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November 5, 2024

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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

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PJM Planning Committee and TEAC Briefs

Endorsements Sail Through by Acclamation

VALLEY FORGE, Pa. — Stakeholders moved quickly through PJM’s requested endorsements at Thursday’s Planning Committee meeting, approving all three by acclamation. In addition to largely administrative updates to Manual 22, the committee endorsed:

  • The sunsetting of the Earlier Queue Submittal Task Force, whose Tariff revisions went into effect on Nov. 1. The revisions allow PJM to start feasibility studies sooner and allocate review and study costs to interconnection customers rather than socializing them. “The big problem is that there were [project] requests that were deficient at the end of the window … that’s what was bleeding into the feasibility window,” PJM’s Andrew Gledhill explained. (See “Stricter Standards OK’d for Project Queue Submittal,” PJM Markets and Reliability Committee Briefs.) James Manning of the North Carolina Electric Membership Corp. supported the changes but requested that there be a “feedback loop” to ensure the rule changes are successful in incenting customers to file their requests sooner. PJM said it would provide updates.
  • Exempting certain transmission substation equipment from competitive bidding. Brenda Prokop of ITC Holdings thanked PJM staff for making sure the revisions got completed.

PPL Removing Jenkins SPS

PPL’s Jenkins special protection scheme, which was installed to protect against overloads on the Susquehanna-Jenkins 230-kV line, is being removed because the line is being rebuilt. The line will be out of service from March through December.

Planning Coordination with MISO Improved

PJM and MISO filed joint operating agreement revisions for the targeted market efficiency project process with FERC on Dec. 30, PJM’s Chuck Liebold said.

pjm planning committee transmission expansion advisory committee

“That was a big need. That should be a very beneficial change to expedite the analysis,” Liebold said. “In the past, it has taken months and months to put together an interregional case.”

Previously, PJM and MISO used incompatible analysis criteria. “Now we can go after any type of project on our border and go after whatever is truly the most cost-efficient project,” he said.

Stakeholders asked why there wasn’t a common interregional model. Liebold explained that FERC set it up so that interregional planning is developed from each RTO’s regional planning process, so it would be impossible for them to be the same.

“We’re not disputing MISO’s assumptions or MISO’s processes. … If their stakeholders have decided that’s the basis on which to go forward on a particular study, they can do that. … I think our responsibility is to make sure … that we come up with the best solution that satisfies the [needs] on both sides,” Liebold said.

Transmission Expansion Advisory Committee

New Proposal Shaves $78M from PSE&G Switch Fix

PJM told the Transmission Expansion Advisory Committee it has developed an alternative solution to address the fire hazard at Public Service Electric and Gas’ Newark transmission switch that would cost $275 million, saving $78 million from a proposal outlined previously.

Planners said the switch is considered at the end of its life and failure to replace it could result in a fire that could engulf the substation, which was built in 1957.

A fire would threaten a nearby school and healthcare facility as well as possibly cut service to 300 MVA of load, including Newark City Hall, Rutgers University facilities, Prudential Center, several data centers and two train lines.

A proposal outlined last August called for building a new gas-insulated switch station adjacent to the existing switch at a cost of $353 million.

The new proposal modifies the scope and layout, reducing constructability concerns. PJM said it would save $18 million in direct costs and $60 million in risk contingency expenses. It would be fully energized by June 2021.

PJM Recommends Spending $10M to Correct AEP Voltage Problem

PJM said it is recommending installing 300-MVAR reactors at American Electric Power’s Ohio Central and West Bellaire 345-kV substations at a cost of $5 million each. Planners said the reactors were needed to correct high voltages on the extra-high-voltage system in AEP’s service territory during light load conditions. PJM is targeting a Sept. 1, 2018, in-service date.

– Rory D. Sweeney

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Stakeholders, MISO at Odds over Resource Adequacy Survey

By Amanda Durish Cook

CARMEL, Ind. — MISO is looking to improve its annual resource adequacy survey by expanding the scope of potential projects included in the report, but some stakeholders are still questioning the survey’s credibility.

