Page 1086 – RTO Insider

December 20, 2018

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 (RM 1 8 –1 , A D1 8 -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 com m e nt s 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 o n 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.)

December 20, 2018

GT Power Group’s Dave Pratzon Retiring

By Rory D. Sweeney

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!”

December 20, 2018

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 li s t 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.

December 20, 2018

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

December 19, 2018

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.

December 19, 2018

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.”

December 18, 2018

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.

December 17, 2018

State Regulators Still Frustrated with PJM

By Michael Brooks

WASHINGTON — The tension between PJM and certain states has not loosened, judging by comments made at a forum held by the Great Plains Institute and Duke University’s Nicholas Institute on Environmental Policy Solutions last week.

From left to right: Panel moderator Jennifer Chen, Nicholas Institute; M. Beth Trombold, Ohio PUC commissioner; Brien Sheahan, Illinois Commerce Commission chairman; Mary-Anna Holden, New Jersey BPU commissioner; and Norman Bay, Willkie Farr & Gallagher. | © *RTO Insider*

During a panel on PJM and state authority over resource adequacy, Illinois Commerce Commission Chairman Brien Sheahan and New Jersey Board of Public Utilities Commissioner Mary-Anna Holden took the RTO to task over several issues, including its latest proposal to revise the capacity market to factor in their states’ subsidies for zero-emission resources.

Holden said that while she thinks the relationship between her state and PJM has improved, she was incensed by a recent letter from the RTO’s Board of Managers giving stakeholders a Jan. 31 deadline to reach consensus on several energy price formation issues. (See PJM Board Demands Action on Energy Price Formation.)

“We’d like to have representation in the stakeholder process,” Holden said. “Yes, a stakeholder process takes place, but we’d like to have respect in the stakeholder process. And that when we’re moving towards an answer, not to come out with a letter of decree from PJM saying, ‘Well, you didn’t work fast enough, so we’re just moving ahead,’” she continued, holding a copy of the letter aloft. “That’s not good governance, and that’s not communicating or collaborating.”

“I would second all of that,” Sheahan said. “I think the letter certainly has rubbed people the wrong way.”

Sheahan expressed appreciation for PJM’s position. “They have a very, very difficult job. … There is enormous tension between the job they have and the policies that states express.”

But, he added later, “I really don’t know how that tension gets resolved.” He noted that he has advocated for Commonwealth Edison, whose Chicago service territory is in PJM, to join MISO, which encompasses the rest of Illinois. But he said the solution may be for the state to not participate in PJM’s capacity market. “I think PJM may just have to decide, ‘Look this is the best we can do, and if it doesn’t fit for your state, we have some other alternatives.’”

Sheahan’s opinion echoed that of Independent Market Monitor Joe Bowring, who gave a presentation on several PJM market issues prior to the panel, including his firm’s own proposal for the capacity market. “If units don’t clear, then as far as we’re concerned, they’re not capacity resources,” Bowring said. “If states want to maintain them, they’re free to do that, but they do not get capacity market revenues. So the capacity market does not change; we don’t need some hugely complicated, impossible-to-understand set of rules to make sure they really clear and force out competitive units. If they’re not competitive, they’re not competitive; they should not clear. …

“If you want to maintain cost-of-service regulation in the state, that’s fine, but rather than acting as if you were a market competitor, you should simply offer in as” a fixed resource requirement.

The RTO’s energy market is working well and also does not need a complete overhaul, Bowring argued. On that point, Norman Bay, a former FERC chairman who is now a partner at Willkie Farr & Gallagher, agreed. Throughout the panel, it often fell to Bay to act as a calming presence as a counter to Sheahan’s and Holden’s frustrations.

“We should acknowledge that the energy market in PJM works well, and it’s producing competitive outcomes from which consumers have benefited,” Bay said. “PJM deserves a lot of credit with respect to the energy market. It’s the capacity market that seems to have engendered the greatest amount of controversy.”

Bay suggested asking FERC to hold a technical conference on stakeholder processes in RTOs and ISOs. He cited the D.C. Circuit Court of Appeals ruling last year that FERC had overstepped its bounds in suggesting to PJM what revisions to the RTO’s minimum offer price rule it would accept. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

The ruling, written by now Supreme Court Justice Brett Kavanaugh, said the commission could only suggest minor, technical or administrative changes, not “modifications that result in an entirely different rate design than the utility’s original proposal or the utility’s prior rate scheme.”

“Thus, the RTO/ISO stakeholder process is more important than ever,” Bay said. “Which means that, given the importance of the process, I think it is critical that stakeholders have a seat and voice at the table.” He said many stakeholders — not just state regulators in PJM — have concerns about the processes.

