CARMEL, Ind. — A former airline executive is slated to become the newest member of MISO’s Board of Directors, while two incumbents will retain their seats, the RTO’s voting members have decided.
Wise | Delta
Newcomer Theresa Wise, former chief information officer for Delta Air Lines, will join Baljit “Bal” Dail and Thomas Rainwater to begin three-year terms on the nine-member body beginning Jan. 1.
Wise has also served as an executive consultant at Amtrak and CIO for Northwest Airlines. She holds a bachelor’s in mathematics from St. Olaf College and a master’s and Ph.D. in operations research from Cornell University.
“We are pleased to have an executive with Theresa’s knowledge and experience join the board. … With Theresa’s election and Bal and Tom returning to the board, we are well positioned as a governing body to continue providing steady, strategic guidance as MISO leadership navigates future challenges and opportunities,” board Chairman Michael Curran said in a statement.
Dail stood for a fourth term after receiving a waiver of rules limiting directors to three terms. MISO’s Nominating Committee granted the exception in June, saying Dail was needed to preserve the board’s knowledge about information technology. The decision was not taken lightly, committee members said. (See “Committee Permits Consideration of Extra Term for Dail,” MISO BoD Briefs.)
“Paul’s got some things he needs to tend to at home, and that’s going to take him away from MISO for the time being,” CEO John Bear said during a Nov. 14 Informational Forum. Bear commended Bonavia’s contributions over the last three years.
“Director Bonavia served MISO with the utmost commitment to our vision and mission — and we are grateful for his service,” Curran said. “He can leave the board knowing that his leadership helped propel the organization in the right direction.”
Vote Net Solutions, vendor for MISO’s election process, confirmed that 83 online ballots were cast. MISO needed 25% of its 138 voting members to participate to meet its quorum. Electronic voting was open for over a month.
John “Jeb” Bachman, former partner at PricewaterhouseCoopers, and Wolfgang Richter, former CIO at the consulting firm, stood as alternates in the election in the event that any of the candidates failed to garner a majority vote, but neither alternate proved necessary. In MISO board elections, alternates only rotate into the election for a second round of voting if any of the candidates don’t receive a majority in the first round.
PJM on Wednesday released a proposal for revising price formation rules in its energy markets, teeing up stakeholder deliberation on changes that staff estimate could increase market costs by as much as $1.4 billion.
The two-part plan focuses on reducing out-of-market payments and changing shortage pricing to “accurately reflect the value of energy and reserves during reserve shortages.” PJM expects to present the plan to members through a problem statement and issue charge proposed at a Dec. 7 Markets and Reliability Committee meeting. It hopes stakeholders will approve a motion to examine the proposal through the stakeholder process at a second MRC meeting two weeks later.
An example presented by PJM highlights how its current LMP-calculation method fails to represent true incremental cost. When a flexible unit is on the margin, the LMP is its offer price, but when it is an inflexible unit, the LMP drops to the next flexible unit’s offer. The inflexible unit receives uplift as an out-of-market payment to compensate for its costs. PJM’s proposal would set LMP at the inflexible unit’s offer and pay flexible units lower in the stack to follow the reduction in load. | PJM
“Getting prices right is of growing importance, anticipating a continued increase in the penetration of intermittent resources,” the report says.
LMP Changes
PJM plans to reduce out-of-market payments, such as uplift, by allowing inflexible units — which can’t change their output incrementally — to set LMPs and paying flexible units to better follow load changes.
Speaking during a media briefing Wednesday, PJM’s Stu Bresler said that when the RTO implemented LMP, it knowingly included several “simplifying assumptions” that the algorithm wouldn’t consider units’ fixed costs in the market optimization or allow inflexible units to set prices. The assumptions “served very well,” but some of the “downsides … were masked … often enough” by flexible resources on the margin and setting prices with higher costs than inflexible units, he said.