MISO resource adequacy survey
Landstrom | © RTO Insider

The survey — a joint undertaking between MISO and the Organization of MISO States — tracks resource adequacy through reports made by load-serving entities. The 2016 survey forecasted a possible capacity shortfall in the RTO by 2018. (See OMS-MISO Survey: Generation Shortfall Possible.)

The RTO wants to include more potential future resources in the survey’s regional and zonal weighted averages, Darrin Landstrom, MISO’s resource forecasting adviser, said during a Feb. 8 Resource Adequacy Subcommittee meeting.

Landstrom said the survey currently counts only future resources that have already executed a generator interconnection agreement. The RTO is also considering rolling a 35% share of the capacity from resources sitting in the definitive planning phase of the interconnection queue into the survey’s low-certainty resource total.

Using a sample of natural gas projects entering the queue in 2012, 37% failed after entering the definitive planning phase, while 26% ultimately executed generator interconnection agreements. According to Landstrom, the sample left MISO with a possible percentage somewhere between a conservative 26% success rate to a best-case 63% (assuming every project that enters the definitive planning phase will sign a GIA).

MISO’s use of the 35% value in the 2017 survey would be re-examined next year after the RTO completes the launch of its new queue process.

The RTO had additionally considered the idea of including in the survey projects in the system planning analysis stage of the interconnection queue, active projects in the queue that have yet to sign interconnection agreements and planned projects not yet in the queue.

Some stakeholders argued that the 35% figure was arbitrary.

“Ultimately, the OMS-MISO survey is a range of possibilities,” responded Laura Rauch, MISO manager of resource adequacy coordination.

Asked by RASC Chair Gary Mathis whether the proposal had OMS’s support, Bonnie Janssen of the Michigan Public Service Commission responded that the proposal largely represented the RTO’s work.

While stakeholders expressed concern that no planned resources in the definitive planning phase make it into the survey’s high-certainty category, Landstrom pointed out that projects in the definitive planning phase with generator interconnection agreements are counted among high-certainty resources.

Rauch said MISO does not want to imply that planned projects are “a done deal” by assigning them high-certainty designations. She said the move could send the wrong signal to state regulators, who might reject other projects because they assume the likelihood of a planned project included in the survey with high-certainty status.

Wisconsin Public Service’s Chris Plante said MISO might be able to issue information without editorializing by discontinuing high- or low-certainty designations, which some stakeholders think gives the survey a conservative bias that suggests a resource adequacy problem.

Mathis contended that people tend to pay attention to what’s high-certainty rather than low-certainty.

“Is the load growth in the survey high-certainty?” he jokingly asked.

Rauch said that while MISO is focused on signed and committed projects, the survey could concentrate more on a range of possibilities.

In filings made last year to oppose MISO’s retooled auction design, the Coalition of MISO Transmission Customers and the Illinois Industrial Energy Consumers said the survey does not give a “complete reflection of the future capacity needs in the MISO region.” Stakeholders also questioned why last year’s capacity auction results showed a larger surplus than the survey results for a second year in a row.

Jeff Bladen, executive director of market services, said MISO “remains confident” that the survey is the best forward-looking predictor of resource adequacy.

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Modest Optimism, Lingering Questions at Tx Summit

By Wayne Barber

WASHINGTON — Modest optimism about the Trump administration’s infrastructure plans was tempered with questions about leadership at FERC and other federal agencies at a gathering of transmission developers, RTO officials and environmentalists last week.

The first National Electric Transmission Infrastructure Summit, held Feb. 9-10 by Americans for a Clean Energy Grid, also heard concerns over how to pay for grid modernization in a time of anemic load growth. The organization, an initiative of the Energy Future Coalition, has held regional transmission conferences, but this was its first national event.

The coalition was formed in 2002 by former Sen. Tim Wirth, a Colorado Democrat; Republican C. Boyden Gray, who served as White House counsel to President George H.W. Bush; and Democrat John Podesta, a former aide to Presidents Bill Clinton and Barack Obama who chaired Hillary Clinton’s 2016 presidential campaign.

