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December 24, 2024

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NERC Offers Upbeat Long-term Assessment

NERC Offers Upbeat Long-term Assessment

By Rich Heidorn Jr.

NERC offered a mostly upbeat report on the long-term health of the nation’s grid Thursday, celebrating results from its first interconnection-wide frequency response studies while highlighting the need to model the increasing volume of distributed resources and supplement variable generation with ramping resources.

The 2018 Long-Term Reliability Assessment, NERC’s 10-year outlook for the North American bulk power system, found that frequency response will remain adequate through 2022 despite the loss of synchronous generators and the increase in inverter-based renewables.

“That gives us some confidence in the resource mix and also the ability to … see whether that performance is degrading out in the future — which is really important, so that if there are issues, you can put [in] policies or build new resources,” said John Moura, director of reliability assessment and system analysis, during a press briefing on the report.

Moura noted that FERC Order 842, issued in February, requires all new resources seeking interconnections be able to provide frequency response, calling the requirement “really, really important for reliability.” (See FERC Finalizes Frequency Response Requirement.)

The report said dynamic stability analysis showed both the Eastern and Western interconnections’ generation “sufficiently supports frequency after simulated disturbances despite reductions in inertia” from the loss of synchronous generation. It said ERCOT has operational procedures to address risks from “degraded inertia.”

“My optimism is not only based on the current mechanisms in place but the ability of the industry to respond and adapt to the changes. And so, while today we don’t have really what I would call excellent frequency response modeling capability, we’ve got pretty good [capability]. We’re able to see it,” Moura said. “And I have confidence that we’ll be able to have that excellent frequency response model in by the time we really need it.”

Load & Reserves

The report predicts North America will see compound annual load growth of only 0.57% for summer and 0.59% for winter, with five areas — New York, New England, the Maritimes, Manitoba and the California-Mexico region (most of California and a northern sliver of Baja California) — expecting reductions in peak demand. The fastest growing regions are ERCOT and the Rocky Mountains region of the Western Electricity Coordinating Council, both projected to grow about 1.8% annually.

The report did identify concerns, noting that ERCOT’s anticipated reserve margins are below targets for the next five years, with MISO and Ontario foreseeing reserve shortfalls beginning in 2023. (See ERCOT Predicts Tight Reserve Margin for 2019.) But it said the shortfalls could be filled by accelerating construction of additional Tier 2 resources — those that have met milestones such as completing feasibility, system impact or facilities studies.

The report includes new probabilistic evaluations — loss-of-load studies that evaluate all hours of the year — which found the California-Mexico assessment area of WECC at risk of 2.3 loss-of-load hours in 2022, with an expected 152 MWh of unserved energy. “These are not significant numbers … but it’s a faint signal that tells us about risk that may not be occurring in the peak hour,” Moura said.

Following Florida, California

The report projects 100 GW of new generation in the next decade, including about 41 GW of gas and 60 GW of solar. ERCOT and the California-Mexico region expect gas generation to contribute more than 60% of on-peak capacity, while Florida expects gas’ share to rise from 70% to 80%.

“When you do have this level of natural gas resources, you have to plan differently,” Moura said. “There are things that, for example, Florida does that other areas may need to do in the future, such as procuring more firm gas … or ensuring we have more dual-fuel capabilities.”

California is leading the way in addressing reliability risks from increasing solar, with CAISO’s three-hour ramping needs hitting a record 14,777 MW last March and expected to rise to 17,000 MW by 2022.

“As solar generation continues to increase in California and elsewhere across North America, system planners should ensure sufficient flexible ramping capacity, including large-scale energy storage,” the report said.

More than 30 GW of new distributed solar PV generation is expected by the end of 2023, with California expected to reach 18 GW of capacity, almost 40% of its projected peak. New Jersey, Massachusetts and New York are projected to each have 3.5 to 4 GW of distributed solar by 2023.

“There’s more [distributed energy resources] coming online faster than we’ve really ever seen any type of resource coming on. … If that’s not represented in models, we’re going to be modeling the system completely inaccurately. And if we don’t have flexibility in our resources, we really won’t be able to meet the challenges of the daily demand curves,” Moura said.

“In areas that may not have a lot of DER, or only starting to get DER, it’s perhaps common for planning studies to negate them or net them out or mostly ignore them. However, as we get a larger penetration of DERs, it’s really important that their characteristics are modeled,” Moura said. “Engineers and planners need to prepare data specifications and data exchanges that are needed now so that we have a better understanding of what the system’s going to look like in the future.”

This fall, NERC created a new working group to guide its efforts: System Planning Impacts of DER (SPIDER).

Recommendations

Among the report’s recommendations was a call for NERC’s Reliability Assessment Subcommittee to lead development of common metrics to assess energy adequacy. “Additional analysis is needed to determine energy sufficiency, particularly during off-peak periods and where energy-limited resources are most prominent.”

Similarly, it urged NERC’s Planning Committee to develop a common framework for assessing fuel disruptions, saying “system planners should identify potential system vulnerabilities that could occur under extreme, but realistic, contingencies and under various future supply portfolios.” The assessments could be used to develop regulations or market mechanisms to promote fuel assurance.

“A common approach for what kind of contingencies to study would be very valuable to the industry,” Moura said.

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Enviros Seek McNamee Recusal in Resilience Dockets

By Rich Heidorn Jr.

FERC Commissioner Bernard McNamee told Senators at his November confirmation hearing that he would consult with ethics lawyers on whether he should recuse himself from the commisison’s resilience dockets. | © RTO Insider

Environmental groups asked Tuesday that new FERC Commissioner Bernard McNamee recuse himself from the commission’s resilience dockets because of his advocacy for coal and nuclear plants during his time at the Department of Energy.