FERC Commissioner Richard Glick, who gave a keynote luncheon speech at the event, noted that as well. He said he attended a recent Edison Electric Institute conference, and “I was amazed at how many people came up to me to complain about RTO governance in general. … People from all sides of various issues.”

He said it would be worthwhile for FERC to look at the issue, though he did not have any specific suggestions. Both he and Bay noted that it had been a long time since the commission examined RTO governance. In 2008, FERC Order 719 required that each grid operator “increase its responsiveness to customers and other stakeholders.”

Sheahan’s and Holden’s sentiments have been shared by other regulators on their commissions this year. (See NJ Regulator Threatens to Exit PJM Amid States’ Complaints.)

For his part, Bowring said he believes that PJM stakeholder process, “as difficult as it is, has been working just fine. … The stakeholder process is messy … it could be made more efficient. But real issues are debated, real interests are debated and, from my perspective, it has worked very well. The fact that it doesn’t do what one party or another wants, as quickly as they want, is not a sign that it’s not working; it’s a sign that it is working.”

Stu Bresler, PJM senior vice president of markets and operations, defended the RTO’s capacity market filing in a presentation prior to the panel. PJM’s proposal was “really, despite what you may read out there in the press, aimed at accommodating these state policy decisions.”

“There are no easy answers. There are very tough questions with which we are all wrestling,” Bresler said. “From PJM’s standpoint, what we want to do is make sure that we continue to engage with our federal regulator, our state commissions and all our stakeholders, to work our way through these issues.”

“PJM is a member organization,” spokesman Jeff Shields said in an email. “The decision to remain as a member resides with those PJM members.

“We respect the rights of states to determine the mix of generators within their borders, and we have worked with FERC and our stakeholders on recently filed proposals that seek to maintain the integrity of the market while respecting state policy initiatives.”

Looking Ahead

True to the event’s name — “Looking Ahead: Big Challenges in 2019” — many attendees asked speakers and panelists how they thought FERC might rule on the capacity market proceeding.

The abridged version of everyone’s answers: No idea.

But whatever FERC issues, many speakers hoped for a solution that lasts. “It would just be nice to have some consistency,” Holden said. The capacity market “has changed 30 times in 10 years,” she said.

“I don’t know where the commission will end up on this, but I do think that whatever design the commission considers, that it should be sustainable and durable,” Bay said. “I think that it is very hard for stakeholders to deal with significant changes to market design every few years.”

“Good market design is self-sustaining,” Bowring said in closing his presentation.

December 17, 2018

New England Talks Solar, Storage and Public Policy

By Michael Kuser

BOSTON — Growing solar generation will be able to meet a third of peak load in Massachusetts in a few years, but as the grid is reaching the saturation point in certain areas, policymakers are looking to energy storage to help address some of the challenges.

“The grid was not initially designed for this much distributed energy … and we never envisioned 90,000 power plants out there,” Commissioner Judith Judson of the Massachusetts Department of Energy Resources said Friday at the 160th New England Electricity Restructuring Roundtable run by Raab Associates.

The 160th New England Electricity Restructuring Roundtable drew a standing-room-only crowd in Boston on Dec. 14. | © *RTO Insider*

Judson said the state now has more than 89,000 installed solar projects totaling more than 2,300 MW in each of its 351 cities and towns.

On Nov. 26, it launched the Solar Massachusetts Renewable Target (SMART) program, which provides incentives for projects on brownfields, landfills, parking lots and rooftops. “SMART provides a fixed revenue stream to reduce the cost of the program, and we are the first state in the nation to have a solar-plus-storage incentive,” Judson said.

It took the state a long time to launch the program because “we have a regulatory process in DOER and in the Department of Public Utilities, plus heavy stakeholder engagement,” Judson said. “But we’ve had over 2,850 applications for 650 MW in capacity submitted so far and $4.7 billion in cost savings to ratepayers compared to earlier solar programs, so I think it’s made for a better program.”

On Dec. 12, the state issued its Comprehensive Energy Plan (CEP), including a provision for the state’s utilities to procure a combined 200 MWh of energy storage by 2020. (See Massachusetts Deploys Utility-Scale Energy Storage.)

Transition in Connecticut

“The grid modernization proceeding [Case 17-2-03] in Connecticut is a really promising opportunity,” said Mary Sotos, deputy commissioner of the state’s Department of Energy and Environmental Protection.