Lack of Load Growth

Glazer | © RTO Insider

“I’d love to have more load growth. It ain’t going to happen,” Craig Glazer, PJM’s vice president for federal government policy, told the gathering.

Weak load growth will make it more complicated to finance upgrades for aging transmission, and the lack of a federal carbon tax or renewable mandate is making it difficult to integrate renewable generation, Glazer said.

Much of the current grid was built during the 1950s, 60s and 70s, with the deployment of coal and nuclear power plants, said ITC Holdings Executive Vice President and COO Jon Jipping. Now that many of those big baseload stations are being retired, much of the new generation — mostly natural gas or renewable energy — is in different locations that require new transmission, Jipping noted.

From the podium and on the sidelines, speakers said that while they like the Trump administration’s pro-growth rhetoric, they are also anxious to see FERC restored to full strength and who will be the key lieutenants to energy secretary nominee Rick Perry.

Speakers also cited concerns over cost allocation, regional planning and the shortcomings of FERC Order 1000.

Wade Smith, senior vice president of grid development for American Electric Power, said his company has made transmission a higher investment priority than generation in recent years as it focuses more on regulated utility operations.

Modernization is needed because much of the AEP grid is 70 years old, and yet it integrates 9,000 MW of wind, Smith said.

While much of the U.S. electric transmission system was built in the mid-20th century, the infrastructure components are inspected every year, said Rudy Wynter, National Grid’s president of FERC-regulated businesses. The grid was built in big chunks and it will largely be rebuilt in large chunks, Wynter said. This includes not only renewable integration but also preparing for more electric vehicles and offshore wind power, he added.

Siting Authority

During one session, SPP CEO Nick Brown was interviewed by former FERC Chairman James Hoecker, now senior counsel for WIRES Group, which represents transmission developers and utilities. Hoecker stressed the importance of adding three commissioners to get FERC back to full strength. With only two commissioners since the Feb. 3 resignation of former Chairman Norman Bay, FERC lacks a quorum. (See FERC OKs Pipelines, Delegation Order Before Losing Quorum.)

Hoecker (left) and Brown | © RTO Insider

Hoecker and Brown discussed FERC’s inability to gain “backstop” siting authority, saying it’s still very difficult to prevent individual states from blocking a project. The Energy Policy Act of 2015 amended the Federal Power Act to give FERC the authority to site electric transmission lines blocked by states, but court rulings have blocked the commission’s attempts to use it, prompting some in Congress to propose additional legislation strengthening FERC’s authority.

Brown said that Order 1000 hasn’t really helped SPP much with large regional projects.

“We need to decide what we want this grid of the future to look like,” Glazer said. For example, should it be a “localized grid” that can harness distributed generation? he asked. “There’s an added complication; it’s not even clear who is in charge,” Glazer said. FERC, state utility commissions and governors all have a say in siting decisions, he said.

If each governor is asked what infrastructure projects they want, the country will end up with a lot of state-based projects, not interstate ones, Clean Line Energy Partners President Mike Skelly said.

Perhaps the new mantra is “we’re going to make transmission great again,” Skelly said. The power to select infrastructure projects should not be taken away from transmission planners and placed in the hands of Congress, he said.

Skelly and others cautioned the Trump administration not to skimp on project reviews or stakeholder input. The key is that all projects must have “timelines” for regulatory approvals to avoid infinite delays, he said.

The executive director of the AFL-CIO’s Industrial Union Council, Brad Markell, said the labor movement agrees with the need for “hard timelines” to shorten the permit process.

Markell said that labor unions have been in contact with the Trump administration on potential infrastructure efforts.

“From our point of view, more power for the federal government and less power for the states [on electric infrastructure] would be a good thing,” he said.

Others deemed that unlikely. “I think we’re stuck with the system we have,” Glazer said.

Environmentalists Weigh In

Liese Dart, senior energy advisor for The Wilderness Society, said her organization favors prescreening certain public lands for development suitability.