The motion by the Natural Resources Defense Council, Sierra Club and Union of Concerned Scientists echoed concerns Senate Democrats expressed during McNamee’s confirmation hearing in November (RM18–1, AD18-7). McNamee was sworn in on Dec. 11 after winning confirmation on a 50-49 party line vote.

McNamee’s role in DOE’s Notice of Proposed Rulemaking and the agency’s second proposal, to save at risk generators under the Defense Production Act, “create the appearance that Commissioner McNamee has prejudged central matters of law and fact that remain at issue in these proceedings,” the environmental groups wrote.

As Deputy General Counsel for Energy Policy at DOE, McNamee signed the NOPR, which asserted that “[t]he resiliency of the nation’s electric grid is threatened by the premature retirements of power plants that can withstand major fuel disruptions caused by natural or manmade disasters.” The NOPR proposed eligible fuel-secure units within PJM, NYISO, MISO and ISO-NE receive “full recovery of costs,” including a return on equity, arguing wholesale pricing in organized markets “does not adequately consider or accurately value” resiliency benefits of fuel-secure generators.

McNamee also worked on DOE’s second proposal, which asserted that “retirements of fuel-secure electric generation capacity across the continental United States are undermining the security of the electric power system because the system’s resilience depends on those resources.”

The environmental groups cited a series of court rulings outlining the circumstances in which recusal is required. “Due process considerations require that an adjudicator `who participates in a case on behalf of any party, whether actively or merely formally by being on pleadings or briefs, take no part in the decision of that case by any tribunal on which he may thereafter sit,’” they wrote, quoting from a 1958 D.C. Circuit Court of Appeals ruling.

The groups also noted FERC’s rejection of the DOE NOPR (RM18-1) is still subject to rehearing request by the Foundation for Resilient Societies. “McNamee’s participation in these rehearing requests would violate the venerable prohibition against a man standing in judgment of his own cause, and due process,” the groups said, adding that McNamee also should recuse himself from the resilience docket the commission opened in January when it rejected the NOPR (AD18-7).

‘Same Factual Questions’

“The resilience docket therefore encompasses the very same factual questions that were answered by the department, and by Commissioner McNamee on behalf of the department, in the DOE NOPR: whether the grid is threatened by retirements of so-called `fuel secure’ power plants and whether and to what extent such `fuel secure’ resources are necessary to the reliability and resiliency of the grid… The mere technicality that the two proceedings have different docket numbers, where the substantive matters at issue are materially the same, does not make the resilience docket a sufficiently distinct matter for the purposes of the due process inquiry.”

The groups cited comments filed Dec. 6 by the Harvard Electricity Law Initiative, which also questioned McNamee’s impartiality. “His recusal must extend beyond these two dockets,” wrote Ari Peskoe, the director of the law project. “The NOPR’s sweeping conclusions prejudge issues that could appear before the commission in ratemaking proceedings. This prejudgment is substantially different from a commissioner’s public statements about policy issues, which the commission has recently determined were not a basis for recusal.”

In his confirmation hearing, McNamee said he would consult ethics lawyers on whether he should recuse himself from the resilience dockets. (See Democrats Urge McNamee’s Recusal from Resilience Docket.)

Democrats also were alarmed by comments McNamee made in a videotaped speech in February after briefly leaving DOE and working for a conservative think tank’s project to “reframe the national discussion” about fossil fuels. McNamee said renewables are disruptive to “the physics of the grid” and described environmentalists’ activism against fossil fuels as a “constant battle between liberty and tyranny.”

After the video became public, Sen. Maria Cantwell of Washington, the ranking Democrat on the Energy and Natural Resources Committee, questioned McNamee in writing about his comments, asking: “How can environmental groups possibly expect a fair shake from you as a FERC commissioner?”

McNamee responded: “I understand the difference between being an advocate and an independent arbiter.”

McNamee and FERC Chair Neil Chatterjee declined to comment on the recusal motion.

Comments Filed

McNamee replaced former Commissioner Robert Powelson, who joined in FERC’s 5-0 vote rejecting the DOE NOPR and opening the new resilience docket in January. The commission has received two rounds of comments in the new docket, including a June request by FirstEnergy for an emergency order to preserve fuel-secure generating resources. (See RTO Resilience Filings Seek Time, More Gas Coordination and Don’t Rush on Resilience, Commenters Urge.) The commission has given no indication of what it will do, if anything, in response.

The Trump administration reportedly dropped DOE’s second proposal this fall. (See Chatterjee Dodges as DOE Spins on Coal Bailout.)

But the resilience concerns the department raised haven’t gone away. On Dec. 17, PJM issued a report calling for payments for fuel-secure generation. (See Full PJM Study Makes Case for Fuel Security Payments.) On Dec. 18, NERC issued a warning that quicker-than-expected retirements of coal and nuclear plants could undermine reliability. (See NERC Releases ‘Stress Test’ Analysis of Gen Retirements.)

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GT Power Group’s Dave Pratzon Retiring

By Rory D. Sweeney

Dave Pratzon

It’s the end of an era at PJM: Following the Dec. 20 Markets and Reliability Committee meeting, GT Power Group’s Dave Pratzon will call it a career after 45 years.

Over that time, Pratzon has seen many of the biggest changes to the electricity industry from the trenches, having been involved in developing a number of the processes and rules that would eventually make up the grid and its markets as they are today.

“I care about the success of the enterprise. I want to deploy myself to the end,” said Pratzon, who turns 68 later this month.