“In the past, higher-cost flexible units set price often enough to ensure that all needed resources could earn sufficient revenues in the energy market, when combined with capacity revenues, to drive efficient resource investments,” the report says. “Today, the continuing penetration of zero-marginal-cost resources, declining natural gas prices, greater generator efficiency and reduced generator margins resulting from low energy prices have resulted in a generation mix that is differentiated less by cost and more by physical operational attributes.”
Allowing inflexible units to set LMPs and incentivizing flexibility will reduce out-of-market uplift payments and increase the value of flexible units with higher LMPs and flexibility compensation, PJM argues. The extended LMP method, which PJM had told FERC it was “actively exploring,” would bifurcate its security-constrained economic dispatch into separate dispatch and pricing runs, as is already done in MISO, ISO-NE and NYISO.
Shortage Pricing
To address shortage pricing, PJM proposes to create a 30-minute operating-reserve product to supplement its current 10-minute reserves and to revise its operating reserve demand curve to more accurately value granular amounts of reserves.
“Improved shortage pricing would substantially enhance market performance,” the report said, through incenting demand response and distributed generation “when it is most needed,” reducing the “‘missing money’ problem” that creates generators’ reliance on capacity market revenues and providing better signals for transmission investment.
“PJM believes that it is critical that … the shortage-pricing mechanism be reviewed and enhanced,” the report said.
Costs
Bresler noted that other grid operators, including MISO and ISO-NE, have already implemented portions of these proposals. He said either element would be “beneficial,” but that “we think the maximum benefit would be achieved by implementing both.”
The changes would affect both the real-time and day-ahead markets and come at a cost. PJM estimated the energy market changes will likely reduce capacity market costs but still increase overall costs between 2 and 5%, or between $440 million and $1.4 billion, annually.
Bresler said it isn’t possible to determine how the proposals would interact with any decision FERC makes on the coal and nuclear price supports suggested by the U.S. Department of Energy or if they would create any instances of double compensation.
“It’s very difficult to answer that question in the hypothetical,” he said.
Timing
PJM included the proposal in its comments to FERC on the DOE request, arguing that the commission should ignore the department’s ideas and instead give the RTO a deadline to present for approval its own solution. PJM had previously floated its proposal at a FERC technical conference on price formation. Members have criticized the RTO’s actions as attempting to bypass its stakeholder process.
Bresler said PJM is “very much looking to engage our stakeholder process with the proposal” but declined to rule out filing the revisions unilaterally if they don’t receive stakeholder endorsement.
“It’s too soon to answer that question,” he said. “We did suggest to FERC that putting some time bounds around that discussion and … requiring something back from PJM by some date in 2018 would be beneficial, and I think we’ll probably suggest [to stakeholders] … that we get in front of FERC [for approval] sometime in the fall of 2018.”
PJM included in its proposal the same letter of endorsement from Harvard economist William Hogan that it submitted with its FERC filing, but the RTO referenced none of the criticism that accompanied the proposal. (See NOPR Reply Comments Bring More Criticism of PJM Proposal.)
A police report, obtained by RTO Insider from the Gwinnett County Police Department in suburban Atlanta, quotes Cauley’s wife as saying he attacked her after she discovered him having cybersex with a “young female employee of his.”
Cauley was arrested for battery, a misdemeanor, in the early morning of Friday, Nov. 10. NERC placed Cauley on a leave of absence after his arrest and named General Counsel Charles Berardesco as interim CEO. (See NERC CEO on Leave After Arrest for Domestic Violence.)
Reached at home Tuesday night, NERC Board Chairman Roy Thilly declined to say whether NERC would investigate Cauley’s alleged relationship with a subordinate. The employee was not identified in the police report.
“I cannot talk to you about this matter,” Thilly said. “It’s a personnel matter, and it has to be handled very carefully.”
NERC later issued a statement saying the board “has engaged counsel to assist in conducting a thorough investigation” of the allegations. “The board takes the allegations seriously and based on a deliberate and objective investigation will act in NERC’s best interests,” it said.