Hitt | © RTO Insider

Mary Anne Hitt, executive director of the Sierra Club’s Beyond Coal campaign, said that — contrary to what conference participants may have heard — her organization doesn’t oppose all power lines, only those that appear aimed to “prop up fossil fuels.”

The environmental group opposed the abandoned “coal by wire” Potomac-Appalachian Transmission Highline (PATH) project in PJM. On the other hand, it has backed the Plains and Eastern Clean Line Project, designed to move renewable energy from Oklahoma to Tennessee.

Hitt said she was concerned that President Trump’s nominee for EPA administrator, Scott Pruitt, opposed Clean Line in 2015 as Oklahoma attorney general.

Hitt also said the Sierra Club has concerns about the Gateway West project, a proposal by PacifiCorp and Idaho Power to build about 1,000 miles of high-voltage transmission through Wyoming and Idaho. She said PacifiCorp has been slower than some Western utilities in reducing its coal use and slower than the Sierra Club would like in expanding its renewable resources.

Grid Security

When it comes to protecting the grid, Brown said much of the discussion seems to be centered on preventing cyber intrusions. Perhaps the discussion should be less about how to keep cyber intruders out than to minimize the damage and restore order once they disrupt the system, the SPP official said, likening the approach to “insurance.”

But he said winning regulatory approval for equipment such as spare transformers may be difficult.

“I believe we are going to have to spend much more money on spare equipment, and that’s going to be tough to sell,” Brown said. “We are unwilling to spend that kind of money for spare equipment because it is not ‘used and useful.’”

SPP Chief Reticent on Mountain West

Brown declined to reveal much about the status of the Mountain West Transmission Group’s discussions about joining SPP.

Mountain West, a partnership of seven transmission-owning entities within the Western Interconnection, revealed the discussions in January. It said if the talks with SPP are not successful, it would likely explore joining another RTO. (See Mountain West to Explore Joining SPP.)

In response to a question about whether Mountain West was attracted by SPP’s cost-allocation system, Brown replied, “You’d have to ask them.”

“We’re excited about it,” Brown said of the talks, before cautioning, “Nothing is signed.”

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MISO South-to-Midwest Transfer Limit Upped for 2017/18 PRA

By Amanda Durish Cook

CARMEL, Ind. — MISO’s South-to-Midwest transfer limit for the 2017/18 Planning Resource Auction will be 1,500 MW, an increase of more than 600 MW over last year’s auction because of a decrease in firm export and wheel-through reservations. The limit reflects the 2,500-MW cap prescribed by MISO’s settlement with SPP, reduced by 1,000 MW of reservations.

MISO is modeling two sub-regional resource zones for the 2017/18 PRA: MISO South (local resource zones 8, 9 and 10) and MISO Midwest region (zones 1-7).

The Midwest-to-South limit for the 2017/18 PRA will hold at 3,000 MW, with zero reservation offsets.

The RTO had previously predicted a 984-MW South-to-Midwest limit and a 3,000-MW Midwest-to-South cap. (See MISO to Use Same Sub-Regional Limit Rules for 2017/18 PRA.)

Aligning Attachment Y Process with PRA

miso transfer limit planning resource auction pra
Reddoch  | © RTO Insider

MISO is looking to align its Attachment Y retirement process with the PRA timeline, implementing a recommendation from the Independent Market Monitor’s 2013 State of the Market Report.

At the Feb. 8 Resource Adequacy Subcommittee meeting, MISO adviser Joe Reddoch said the RTO is considering extending a cancellation period offered to retiring resource owners to align with the release of the upcoming PRA results to give owners a limited window to change their minds regarding retirement.

The Monitor recommended improving the alignment of the PRA and the retirement process so that a unit that has filed retirement plans can defer the retirement date if it clears in the auction. It also said system support resource (SSR) units should retain their interconnection service after their contracts end to allow the “broadest possible participation” in the PRA.

Reddoch said MISO has not yet settled on the length of the cancellation window extension.