A Fate-full Career

Pratzon describes his career as “an accident of fate,” or more accurately, a series of them, starting with how he got into the power business in the first place. While he went to college to become an electrical engineer, he spent his summers laboring at a local steel mill near his home in Wallingford, Conn. However, the job was threatened each year by union unrest or overproduction at the mill. He took the suggestion of a college friend from Philadelphia to join him in seeking summer employment with the Philadelphia Electric Co. (now PECO) and found himself working on substations.

Upon graduation, he attempted to land a full-time position at the utility, only to have the offer rescinded at the last moment. Scrambling, he found work near San Francisco as a field engineer for nuclear submarines. On a trip back East to propose to his  fiancée, Gail, and pick up a car,he happened to swing back through Philadelphia and stop in PECO’s offices.

“You got my letter!” a former supervisor said upon greeting the bewildered Pratzon.

“I’m just driving through,” he responded.

The boss said they were trying to contact him about a job opening and asked if he had time to interview.

“Sure,” Pratzon said, “as long as it’s today.”

The company’s response traveled faster to his West Coast home than he did.

“By the time I got there, there was the letter with my official offer,” Pratzon said.

He quit the submarine job, partially to move back closer to home but also because part of his job would have involved “sea trials” of the ships, and he realized he’s claustrophobic.

“I could never survive out there for a week or two under water in steel containers,” Pratzon said. “I was happy to come back. … It was kind of a step back to the East Coast that I figured would be another temporary position on my way back to New England.”

It would be his last major move.

“My wife and I, being New Englanders, thought this would be a temporary job before moving [back] up there, but 45 years later, we haven’t left yet,” Pratzon said.

Gail became a librarian and helped found the public library in their town, Lower Providence Township.

“Opportunities have come for both of us,” he said.

PJM Work

From his first day at PECO, Pratzon was heavily involved with PJM. PECO supplied PJM’s staff for the first several decades after its founding, and Pratzon worked for the grid operator from 1973 to 1991 before being transferred to PECO as a “broadening” assignment. He was the first secretary of PJM’s cost-development subcommittee in the mid-1970s and helped develop the initial market rules that he jokes PJM Independent Market Monitor “Joe Bowring may or may not like right now.”

Pratzon’s career was a period of change for both the industry and PJM, which began transitioning to an independent organization in 1993. In 1997, it opened its membership to non-utilities and elected an independent Board of Managers.

“The market was very different when it was just the eight companies dealing with each other,” he said, referring to PECO, Public Service Electric & Gas, Pennsylvania Power & Light, General Public Utilities (GPU), Baltimore Gas & Electric, Potomac Electric, Atlantic City Electric and Delmarva Power and Light.

The first major transition occurred during the Three Mile Island crisis, when plant owner GPU began searching for power supplies outside of the other seven utilities in PJM at the time. Up until then, the companies had bought and sold amongst each other with PJM determining which plants would run to provide all of the power necessary at the cheapest overall cost.

Each day, the companies would submit their projected costs to run each plant the following day. If one company’s plant would cost more to run the next day than those of other companies, PJM would dispatch the cheaper plant to cover the demand and charge the company with the more expensive plant half of the difference between the plants’ costs in an accounting method known as “split savings.”

But GPU’s alternative during the TMI crisis was combustion turbine plants, which were experiencing a crisis of their own during the oil shortages of the 1970s. Using the expensive CTs as the baseline cost under the split savings method would have cost GPU a fortune, so the company sought alternatives outside of the PJM ring. It was controversial and “unheard of at the time,” Pratzon said, at least partially because the other companies anticipated the profits they might make from GPU’s problems.

GPU, however, saw external tie lines that weren’t being used. “They were the first PJM utility to go out on their own,” he said.

Another blow to split savings occurred when merchant generators entered the market thanks to open-access transmission lines and subsequently refused to share their cost information.

By the time PJM began working on its locational marginal pricing proposal, Pratzon had left the grid operator and was working at PECO.

From 1992 through 2002, he advocated for PECO’s interests, including testifying at FERC in opposition to LMP. PECO at the time thought a bilateral-contracting approach would be more profitable. Pratzon was also involved with developing the wholesale market participation rules for competitive suppliers in Pennsylvania, the first state in PJM to adopt retail customer choice.

While “in the beginning, a lot of [his work at PECO] was reactionary” to what was happening in the industry, the company soon started to notice opportunities, such as selling the excess generation from its Limerick 2 nuclear plant into PJM’s markets after its failed effort to get Pennsylvania Public Utility Commission approval to include it in ratepayers’ bills.

Those experiences precipitated PECO forming a Power Team to market the excess power. “If you can’t beat them; join them,” said Pratzon, who was on the team from 2002 to 2012.

Exelon’s merger with Constellation in 2012 moved the Power Team to Baltimore. Instead of moving further from his New England roots, Pratzon lit out on his own and eventually joined with former Pennsylvania PUC Chair Glen Thomas’ GT Power Group, which already represented the PJM Power Providers group known as P3.

While Pratzon did testify at the PUC during Thomas’ tenure as the commission’s chair, they had never met.

“I don’t remember him being there; he doesn’t remember me testifying,” Pratzon said. “He heard about me through mutual acquaintances.”

Enjoying Every Minute of It

Even as his time has been wrapping up, Pratzon has remained active and vocal in stakeholder meetings.

“I’ve loved every minute of it,” he said. “It’s never the same thing twice. … I’ve invested so much of my work career into PJM and trying to help and resolve [issues].”

He hopes to have brought an attitude to the process of “trying to understand and respect the views and positions and needs of the many stakeholder groups and trying to find solutions that will help the market thrive.”

