its focus” but that staff does not mind the sparse specifics.

The RTO is grateful that FERC didn’t order it to develop new market products or services, Bladen said. (See MISO Ordered to Change Storage Rules Following IPL Complaint.)

Another benefit: The order’s lack of detailed directives will allow MISO to continue its stakeholder-guided work on incorporating storage into its market.

“We certainly see this as aligned with our core guidelines,” Bladen said at a Feb. 9 Market Subcommittee meeting. He didn’t see the order requiring fundamental changes and didn’t think it would be difficult for the RTO to create a compliance filing (EL17-8).

In response to a question from Xcel Energy’s Kari Clark about whether MISO could implement new market rules within 60 days, Bladen said the window to submit a compliance filing is not a target for putting rules in place but a deadline to explain the RTO’s plan of action.

Bladen also doesn’t anticipate that the RTO’s compliance filing would be at odds with future directives stemming from FERC’s recent Notice of Proposed Rulemaking on storage (RM16-23, AD16-20).

Five-Minute Settlements BPM due in Summer

MISO is drafting Business Practices Manual language implementing five-minute settlements to share with stakeholders by early summer.

In its Jan. 11 compliance filing, required by FERC Order 825, the RTO requested a March 1, 2018, implementation date for aligning settlement calculations with dispatch and pricing intervals, seven weeks after the order’s projected date (ER17-778). John Weissenborn, MISO’s director of market services, said the additional time is needed for “extensive software development and testing.”

“We are working on developing some key milestones and project planning,” added Weissenborn.

Under the revisions, MISO will settle excessive and non-excessive energy market trades, price volatility make-whole payments and real-time revenue sufficiency guarantee (RSG) make-whole payments on a five-minute basis. Weissenborn said some real-time settlements, like asset energy and net inadvertent distribution, will remain hourly. MISO also said it has been compliant with an Order 825 requirement for 15-minute interval interchange transaction settlements since mid-2015.

Weissenborn said the Tariff filing changes several mentions of “hourly” to “dispatch interval.”

“We believe we are in compliance. If we’ve missed something, we’ll file again,” he added.

Bladen said MISO is “moving ahead with the implementation. … We’ll be ready in March, barring something completely unforeseen.”

Natural Gas Price Hike Raises December Energy Prices, RSG Payments

Higher gas prices drove systemwide average energy prices above $30/MWh across MISO in December, a 22.4% upsurge from November.

The $3.59/MMBtu average price in December was up 45% from November and 91% from December 2015.

MISO said the impact of high fuel prices on real-time energy price was mitigated “to some extent” by higher wind output and more resources back online after planned outages in the fall. However, the high gas prices led to “disproportionate increases” in RSG payments during the month, the RTO said.

Total real-time RSG make-whole payments totaled $7.1 million in December, a three-fold increase from November. Day-ahead RSG payments hit $6.5 million. MISO said most of its day-ahead payments were made to voltage and local reliability resources in MISO South, where emergency conditions in load pockets were declared on multiple days in early December.

miso market subcommittee energy storage

During a Feb. 3 Markets Committee of the Board of Directors meeting, Independent Market Monitor David Patton said the high RSG payments were not unusual.

“When we see higher real-time prices rise, we see uplift and revenue sufficiency guarantee rise even faster,” Patton said.

December saw a 99.9-GW load peak, higher than December 2015’s 87.1-GW peak, Vice President of System Operations Todd Ramey said. Load averaged 76.9 GW for the month.

Total wind energy production in December was 5,687 GWh, the highest value ever recorded for MISO. Wind represented about 11% of the RTO’s total energy output for the month.

— Amanda Durish Cook