The RTO is also contemplating removing the distinction between suspension and retirements in favor of a single deactivation status, Reddoch said. The change would eliminate “conflict between documented plans and the owners’ actual intentions,” he said. The change would simplify the process between temporary, uncommitted shutdowns and pending retirements, according to MISO.

RTO officials said the change would reduce uncertainty in planning processes, with baseline reliability projects being reprioritized if not needed because of a later rescission. Upgrades needed for new generation interconnections would be determined by the known plans of retiring generators.

The issue will be discussed at the Feb. 15 Planning Advisory Committee meeting and referred to the Steering Committee for assignment to a parent committee, Reddoch said.

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CAISO Takes First Stab at Defining Frequency Response Market

By Robert Mullin

CAISO’s first pass at soliciting stakeholder input on its primary frequency response product initiative generated a wide-ranging discussion about an obscure but increasingly important aspect of the ISO’s operations.

“We know that [primary frequency response] is important to your fundamental role as a balancing authority, and currently there are no financial incentives to provide this critical service,” Alex Morris, director of policy and regulatory affairs at the California Energy Storage Association (CESA), said during a Feb. 9 presentation to a stakeholder working group convened to lay the foundation for a market proposal.

caiso frequency response
CAISO is seeking to develop a market mechanism to compensate resources for responding to frequency dips during the “primary” control horizon — just moments after the onset of the event.

“And I don’t mean to be trite, but what we’re seeing from the data is that it’s no longer workable to assume the primary frequency response service will be provided — quote — ‘for free,’” he added.

Inertial Response

By “free,” Morris was referring to the fact that grid operators have benefited from the “inertial” frequency response capability inherent in the operation of most conventional generators, which can automatically vary their turbines’ rotational speed and output based on the pull of load, functioning as a damper for frequency excursions on the grid.

Nonconventional technologies such as wind and solar resources have little or no inertial response to momentary changes on the grid. Late last year, FERC proposed revising pro forma generator interconnection agreements to require all newly interconnecting facilities, including renewable generators, to have primary frequency response capability (RM16-6). (See FERC: Renewables Must Provide Frequency Response.)

“It’s probably been great that for many decades [frequency response] came along as part of the generation fleet for free and that’s how it worked, but unfortunately we’re in a different era with a different grid and we need to wrestle with this problem,” Morris said.

NERC reliability standard BAL-003-1.1, which was phased in between November 2015 and last April, requires each balancing authority area (BAA) to carry sufficient capability to respond to a frequency event. Meeting that requirement will become increasingly difficult as California’s 50%-by-2030 renewable portfolio standard drives increased penetration of renewable resources.

The NERC rule requires BAAs to respond to a deviation within about 20 to 52 seconds of occurrence. That rapid reaction requires a resource to automatically detect under-frequency and autonomously ramp its output without receiving a market signal or manual instructions from the ISO.

Procurement Needed

An issue paper published by CAISO in December laid out the ISO’s deteriorating frequency response performance in recent years and raised the alarm of further declines. (See CAISO Seeks Primary Frequency Response Market.)

“Without explicit procurement of primary frequency response, the ISO cannot position our fleet in a way that will provide sufficient frequency response,” said Cathleen Colbert, senior market design and regulatory policy developer at CAISO. “We need to also mitigate the risk of noncompliance” with the NERC standard.

For the current compliance period, the ISO issued a competitive solicitation to external BAAs to essentially procure an adjustment on its frequency response reporting. (See FERC Accepts CAISO Contracts for Imported Frequency Response.)

“We’re concerned about continuing to rely solely on procuring this adjustment in the long term,” Colbert said. Instead, CAISO seeks to provide internal generators with the ability to compete against external BAAs to provide the service.

In his presentation to the working group, Morris sketched out a preliminary proposal in which the ISO would develop a product that would incentivize frequency response capability and performance while compensating resources for their opportunity costs — for example, forgone energy market revenues.