“I think … there is maybe now less of the collaborative spirit than there has been [at] times in the past. I’m not sure I can put my finger on why,” he said. “I’ll miss being part of the hopeful solution.”

PJM is a “good atmosphere to try to resolve the new issues as they come up” because while the RTO “has the hammer” to implement rules as it sees fit, it “respects and listens to stakeholder input.”

“It happens in PJM more than perhaps in any other RTO,” Pratzon said.

So why leave now?

“I feel like I have to be all-in” to do this work, he said, and to do less “would feel like dabbling.”

Instead, he’s becoming a “full-time project manager” for three months to renovate his kitchen and plans to spend more time with his three- and six-year-old grandchildren.

Traveling is in the works “to get around and see more of the world than we have in the past,” and he’ll be volunteering with an elder support group in town to meet more people and aid those who might otherwise be lonely.

Still, the stakeholder process and what it means won’t ever be far from his mind. In breaking the news of his retirement to industry colleagues, Pratzon has become fond of making a final request:

“Just remember: Keep the lights on for me now that I’m just a retail customer!”

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MISO Probing South and SPP Seams Tx Needs

By Amanda Durish Cook

MISO this week opened the floor to stakeholders’ ideas on transmission projects to relieve congestion in MISO South and near the SPP-MISO seam.

During a Dec. 18 South Subregional Planning Meeting, MISO Planning Manager Matt Ellis asked for stakeholder help in identifying project candidates for the South region as part of MISO’s annual Transmission Expansion Plan (MTEP) cycle. The MTEP 19 solution submission window will close March 1.

MISO has compiled a preliminary list of four congested flowgates with upgrade potential in and around MISO South and the MISO-SPP seam, though the RTO is telling stakeholders to expect lower congestion in 2019 and beyond.

MISO Economic Studies Engineer Karthik Munukutla said several top congested areas in MISO South have already been addressed with MTEP projects, coming online as early as this month and as late as mid-2023. Munukutla also said congestion will subside due to low energy demand and potential distributed resources further reducing those needs. However, he said some local resource zones expecting high renewable penetration may experience higher congestion.

MISO predicts future flowgate congestion at the Bullshoals-Midway Jordan 161-kV line near the Missouri border in northern Arkansas and the Fulton-Patmos 115-kV line in southwestern Arkansas. The RTO also predicts seams congestion around the Raun-Tekamah 161-kV line on the Iowa-Nebraska border and the Neosho-Riverton 161-kV line on the eastern Kansas-Nebraska border.

Top congested flowgates in MTEP 19 | MISO

MISO officials said a complete list of MISO South and MISO-SPP issues and a formal request for ideas will be sent via email to stakeholders in early January.

Project ideas will be analyzed under the MTEP’s 2019 Market Congestion Planning Study (MCPS), the first such footprint-wide study since Entergy’s five-year transition period began in 2013. The transition period, which expires at the end of 2018, has limited the cost-sharing of transmission projects.

Going forward, the RTO will discontinue its practice of creating separate studies for MISO Midwest and MISO South, though the MCPS will continue to focus on subregional needs. In another first, the MCPS will also contain MISO-PJM and MISO-SPP congestion analyses that could produce an interregional congestion-relief project.

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NYISO Management Committee Briefs: Dec. 19, 2018

RENSSELAER, N.Y. — Interim NYISO CEO Robert Fernandez told the Management Committee on Wednesday the Board of Directors this month had “reached a unanimous decision” on the AC Public Policy Transmission Project approved by the committee last summer and would release its decision no later than Dec. 27.

The MC in June backed joint proposals by North America Transmission (NAT) and the New York Power Authority (NYPA) to build two 345-kV transmission projects that could cost $900 million to $1.1 billion and would address persistent transmission congestion at the Central East interface and Upstate New York/Southeast New York interface. (See NYISO MC Supports AC Transmission Projects.)

Potomac Economics, NYISO’s Market Monitoring Unit, said the AC Public Policy Transmission Projects will be economic if the state Clean Energy Standard is satisfied with high levels of intermittent renewable generation upstate. | Potomac Economics

The MC selected project T027, a double-circuit 345-kV line from Edic to New Scotland, along with project T029, a standard 345-kV line from Knickerbocker to Pleasant Valley.

Winter Outlook

Vice President of Market Operations Emilie Nelson reprised the winter outlook, saying the ISO will have adequate capacity on hand to meet its forecasted peak demand of 24,269 MW for the 2018/19 winter season, well under last winter’s peak of 25,081 MW. (See NYISO Forecasts Adequate Capacity for Winter.)

Balancing Energy Tariff Revisions Okd

The MC approved Tariff changes clarifying real-time market settlements and their interaction with energy storage resources (ESRs), subject to approval by the Board of Directors in January.
ISO staffer Christopher Brown told the committee the changes do not affect calculations or require software modifications. (See “Real-time Market Settlements Clarifications” in NYISO Business Issues Committee Briefs: Dec. 12, 2018.)

Energy imbalance payments and charges address the differences among actual energy injections or withdrawals and real-time and day-ahead energy schedules. The changes apply to the injections and withdrawals of ESRs and include terms introduced and defined in the ISO’s FERC Order 841 compliance filing submitted Dec. 3 (ER19-467). (See RTOs/ISOs File FERC Order 841 Compliance Plans.)

— Michael Kuser

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IPPTF Hands off Carbon Pricing Proposal to NYISO

By Michael Kuser

RENSSELAER, N.Y. — The Integrating Public Policy Task Force (IPPTF) met for the last time on Monday before handing its final carbon pricing proposal to NYISO’s stakeholder governance process. The ISO will pick up work on the market design in January through its Market Issues Working Group.