The statement quoted Thilly, who said he is “in constant communication with NERC’s senior management team as they remain fully focused on NERC’s mission to assure the reliability and security of the bulk power system.”
According to the report, Jean Cauley told a responding police officer that she and Gerry are getting divorced and that he was living in the basement of their home in the Sugarloaf Country Club gated community in Duluth, Ga.
Jean told the officer she had washed several of Gerry’s shirts and was bringing them to his room. When she entered the room, she found her husband in front of an iPad. Shocked, she took the iPad, which she said is hers, and also found what the report describes as “several personal pictures of Gerald.”
At that point, Jean said her husband pushed her into a wall and then into a bathtub. “She stated that while Gerald was pushing her around, he asked her what she wanted and stated that if she calls the police, he will lose his job and she will get nothing from him.”
Police reported observing scratches and bruises on Jean and “that the bathmat was dishevelled [sic] and several of the shower curtain rods were pulled off.”
The arresting officer said she “could smell a strong odor of alcoholic beverage from several feet away” when she spoke with Gerry, who denied causing his wife’s injuries “and refused to say any more.”
Gerry was handcuffed and transported to the county jail. Jean, who was transported to a local hospital, was experiencing a great deal of pain in her back — which had recently been operated on.
The NERC Board of Trustees posted a notice Saturday saying it “is aware of the personal incident involving” Cauley and saying he is on a leave of absence “until further notice.” The board added that it is “taking steps to ensure the work of NERC continues seamlessly.”
NERC’s loss of its CEO comes as the reliability agency has found itself sucked into the debate over Energy Secretary Rick Perry’s proposed rescue of coal and nuclear plants that he contends are vital to the reliability of the grid.
On Tuesday, NERC officials held a webinar to announce the release of a report on potential reliability problems from natural gas delivery disruptions. There was no mention of Cauley. (See NERC: Dependence on Natural Gas Alters Resilience Planning.)
California electricity suppliers have met the state’s 25% renewable generation requirement, in many cases exceeding it substantially, state regulators said.
The state’s three large investor-owned utilities have also signed contracts with renewable suppliers necessary to exceed the requirement that they meet 33% of customer energy demand with renewables by 2020, the California Public Utilities Commission said in its Renewables Portfolio Standard report for 2016, issued Nov. 13. The commission is required to submit quarterly and annual reports to the state legislature on the industry’s progress in meeting RPS goals.
Retail electric sellers were required to meet 25% of load with RPS-eligible resources by the end of 2016. Pacific Gas and Electric reached about 33% renewables, Southern California Edison about 28% and San Diego Gas & Electric nearly 43%.
An aggregated forecast projects the utilities will meet the 2030 requirement of 50% by 2020, according to the PUC, which administers the RPS with the California Energy Commission. The PUC’s role includes setting policies for implementation, reviewing RPS procurement plans, reviewing IOU contracts and enforcing compliance.
PUC Commissioner Clifford Rechtschaffen said: “Our utilities are exceeding the goals we put in place for them. Costs have continued to decline, and reliability has not been compromised in any way. California’s successful program offers lessons for other states interested in advancing clean energy policies.”
The program requires IOUs, community choice aggregators, electric service providers and publicly owned/municipal utilities to procure renewables to reduce greenhouse gas emissions, stabilize electricity rates, diversify energy resources and contribute to reliability.
The state’s five CCAs and various multijurisdictional utilities report they are compliant with RPS requirements and expect to meet or exceed the 33%-by-2020 requirement.
RPS Compliance Period Requirements (2017-2030) | California Public Utilities Commission
California’s latest RPS requirement of 50% renewables by the end of 2030 was set in SB 350, signed by Gov. Jerry Brown in 2015. The State Legislature is getting heavy pressure from environmental groups to pass a 100% zero-carbon bill that would include nuclear and large hydro in the last 40% of the requirement. Lawmakers are due to take up the legislation in January. (See CAISO Regionalization, 100% Clean Energy Bills Fizzle.)