“I think it’s the first time utilities have laid out for the public … how they’re doing manual, back-end system work for stuff they want automated at scale,” Sotos said. “It’s not just the cost of the meters for them; the concern is managing the data … putting it in the right format, which is all part of this broader shift in information availability.” (See Connecticut Explores its Energy Future at CPES Event.)

Sotos highlighted “opportunities to align policy objectives, customer objectives and developer objectives.”

Connecticut’s solar programs are all in transition, including ones that limit virtual net metering for state, municipal and aggregation customers by capping the amount that could be reflected into rates, she said.

Connecticut last spring passed a bill that doubles the amount of renewable energy utilities must use to serve load — 40% by 2030 — while also revoking net metering guarantees that ensured rooftop solar owners earn retail prices for their excess electricity. (See Connecticut Energy Bill Draws Mixed Reviews.)

“Net metering was available to all these customers in the past on the energy side to compensate solar energy … and each of those solar programs had a statutory spending cap, but we found that municipalities were reaching that cap very quickly,” Sotos said. “For each of these groups we also had a separate program to help facilitate the deployment of behind-the-meter solar by focusing on the RECs [renewable energy credits].”

The state’s Green Bank ran “an incredibly successful” residential solar investment program to focus on the RECs from installations with storage, she said.

“However, under the current monthly net metering model, there isn’t an obvious incentive for customers to do storage, because any energy that is excess or used in real time, it’s all valued at the same level,” Sotos said. “From our perspective, to really value storage for dynamic peak reduction or other benefits … there needs to be an additional financial signal, whether that’s a time-of-use rate or some other type of adder.”

Field Experience

Jonathan Raab of Raab Associates, who has been convening the roundtables since 1995, said he was lucky in his selection of two of last week’s panelists: Evan Dube, senior director of policy at SunRun, represented the most megawatts bid in the under-25-kW category in the SMART program, while Ilan Gutherz, senior director of strategy and policy at Borrego Solar, represented the most megawatts bid in the over-25-kW category.

“Having a robust [distributed energy resources] market, both behind-the-meter and in front, is going to be critical for sustaining the grid in the future,” Dube said. “We hear an awful lot about how rate design must be sustainable … but in so doing, we have to keep in mind the benefits that building out these resources will have in the long term, and how that’s going to make us more sustainable in the future.”

More granular rate design such as time-of-use rates is preferable because it is fairer to customers, but that rate structure is contingent on penetration levels and their location, which affect the price of electricity, Dube said. The availability of metering infrastructure and data also influence how exact electric power billing can get.

The future of compensation for zero-marginal-cost resources like wind and solar depends on getting regulators to “think about how PV and batteries can avoid the need for long-term transmission investment,” Gutherz said.

New York’s Value of DER tariff that large-scale solar and other resources are now on has been testing value-based compensation as opposed to cost-based compensation alone, he said.

“New York’s an interesting experiment; in our opinion, they went a little bit too fast, so if you watch the recent filings from the commission there, you’ll see there’s been a lot of back-pedaling on certain aspects of that tariff,” Gutherz said.

“Solar plus storage is a game-changer,” said Juliana Mandell, director of market development and policy at ENGIE Storage. “You’re transforming solar into a dispatchable, reliable renewable energy resource that’s no longer time-constrained, and that fundamentally shifts the conversation.”

Energy storage can flatten load and generation, be used to reduce peak demand, or to shift generation and load depending on grid system needs and economic signals, she said.

“And you can use storage to mitigate locational constraints and congestion [and] improve capacity supply, and storage can participate at a high level in the wholesale market,” Mandell said. “You can see that coming out of the recent FERC orders if you’re looking [at] how do we pay fairly for resources that provide a different level of performance.”

“The questions is not why solar, but why distributed solar?” said Jesse Jenkins, postdoctoral fellow at Harvard’s Kennedy School and one of the contributors to the MIT Utility of the Future study. “Solar and storage are technologies and means that deliver value, so what we need to focus on is the ends that we have in mind and the value that we want to capture. … Solar and storage are not the only ways to deliver any of the values we’re talking about.”

Mark LeBel, an attorney with Acadia Center, said that solar, peaking in summer, has to be balanced with winter-peaking wind, but that balance is also needed to value societal concerns.

Rooftops almost certainly have to be part of the answer for solar, because there are little or no siting issues, he said.

“Where are we going to put 20 GW of solar?” LeBel said. “Does New England want to pave over paradise?”