The ISO and the New York Public Service Commission created the task force last October to explore ways to price carbon into the wholesale electricity markets to align them with state decarbonization policies, including the zero-emission credit program for struggling nuclear plants.

NYISO published the IPPTF Carbon Pricing Proposal on Dec. 7 after recommending it no longer include a mechanism that would make emissions-free resources with existing renewable energy credit contracts pay the carbon component of locational-based marginal prices (LBMPc). (See IPPTF Updates Carbon Charge Analysis, Treatment of RECs.)

Social Cost of Carbon

The key metric to be used in calculating a wholesale charge on emissions is the gross social cost of carbon (SCC), which the PSC would set “pursuant to the appropriate regulatory process,” according to the proposal. The state Department of Public Service based its calculations on that of the federal government’s Interagency Working Group on Social Cost of Greenhouse Gases.

The Brattle Group projects that carbon charges will lead to incremental internal emissions reductions of 6% by 2030. Most reductions would come from price-responsive load, renewable shifts and possible nuclear retentions. | The Brattle Group

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, asked whether there had been any discussions with state regulators about the timing of the PSC’s process

“I assume that the commission is not going to have any regulatory process on setting the social cost of carbon unless and until there’s a vote at the ISO, but doing it that way creates difficulties for stakeholders because then we’re being forced to vote on a carbon pricing proposal without having any guarantees on how the social cost of carbon will be set, how it will be updated [and] when it will be updated,” Mager said.

“The policy of the state of New York is very obvious, and I clearly stated where we got the social cost of carbon used in this analysis,” said Warren Myers, DPS director of market and regulatory economics. “There are no guarantees in life, but you sure have a heck of a lot of information.” (See NY Looks at Social Cost of Carbon, Modeling.)

“The ISO and DPS staff have had a few conversations on this subject” and continue to have conversations on how to structure the rules to accommodate the PSC’s ruling, said Michael DeSocio, NYISO senior manager for market design.

“At the end of the day, if there’s a public policy that establishes a value for carbon, that would be the value that we need to incorporate into the wholesale market,” DeSocio said. “How that value has been established is public policy. I don’t know that we’d create bookends for what the maximum or minimum should be.”

External Transactions

Under the proposal, suppliers would be expected to embed the carbon charge into their energy offers and would continue to receive the full LBMP and be debited their carbon charges during settlement. NYISO would calculate and publish the LBMPc to provide market transparency, adjust payments for import and export transactions, and allocate carbon residual revenues.

“As we discussed along the way, the ISO put forth a proposal that would allow imports and exports to continue to compete on a status quo basis with internal suppliers,” DeSocio said. “As we get experience with it, if we see there are ways to make it more efficient, let’s do that.”

Several stakeholders questioned how NYISO planned to deal with the possibility that FERC might not accept in full the impact of a state-mandated carbon charge on wholesale electricity rates.

“We’re looking at the potential in the very near future to have gigawatts of offshore wind coming into New England and PJM, so this concern may be on us much sooner than you think,” said Seth Kaplan of EDP Renewables. “I refer you specifically to the work done by the Massachusetts Department of Environmental Protection for implementation of the Global Warming and Solutions Act, where they got into this exact issue in terms of customers in Massachusetts that were buying clean energy and wanting to make sure that it was credited in the emissions mix.”

DeSocio said the ISO will release a forecast LBMPc an hour before real-time dispatch. “What we’re not going to do is guarantee that that forecasted price is what we’re going to charge you, and instead will charge you the actual price,” he said.

The New York Department of Public Service derived the gross SCC from the federal government’s Interagency Working Group on Social Cost of Greenhouse Gases. The expected RGGI price is based on the August 2017 base case forecast for RGGI prices (in dark blue). The light blue values are interpolated. | NY DPS

Update on Analysis Requests

DeSocio gave an update on NYISO’s actions on several stakeholder requests for additional analysis, saying it would not study using buyer-side mitigation as a replacement for carbon pricing.

“Seemingly small adjustments to assumptions have wild differences in what the analysis shows,” he said. “That tells us whatever number we put out, we know [it] will be wrong, and most likely will be wrong in a big way.”

“The reason we wanted to see this study performed is that part of the reason we’re here is because FERC is concerned with the impact state policies are having on the markets, specifically price formation,” said Matt Schwall of the Independent Power Producer of New York. “One of the tools FERC has in its box is mitigation. I don’t know what the likelihood is that FERC could subject state-supported resources to mitigation; I do know that’s an option, and that carbon pricing is one way to protect against that.”

Bob Wyman of Dandelion Energy referred to recent rulings by the PSC that will double New York’s existing 2025 storage goal to 3,000 MW by 2030 and require the state’s utilities to reduce building energy use by an additional 31 trillion British thermal units (TBtu) to meet an energy efficiency target of 185 TBtu by 2025. (See NYPSC Expands Storage, Energy Efficiency Programs.)

“It’s important to note that in that order [Case 18-M-0084], they called for 5 [trillion] Btus in savings from heat pumps,” Wyman said. “Increasing the price of electricity relative to gas and oil is going to discourage people from accomplishing that goal, as with any of the beneficial electrification stuff, if we have a single-sector carbon price. And that really should be taken into consideration.”

“Climate change is occurring, it’s clearly related to carbon dioxide emissions and it’s not tip-toeing in on little cat’s feet anymore; that time is past. It’s coming like a freight train,” Myers said. “As an economist, I am convinced that the most economical way to address this problem starts with — it may not be sufficient — but starts with a universal, economy-wide price on carbon.”

Myers said, however, that, “unfortunately, we do not currently have a federal government willing to work on such a universal, economy-wide carbon price. And the proposal we have here put forth by the NYISO is not that. Context matters, and the context here is that we are evaluating a single-state, single wholesale market carbon price.”