The state’s IOUs are currently over-procured for renewables and held no annual solicitations in 2016. But they were required to procure renewables through other programs to meet the future RPS and other state policy goals. These include the Renewable Auction Mechanism, Bioenergy Renewable Auction Mechanism, Renewable Market Adjusting Tariff and Bioenergy Market Adjusting Tariff.
IOUs are also required to comply with “least-cost, best-fit” methodology to ensure the most cost-effective resources are being procured. The PUC plans to reform the methodology.
The average price of utility-scale wind contracts has dropped 47% in the last decade, CAISO says
It said contract prices for solar photovoltaic fell 77% between 2010 and 2016 to an average of $29.17/MWh, and IOU contracts for wind fell by 47% to $50.99/MWh. This is because of the rapid expansion of the market and decreasing technological cost.
The report also lists challenges in meeting RPS requirements, including uncertainty in IOU load forecasts, curtailment of solar due to oversupply at certain periods, stranded costs that could end up with remaining IOU customers as other customers migrate to CCAs, and significant terminations in the Renewable Market Tariff program — a feed-in tariff for small, distributed renewable energy technologies.
Planners must give more weight to potential pipeline outages in electric reliability reviews, NERC said in a report Tuesday.
“In light of the power sector’s rising reliance on natural gas, the loss of gas facilities must be added to the list of potential extreme contingencies used to measure system reliability impacts,” John Moura, NERC’s director of reliability assessment and system analysis, said in a statement announcing the report.
The report shows the impact of natural gas delivery disruptions will vary depending on the location and density of infrastructure. But the reliability authority says mitigation strategies are available to reduce the potential harm to the electric sector.
Natural gas has had an out-sized influence on electric generation. | Matcor
The report, “Special Assessment: Potential Bulk Power System Impacts Due to Severe Disruptions on the Natural Gas System,” listed several key mitigation strategies, including transmission upgrades, dual-fuel capability, power imports, adding incremental and diverse generating resources, firm fuel agreements and battery storage.
NERC said the power sector is seeing a drop in the number of dual-fuel units. Developers are foregoing the added expense of dual-fuel capability in many new projects, it said.
It also suggests dual fuel, backup pipeline capacity, and alternative sources of supply should be required in areas with significant risk.
“Dual-fuel capability increases generation reliability and resilience,” the report said, noting dual fuel is currently limited by environmental regulations restricting how long plants can run on oil. NERC called for temporary air permit waivers before any “sustained natural gas infrastructure disruption,” saying waivers should be incorporated into “resilience-planning initiatives when they are required.”
The assessment does not directly take on the Department of Energy’s directive that FERC strengthen the grid’s resiliency by propping up the finances of coal and nuclear plants, but it does point out the growing importance of natural gas as a fuel supply.
“Natural gas resources have become much more diversified,” Tom Coleman, NERC’s director of reliability assessments, said during a media conference call. “Twenty years ago, we were more reliant on Gulf [of Mexico] supplies. We have much more shale gas in some of the market areas that has really changed the dichotomy. Due to this diversity, we don’t have the same risks we had 20 [or] 25 years ago.”
The report offers recommendations to policymakers, the industry and NERC itself. It calls for regulators to consider fuel diversity when they evaluate system plans and establish energy policy objectives. It also recommends expedited licensing of new transmission and natural gas facilities to diversify risk.
NERC suggests registered entities consider the loss of key natural gas infrastructure in their planning studies, and that the gas and electric industries increase coordination and information sharing “to promote reliability and interdependent system integrity.”
“As our power supply becomes increasingly dependent on natural gas, industry must ensure this just-in-time fuel is as reliable and secure as the power plants that need the fuel to operate,” the assessment says.
The organization also recommends adding planning and operating requirements for analyzing disruptions to its reliability standards. To mitigate common causes of failure, it said its Generator Availability Data System (GADS) database should begin collecting additional information on the duration, frequency and causes of natural gas outages.