Under the plan, the CAISO day-ahead and real-time markets would solve for current constraints and products while also reserving capacity from resources capable of providing primary frequency response. The market would compensate those resources for the service, as well as the energy injected during a frequency deviation event, similar to the energy settlement for regulation service resources that follow a dispatch order.

Regulation Service

“I thought that regulation was simply a zero-energy service,” said Mark Smith, vice president of government and regulatory affairs at Calpine.

George Angelidis, a principal at CAISO, explained that the energy a regulation service provider gives and takes from the grid should, in theory, sum up to zero, which is why regulation is considered a control service rather than an energy service.

“But there’s a capacity behind it, and through the energy provision, you provide the control service, but the expectation is that over a long period of time it’s more or less a zero-energy service,” Angelidis said.

“The general high-level view is that this resource is sitting at the ready — [and] frequency drops,” Morris continued. “The resource autonomously bursts out energy to provide the primary frequency response. In so doing, it’s giving energy to the grid. It may be appropriate to compensate [the resource] for the energy it gave to the grid.”

Biddable or Not?

Morris acknowledged that he avoided taking a position on whether frequency response provision should be biddable in the market on a standalone basis.

“I think as long as it’s being solved for inside the market — it’s co-optimized among the many other constraints in the market — then the opportunity cost of providing this service is then reflected,” Morris said. “So there would be some element of payment for providing this service, whether that’s just an opportunity cost, if any, or not.”

Jan Strack of San Diego Gas & Electric questioned the effectiveness of a “non-biddable” solution.

“The issue is, if you don’t have a bid, I think the market has no ability to select,” Strack said. “Which [resource] would it select? There’s no way to know. So I think you inevitably end up with a capacity offer situation just like you do with regulation.”

“I hear you,” Morris responded. “But I also think just the information about the energy costs will inform the optimization, similar to how with the [CAISO] flexible ramping product you can bid your flexible ramping capability for zero dollars, but you also have an energy bid, so [the market] knows if you have an opportunity cost.”

Smith wondered whether a generator that did not receive an award would be allowed to disable its frequency response capability, as it would automatically respond to an event.

“Basically, we make sure that you provide the service all the time, but if while you provide the service you suffer a lost opportunity cost for it, then you will be compensated adequately for it,” Angelidis said, adding that disabling that capability could run “contrary” to a generator’s interconnection agreement.

In comments filed with CAISO, Seattle City Light — which currently provides the ISO with transferred frequency response under a yearlong contract — said it hoped the ISO would develop a market mechanism that would allow transferred capability to compete with internal resources.

Mike Benn, energy trade policy analyst at Powerex, backed up City Light’s position.

“We’re supportive of what CESA said to co-optimize the procurement of frequency response in real time, but we think there would be a gap there and we’d like a forward procurement mechanism as well, similar to the [resource adequacy] construct,” Benn said. “So you could go out and procure on a year-ahead basis, and then they could procure from internal [resources], or they could also go and procure from external BAs.”

The “gap,” according to Benn, stems from the fact that short-term procurement of frequency response won’t guarantee resources will be available on a given day and might be insufficient to spur development.

“The transferred response from external BAs is a yearly product,” Benn said. “So in that way, when you get to real time, you’ve guaranteed that the resources are available.”

Benn pointed out that the absence of a forward procurement option would exclude the participation of external resources because NERC’s frequency response reporting requirement is based on an annual obligation that cannot be transferred on a daily basis. FERC recognized this fact on Feb. 2, when it approved the terms of CAISO’s transferred frequency response contracts with City Light and the Bonneville Power Administration. (See FERC OKs CAISO Frequency Response Contract Terms.)

“I think the two processes — a market mechanism and a transferred frequency response mechanism — aren’t mutually exclusive, and it’s probably good to think about them in that sense,” said Andrew Ulmer, CAISO director of federal regulatory affairs. “From a relatively non-engineering, non-market design perspective, I think of both as insurance mechanisms.”

CAISO has asked stakeholders to submit comments on the primary frequency response initiative by Feb. 23. A second working group meeting on the issue will be held on a date yet to be determined.