DeSocio said he expects stakeholders will be meeting on the carbon pricing proposal several times a month in the first half of the year and that the ISO will soon release a schedule for those meetings.

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FERC OKs PJM Plan to Prevent Shortchanging of DR Value

By Rory D. Sweeney

PJM Market Implementation Committee Briefs: Sept. 13, 2017.)

East Kentucky Power Cooperative headquarters | EKPC

PJM calculates an end-use customer’s DR capability by taking the lesser of its total peak load contribution, which measures summer capability, or its WPL.

The WPL, which is usually lower, is calculated by averaging the customer’s peak hourly loads during traditional daytime hours on the five days with the highest daily unrestricted peak loads from December through February, known as the five coincident peaks (5CPs).

However, one or more of the 5CPs can have little or no load because of load-management actions, offline factories or meter malfunctions. Such reductions reduce the WPL, which will likely reduce the calculation for the resource’s potential load reduction.

To avoid this, PJM will allow customers to exclude up to two CP days when the peak hourly loads for each of those days are individually below 35% of the average peak hourly load for all the location’s winter 5CP day. The 35% threshold represents 1% of all submitted peak load days.

The commission’s Dec. 17 order said the new rules “should more accurately reflect end-use customers’ actual loads during peak winter periods.” It rejected the Independent Market Monitor’s argument that the proposal would arbitrarily increase the calculated WPL.

“Similarly, we are unpersuaded by the Market Monitor’s argument that failure to also eliminate high-load days renders the winter peak load calculation arbitrary. There is no evidence in the record that identifies any particular circumstances or events that may cause abnormally high-load days that are not representative of actual peak loads and, when used to calculate winter peak load, lead to an inaccurate representation of a demand resource’s capability to reduce its winter load.”

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NERC Releases ‘Stress Test’ Analysis of Gen Retirements

NERC Releases ‘Stress Test’ Analysis of Gen Retirements

By Michael Brooks

NERC on Tuesday warned that faster-than-expected coal and nuclear plant retirements could jeopardize reliability if grid operators are not prepared.

“If these retirements happen faster than the system can respond with replacement generation, including any necessary transmission facilities or replacement fuel infrastructure, significant reliability problems could occur,” NERC said in a special reliability assessment report. “Therefore, resource planners at the state and provincial level, as well as wholesale electricity market operators, should use their full suite of tools to manage the pace of retirements and ensure replacement infrastructure can be developed and placed in service.”

Calling it a “stress test” of the bulk power system, the organization used data from the U.S. Energy Information Administration to identify generators set to retire through 2025 in 10 areas where coal-fired and nuclear generation make up a significant portion of the resource mix. It then analyzed the impacts of those generators retiring earlier, in 2022.

The analysis found four areas — SPP, SERC-East, WECC-RMRG and WECC-SRSG — in which currently planned generation resources would not be sufficient to make up for the accelerated retirements. NERC determined this by comparing projected planning reserve margins for 2022 under the scenario to projected peak load levels for the year. The organization used data from its 2017 Long-Term Reliability Assessment to determine projected reserve margins under currently confirmed retirements through 2022, to which it factored in the accelerated retirements. It also used the LTRA to determine the projected peak loads.

‘Unlikely’ Scenario

Both the report and John Moura, NERC director of reliability assessment and system analysis, repeatedly emphasized that the analysis was not a prediction.

“I think it’s really important that stakeholders understand that this is a stress-case scenario,” Moura said in a conference call with reporters Tuesday morning. “We’re not necessarily making any recommendations or calls for any additional financial support beyond that which market operators think are required. We completely acknowledge that the scenario as tested is unlikely.”

He noted the organization also analyzes the impacts of geomagnetic disturbances and simultaneous, highly coordinated physical and cyberattacks on the grid. “These are things that we don’t believe will happen, but we think it’s instructive, when we break a system, to understand what are the potential mitigations and see how to get it working.”

“NERC’s stress-test scenario is not a prediction of future generation retirements nor does it evaluate how states, provinces or market operators are managing this transition,” the report says. “Instead, the scenario constitutes an extreme stress-test to allow for the analysis and understanding of potential future reliability risks that could arise from an unmanaged or poorly managed transition.”

Moura also noted that the report doesn’t criticize capacity markets or out-of-market subsidies. “We’re simply saying that these tools need to be monitored and tested in planning,” he said.

Fears of Politicization

NERC was criticized by some stakeholders in early November, when it briefed its Members Representatives Committee on the report. They feared it would be politicized, and that the press and public would misunderstand it as a warning of things to come. (See LaFleur, Stakeholders Anxious over NERC Retirement Study.)

“Policymakers and regulators should not interpret this study as justifying interventions to artificially retain unprofitable power plants, as these actions deter the economic transition in the power generation fleet, undermine innovation and raise costs to America’s businesses and families,” Devin Hartman, CEO of the Electricity Consumers Resource Council, said in a statement Tuesday.

“As NERC itself states, the report looks at unlikely scenarios that go far beyond either announced or projected power plant retirements to determine at what point there might be some risk for reliability,” said Jeff Dennis, general counsel for regulatory affairs at Advanced Energy Economy. “The report does not provide evidence of any imminent threat to the reliability of the bulk power system. Nor does it suggest that competitive wholesale energy markets aren’t up to the job of ensuring reliability as the resource mix changes.”

The report “relies on too many extremes to be enlightening about real-world grid reliability,” the Natural Gas Supply Association said.

Tuesday’s report did not include a detailed analysis of natural gas infrastructure; however, NERC said “additional midstream natural gas infrastructure could be required” to respond to early retirements.