NERC conducted the assessment by reviewing existing studies, evaluating gas storage facilities and identifying generation clusters — areas with at least 2 GW of gas generation — to determine potential vulnerabilities.
NERC’s Generation Clusters | NERC
Coleman said the organization studied 24 areas, 18 of which “demonstrated the need for additional follow-up and analysis, based on power flow and stability issues” of the “extreme cases” it ran.
“We wanted to develop a bookend, a worst-case scenario,” he said.
Coleman said natural gas demand has “altered the storage dynamics,” which have historically operated as an inventory hedge by injecting in the summer and withdrawing in the winter.
“With much more electric generation out there, we’re seeing more of an annual injection and withdrawal cycle, versus just a winter and summer dichotomy.”
The report was received coolly by the American Petroleum Institute, which called it “a missed opportunity to properly examine ways to improve the reliability and resilience of North America’s electric grid.”
It said NERC acknowledged “that natural gas supply disruptions are extremely rare events and … that industry is taking steps to prevent such disruptions.”
It cited its joint report with the Natural Gas Council on resilience, which was released in July.
BALTIMORE — Department of Energy officials and FERC Chief of Staff Anthony Pugliese traveled 40 miles from the capital Monday to make their case for coal and nuclear price supports at the National Association of Regulatory Utility Commissioners’ 129th Annual Meeting.
In the morning, Pugliese and Bernard McNamee, DOE deputy general counsel for energy policy, spoke at a breakfast meeting sponsored by the Consumer Energy Alliance. After lunch, Sean Cunningham, DOE’s executive director for energy policy — and a former lobbyist for FirstEnergy and American Electric Power — lectured the audience on how he said FERC had failed to protect the grid against disaster. The audience included Commissioner Cheryl LaFleur — who kept her head down, writing notes and betraying no reaction.
The department’s Notice of Proposed Rulemaking (RM18-1) was a big topic of conversation both at the microphones and in the hallways at the Hilton Baltimore beside Oriole Park at Camden Yards. But LaFleur and Commissioner Robert Powelson, who spoke to consumer advocates in the morning, had little to say on how they will vote next month on the controversial proposal.
FERC Chairman Neil Chatterjee said last week he will seek an interim “lifeboat” to ensure the survival of struggling coal and nuclear plants while the commission ponders long-term rule changes. Chatterjee has said the commission will take action by Dec. 11 on Energy Secretary Rick Perry’s call for “full recovery” of coal and nuclear plants’ costs in RTOs with energy and capacity markets, including PJM, ISO-NE and NYISO. More than 700 comments were filed in response to the proposal. (See NOPR Backers, Foes Seek Last Word at Comment Deadline.)
LaFleur, Powelson Respond
LaFleur declined to comment on Chatterjee’s plan.
“I’ve really tried to spend my time thinking through the issues and not debating in the press. So, for now, I’ll just stick there, I think,” she said, adding, “But it’s less than a month so you’ll be hearing from us.”
Powelson also declined to say if he would support the chairman’s proposal.
“We’ll listen and see what everybody’s saying,” he said in an interview after speaking to the National Association of State Utility Consumer Advocates (NASUCA), which is holding its annual meeting alongside NARUC. “I don’t want to prejudge any outcomes.
“I’m open to having a broader conversation around valuing resiliency; looking at reliability metrics beyond just the capacity construct. And making sure … that we stay above and out of the fuel war conversation. That’s not the FERC’s role.
“I don’t think the secretary’s asking us to revert on organized markets,” Powelson added. “I think what he’s saying is, look at some of the things that are working in these markets and some of the things that aren’t working.”
But at the General Session after lunch, DOE’s Cunningham made it clear he already knows the answers.
“The bottom line is this: Coal and nuclear power remain crucial to the continued functioning of the electric grid,” he said.
He used a revisionist view of the 2014 polar vortex to make his point.