December 17, 2018

Soapbox: Large Buyers – Don’t Stop Our Renewable Purchases

By Jeff Dennis and Caitlin Marquis

In response to FERC’s directive to address the impacts of state policies on capacity prices, PJM has proposed a sweeping approach that could put at risk a broad set of transactions for renewable energy that have nothing to do with any state policy or mandate. On behalf of the Advanced Energy Buyers Group, a collection of large companies ranging from technology to retail to manufacturing, we urge FERC to avoid disrupting the voluntary market for renewable energy by rejecting PJM’s approach.

Companies involved in the Advanced Energy Buyers Group are committed to increasing their use of advanced energy, with many entering into contracts to develop renewable energy projects to meet their own business needs, completely independent of state mandates or incentives. We are concerned that PJM’s proposal, if adopted by FERC, would unfairly apply to some of these voluntary transactions the same measures intended to “correct” a market distortion supposedly caused by so-called “material subsidies” provided by states. This could threaten the continued growth of the quickly expanding voluntary market for renewable energy in the PJM footprint, and the jobs and other economic benefits that growth brings to states and communities in the region even as it gives companies the clean energy they seek.

According to FERC, generating resources that receive revenue as a result of state renewable portfolio standards or zero-emissions credit (ZEC) programs are able to submit offers in PJM’s capacity auctions at a lower price than they would otherwise. FERC claims that these offers result in “artificially” lower prices, harming other suppliers that do not receive such revenue. To address this alleged price suppression, FERC ordered PJM to expand its minimum offer price rule (MOPR) — which requires capacity suppliers to make offers at or above a predetermined minimum value — to apply to any capacity resource receiving revenues from state policy programs.

To its credit, PJM correctly acknowledged that voluntary renewable energy purchases should be exempted from the expanded MOPR because any revenue received from such purchases aren’t the result of any state mandate or policy. PJM goes on, however, to state that any renewable energy certificates (RECs) purchased through brokers or intermediaries will be assumed to be serving state policy needs rather than meeting voluntary market demand. This means that only those RECs that are purchased by voluntary buyers through direct, bilateral transactions would be exempt from MOPR requirements. Other renewable energy transactions that use different structures would face the possibility that they could be subject to the MOPR. That matters because application of the MOPR could force certain renewable energy projects out of the capacity market, depriving them of legitimate revenue.

Applying the MOPR in such a broad fashion would fail to satisfy FERC’s legal obligation to narrowly tailor such mitigation to the market harm it identified, i.e., the supposed price-suppressive impacts of state-directed revenues. Equally important, it would fail to account for how the voluntary market actually works, especially the variety of transaction structures and market actors, including REC brokers and intermediaries, that support voluntary renewable energy purchases.

Direct REC purchases from renewable energy projects are an important segment of the voluntary market, to be sure. But so too are “unbundled” RECs purchased through brokers or intermediaries. Renewable energy buyers range from residential consumers to small businesses to large international corporations. Many of these buyers rely on unbundled RECs to some degree, and in 2017 unbundled REC sales accounted for nearly half (46%) of all voluntary market sales of renewable energy. The voluntary purchase of these unbundled RECs by buyers who (unlike utilities and other electricity suppliers) have no state-imposed obligation to purchase renewable energy does not contribute to the state’s RPS or other policy mandate. These RECs are effectively retired, rather than used for compliance with state requirements — which is why they can be counted toward corporate sustainability goals.

Even for large companies that pursue direct contracts with renewable energy projects, unbundled RECs purchased from brokers or other intermediaries can play an important part in an overall renewable energy strategy. Unbundled RECs allow companies to purchase renewable energy without a long-term, large-scale commitment to a single project, as part of a diversified renewable energy portfolio. Unbundled RECs also allow companies to meet renewable energy goals while they pursue direct renewable energy contracts, which takes time.

Many companies and other renewable energy buyers rely heavily on RECs purchased through brokers or intermediaries — to the tune of 51 million MWh across the country last year. These RECs have contributed to a rapid expansion of voluntary corporate renewable energy deals in the PJM region in just the past few years. One voluntary REC getting swept up in mitigation that is, by the terms of FERC’s directive, supposed to be narrowly focused on material subsidies provided by states is one too many, and PJM’s approach could sweep up nearly half the market.

Accordingly, we urge the commission to ensure that any changes to PJM’s capacity market do not, even inadvertently, unfairly cripple the voluntary market for renewable energy.

Caitlin Marquis is manager of federal and state policy for the Advanced Energy Buyers Group, a business-led coalition of large energy users engaging on policies to expand opportunities to procure advanced energy to meet their operational needs.

Jeff Dennis is general counsel, regulatory affairs, for Advanced Energy Economy, a national association of businesses making the energy we use secure, clean, and affordable. AEE facilitates and supports the work of the Advanced Energy Buyers Group.