In a November 2017 assessment, NERC had recommended industry consider the loss of key natural gas infrastructure in their planning studies under NERC reliability standard TPL-001-4. (See NERC: Natural Gas Dependence Alters Reliability Planning.)

Although NERC sees risks to increasing dependence on renewables and gas-fired generation, Tuesday’s report said that “successfully managed, the changing resource mix can provide … potential benefits to reliability and security of the BPS. Less reliance on large, centralized generation stations and greater use of dispersed networks comprised of smaller diversified generation resources can provide operating and planning flexibility. Additionally, some fuel assurance risks diminish with the changing resource mix. The effects of adverse weather on coal stockpiles or fossil fuel resupply infrastructure may be reduced when natural gas pipelines supply a greater proportion of the generating fleet. Attaining reliability enhancements associated with the changing resource mix is possible when the different challenges to fuel assurance and [essential reliability services] are addressed.”

Recommendations

NERC included several suggestions to stakeholders, regulators and policymakers in the report, among them a recommendation to incorporate fuel assurance analyses in generator retirement assessments. This would mean factoring in fuel supply infrastructure, new infrastructure requirements for replacement resources, and firm vs. non-firm fuel delivery contracts.

It also recommended that regulators and policymakers consider ways to speed up approvals of infrastructure. “When a generator’s planned retirement is delayed to allow for completion of transmission system upgrades, expedited regulatory proceedings can help minimize the delay,” the report says. “Where more natural gas generation is needed, more natural gas pipeline capacity will likely also be needed.”

But Moura also noted that the report doesn’t make any specific recommendations for the four areas identified by the report as being at risk under the scenario. “We have a lot of confidence in how these areas plan their systems,” he said.

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OMS Names New Executive Director

By Amanda Durish Cook

Marcus Hawkins | © RTO Insider

The Organization of MISO States announced Monday that its board of directors has promoted Marcus Hawkins to head the organization, replacing outgoing Executive Director Tanya Paslawski next year.

Hawkins, formerly an engineer with the Wisconsin Public Service Commission, joined the organization in 2016 as its director of member services and advocacy. (See Former Wisconsin PSC Engineer Marcus Hawkins Joins OMS Staff.)

Paslawski, who has headed OMS since 2015, will leave effective Dec. 31 to become president of the Michigan Gas and Electric Association. (See OMS Executive Director to Exit.)

“OMS commissioners know and have great respect for Marcus Hawkins’ work as director of member services and advocacy. We look forward to working with him in his new role,” said OMS board President Ted Thomas, chairman of the Arkansas Public Service Commission.

Hawkins said he is excited to lead the organization during “rapid change in the electric industry.”

In addition to his role at the Wisconsin PSC, Hawkins has also worked at Wisconsin Energy Conservation Corp. and PA Consulting Group. Hawkins has a master’s in mechanical engineering and a bachelor’s in nuclear engineering, both from the University of Wisconsin-Madison.

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PJM PC/TEAC Briefs: Dec. 13, 2018

By Rory D. Sweeney

FSA Unit Plan

VALLEY FORGE, Pa. — PJM is reformatting and drafting clarifications to Manual 14B: PJM Region Transmission Planning Process that may impact the RTO’s planning modeling, staff told attendees at last week’s Planning Committee meeting.

PJM Planning Committee | © RTO Insider

The proposed revisions would clarify that units with facility service agreements (FSAs) will only be added to the base case if there are not enough existing units and units with interconnection service agreements (ISAs). Units with FSAs that are not included in the base case will be subject to a sensitivity study to determine if long-lead-time upgrades are required to support them. The long-term base case will only be studied if the need for a long-lead-time upgrade is identified during the near-term base case analysis extrapolation over Years 6 through 15.

Additional clarifications include:

  • Higher-than-normal capacity interconnection rights (CIRs) may be granted to wind units when justified by meteorological data.
  • Flowgates near PJM’s borders will continue to be examined to understand deliverability concerns that may exist due to loop flows.
  • Merchant transmission facilities (MTFs) with long-term firm transmission service will be modeled the same as MTFs with firm transmission withdrawal rights.
  • Operational contingencies are single contingencies examined under the common-mode outage procedure to determine whether system operators would allow the common-mode dispatch to occur.
  • Constraints identified in the PJM capacity import limit (CIL) analysis are studied in the same manner as other internal PJM constraints.
  • The distribution of the capacity benefit margin from each of the five external supply zones is determined during the annual PJM CIL study.

PJM’s Jonathan Kern said the clarifications were intended to be pre-emptive measures to avoid confusion in the future.

Inverter-based Model

Staff plan to update Manual 14G: Generation Interconnection Requests to identify which user-defined models (UDMs) it has already approved for wind turbines and other inverter-based resources. Developers planning to build affected generators would need to use the tables to determine whether they would need to submit additional information about modeling their units to receive PJM approval.

PJM’s Tao Yang said the list would likely be updated annually.

PJM’s Ken Seiler, who chairs the PC, said standardizing the stability modeling is important so generation interconnection requests can be processed “much faster.”

ELCC Analysis of Intermittent Resources

PJM’s Tom Falin said the RTO is targeting an endorsement vote at the March meeting of the PC for a package of four changes for how capacity credits are calculated for intermittent resources.

One of the prospective changes, resources’ effective load carrying capability (ELCC), has received “a lot of discussion lately,” Falin noted. PJM scheduled a special session of the PC on Dec. 21 so the RTO can get “a read” on stakeholders’ interests. (See “Renewables’ Capacity Analysis Extended,” PJM PC/TEAC Briefs: Nov. 8, 2018.)