“Because a large portion of gas supply is diverted to home heating, the grid operators struggled to meet demand and gas generators became unavailable. It was then that coal and nuclear plants came to the rescue. Because these plants are true baseload generators with onsite fuel storage, they successfully met the emergency demand,” he said.
In its response to Perry’s proposal, PJM said the NOPR “mischaracterized and misconstrued” the polar vortex, noting “PJM’s system remained reliable despite nearly 14,000 MW of coal retirements” and saying the 22% forced outage rate had been “mitigated” by the Capacity Performance rules enacted afterward.
“Contrary to the DOE NOPR, neither the 2014 polar vortex nor the recent hurricanes justify upending existing competitive energy markets,” PJM said, noting that some coal plants were idled because of frozen fuel and conveyor belts. “While fuel delivery was an issue during the polar vortex, it was not the driving factor behind outages that occurred during the extreme weather event, nor was gas-fired generation the villain, nor coal and nuclear the savior, that the DOE NOPR suggests them to be,” PJM said.
DOE: FERC Slow to Respond
Cunningham painted a dire future without coal and nuclear generation.
“Unfortunately, due in part to years of pressure brought to bear by opponents of coal and nuclear power, many of those plants were and are scheduled to close, which makes any number of disasters — or just a hot day in October or a cold one in April — a significant potential threat to our grid today. What if they had closed? How would that closure have affected the functioning of our hospitals? How would it have affected our police and firefighting capabilities? How would it have impacted the operations of our military?”
Cunningham said FERC has been slow to respond to the threat.
“FERC has been studying these issues for years, but the problem remains,” he said. “Secretary Perry’s proposal was intended to jump start a long overdue conversation — and more importantly, to spur FERC to action.”
“Washington has been stacking the deck against coal and nuclear power for years despite their benefits to the grid,” Cunningham added. “President Trump’s clear direction is to unleash every energy resource to make America energy dominant. … The president has nominated the people for government service who share that vision and are willing to address the regulatory burdens and government overreach that have limited our growth potential. Secretary Perry is doing, and will continue, to do everything in his power to jeep our diverse energy mix in place.”
Chatterjee Aide Chimes In
During the earlier meeting, DOE’s McNamee also defended the NOPR, echoing Cunningham’s response to critics who fear it would disrupt wholesale markets. Electric markets are not free, they said, but are shaped by policies such as the tax credits for renewables. “The fundamental fact [is] that the markets are distorted,” McNamee said.
FERC’s Pugliese responded to complaints that the commission’s deliberations were being rushed because of Perry’s 60-day deadline.
“I don’t think it is” too little time, Pugliese said. “Within PJM, this has been an issue that has been discussed for three-plus years. But for a lot of places around the country it … wasn’t. And so, all the sudden now we get 60 days, and I will tell you first-hand, every group around the country is coming in, every chance they get, to come give us ideas.”
‘Lifeboat’
Chatterjee laid out his “lifeboat” plans in remarks at an industry conference and in an interview Thursday on Bloomberg television.
In a meeting with reporters last month, Chatterjee said FERC’s options include initiating its own rulemaking, convening a technical conference or issuing a final rule based on DOE’s NOPR.
Now, facing legal and political obstacles to winning approval of a final rule, Chatterjee said he is seeking a short-term plan to rescue as many plants as possible while the commission does additional fact-finding.
“What I don’t want to have is plants shut down while we’re doing this longer-term analysis, so we need an interim step to keep them afloat,” Chatterjee told the S&P Global Platts Energy Podium in D.C. “I don’t know that we can get everybody in the lifeboat,” he added.
“My approach is going to be one of no regrets,” he said in the Bloomberg interview. “The worst-case scenario would be we do the long-term analysis, we figure out we actually did need these plants, but they’re gone. They’re offline and we can’t get them back.”
He said his plan will not alter RTO dispatch practices or distort markets.