The question to answer, he said, is “do we think moving to an ELCC methodology is the right thing to do?”

PJM’s Jerry Bell will return to the PC in January to reintroduce the proposed changes with whatever consensus on the ELCC is gleaned from the special session.

Cost Containment

PJM’s Mark Sims said staff have gathered all of the pieces necessary to develop the comparative framework for cost containment and return on equity that stakeholders endorsed earlier this year. (See “Update on Integrating Cost-containment Guarantees,” PJM PC/TEAC Briefs: Sept. 13, 2018.)

“The moving parts we’re dealing with … include not only the uniqueness of the proposals that we might receive but … the complexity of the cost-containment proposals we might receive … [so] there’s a couple of big moving parts,” Sims said. “We have all the building blocks we need to pull the process together in 2019. … We can see where all the pinch points are.”

As part of the process, PJM and its Independent Market Monitor met with an independent consultant on Nov. 15 to better understand cost estimating, revenue requirements and other components for developing cost proposals. PJM continues to work with the contractor, and stakeholders questioned how the RTO would handle a situation if the contractor eventually took a contract that created a conflict of interest. PJM’s Sue Glatz said it “would be a given” to re-evaluate the relationship if staff “saw anything” that affected the contractor’s independence, but that “right now we don’t see any conflicts.”

Sims said he plans to return to the committee in January with more detail on the process.

MEPETF

Work in the Market Efficiency Process Enhancement Task Force (MEPETF) has progressed to polling on how to proceed with revising the market-efficiency process, PJM’s Fran Barrett said. At the task force’s Dec. 7 meeting, stakeholders developed a list of nine questions for the poll, including the preferred method for re-evaluating already-approved market efficiency projects and the preferred cycle for PJM to conduct the market-efficiency process.

“That means we’ve got a lot of work in January and February. It’s going to be pretty swift and a lot of hard work,” Barrett said.

Staff are targeting the March PC meeting for a first read of the most popular options so the package proposal can be implemented on Nov. 1.

Offshore Wind Zones

With many coastal states announcing offshore wind solicitations, PJM is now developing concepts for alternative ways to interconnect all of the coming megawatts, Glatz said. She explained that developers have approached staff with challenges and said they’d like to have multiple interconnection points, along with the ability to create offshore transmission networks. Staff are considering how to handle those desires and are seeking input from the PC on a variety of questions, including what studies might be required, what interconnection rights might be offered and whether the rights could be transferrable.

Glatz said staff are targeting the January or February meetings of the PC to introduce proposed concepts and related Tariff revisions. Stakeholders said they had no foundation on which to base their input and called on staff to create a problem statement and issue charge on the topic. But staff voiced concerns about the initiative getting bogged down in debates.

“We have real projects today, so the challenge is how can we be responsive to our customers?” Glatz said, adding that states want to limit impacts to communities while also providing the necessary resources.

The plan is potentially a move toward creating open-access offshore networks as an extension of the onshore grid that has been advocated by stakeholders like Markian Melnyk, president of Atlantic Grid Development. (See Offshore Wind Industry ‘Really Moving;’ Coordination Key.)

However, PJM is currently considering only plans that are “strictly for injecting into PJM,” not connecting to other RTO/ISOs, Glatz said.

2019 Load Forecast

PJM’s John Reynolds | © RTO Insider

The RTO’s preliminary 2019 load forecast is down compared to last year, PJM’s John Reynolds explained. Both the summer and winter forecasts are down at least 0.4% from last year’s forecasts.

The analysis uses the summer forecasts for 2022 and 2024 and the winter forecasts for 2021/22 and 2023/24 to make year-over-year comparisons. The summer 2024 comparison is down 0.5%, slightly more than the other three. Staff are adding a zone summary page for 2019 that details zonal impacts.

The report remains preliminary for now because there were issues with forecasts in the Dayton Power and Light and East Kentucky Power Cooperative zones that are still being revised. The final version, expected by the end of December, will be used for all Regional Transmission Expansion Plan studies.

Because the Base Residual Auction is delayed this year to attempt to implement revisions to the capacity auction construct, PJM staff will develop a second load forecast just for the BRA that would include peak-shaving adjustments.

Reynolds confirmed that the forecast only includes load that PJM system planning staff are working on and nothing speculative.

Planning Resilience

PJM’s Aaron Berner presented analysis from staff’s recent initiative on developing “cascading trees” on load-loss probabilities that shows one facility has a high probability of losing at least 1,000 MW of load.

“This gives us an idea about potential weaknesses based on initiating events,” Berner said, but he cautioned that more work will be necessary to make sure staff are not “looking at things we shouldn’t be.”

Deactivation and Acceleration

PJM’s Nick Dumitriu discusses planned transmission projects during last week’s meeting of the RTO’s Transmission Expansion Advisory Committee as meeting administrators Ken Seiler and Lisa Krizenoskas look on. | © RTO Insider

PJM’s Nick Dumitriu said the 2018 reliability project acceleration analysis found no projects to accelerate to reduce congestion. Project B2766 would ease congestion, but it was already accelerated last year to 2020 and the developer said it can’t be accelerated further.

PJM is performing reliability analyses for deactivation of 30 units, all of which have requested to deactivate no later than June 1, 2020.

Dominion

Dominion Energy’s Ronnie Bailey presented three new need assessments and three planned solutions as part of the transmission owners’ new FERC-ordered process for developing supplemental projects. Dominion has presented 19 needs assessments since the process was implemented in September. Dominion has been presenting such needs and planned solutions for several months. (See “Dominion Supplementals,” PJM PC/TEAC Briefs: Oct. 11, 2018.)