Chatterjee also disclosed he had met with FirstEnergy CEO Chuck Jones “to really kick the tires on what they proposed [in their comments on the DOE NOPR] and challenge them on some of what they had put forward.” FERC’s ex parte rules, which bar commissioners from private discussions with parties in “case-specific, contested proceedings,” do not apply to rulemakings, according to a 2010 presentation by FERC Associate General Counsel Lawrence R. Greenfield (18 CFR 385.2201(a), (b), (c)(1)(ii)).
FirstEnergy proposed that the commission require RTOs and ISOs adopt a pro forma Resiliency Support Resource (RSR) tariff agreeing to make monthly payments to “fuel-secure, resilient generators.” The payments would be “equal to its full costs of operation and service” and a “fair return on equity,” minus its revenues for capacity, energy and ancillary services.
Chatterjee, a native of coal state Kentucky and a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), has made no secret of his desire to aid coal generators. Powelson, a Republican, and LaFleur, a Democrat, have reacted more warily to the Perry proposal, expressing concern it could damage wholesale markets.
Awaiting McIntyre and Glick
Republican Kevin McIntyre and Democrat Richard Glick, who were confirmed to FERC by the Senate on Nov. 2, are awaiting their swearing-in and have not commented publicly on the proposal. Chatterjee told Bloomberg that he had not discussed the NOPR or his interim proposal with McIntyre, who will replace him as chairman.
“Kevin is somebody with a lot of expertise. He’s a smart, thoughtful guy. … And I hope that he will ultimately be persuaded to follow the course that I’ve laid out,” Chatterjee said.
Perry’s Sept. 28 proposal requested that FERC issue a final rule within 60 days. But even if Chatterjee won the two additional votes he needs to approve a final rule in December, it could be vulnerable to court challenges on the grounds that it was rushed through without sufficient notice to the public and proper evaluation by the commission.
Powelson said he was looking forward to the arrival of McIntyre and Glick — who cannot join FERC until President Trump gives them their signed commissions.
“Having two other colleagues be part of this conversation is important,” he said. “I think we’ve got a lot of work ahead of us over the next 24 days.”
VALLEY FORGE, Pa. — PJM Market Implementation Committee members last week expressed frustration over a proposal from the Independent Market Monitor on price-responsive demand (PRD) requirements, saying they hadn’t been given any time to review it prior to voting on the issue.
Ruth Ann Price of Delaware’s Division of the Public Advocate apologized on the Monitor’s behalf and took responsibility for requesting the late submission, but the measure failed to garner stakeholder backing. The proposal was so unexpected that it didn’t make it into the presentation PJM posted on the issue. It received 28 votes in support, or 15%, far below the 50% threshold for approval.
Two other proposals — one from PJM and the other from Calpine’s David “Scarp” Scarpignato — did receive enough support and will be presented at the Markets and Reliability Committee meeting on Dec. 7. Because of the Thanksgiving holiday, PJM moved the November MRC to the first week of December.
At issue is how PRD will be held to Capacity Performance requirements. PRD was developed before CP existed, but PRD bids cleared the annual Base Residual Auction in May for the first time since the new construct was implemented. PJM has proposed extending annual requirements developed for demand response to PRD and trigger CP penalty assessments during performance assessment intervals when the LMP is greater than the PRD price curve. Scarpignato’s “Proposal C” would make the assessment triggers any performance assessment interval. (See PJM Grilled on Price-Responsive Demand Rule Changes.)
DR provider Whisker Labs had presented another proposal but retracted it in favor of the Monitor’s proposal. The IMM argued that all PRD eligibility and performance should be measured from the participant’s peak load contribution (PLC). Both the planned PRD and the amount finally registered should be measured as the PLC minus the participant’s firm service level (FSL) and performance should be measured as PLC minus the actual load, the Monitor proposed.
“The key difference is that in our proposal, it is based on the total consumption in the summer period,” the IMM’s Skyler Marzewski said.
Carl Johnson, representing the PJM Public Power Coalition, and Dave Pratzon of GT Power Group objected to the proposal’s late inclusion because neither had had a chance to review it and make voting recommendations to their membership.
“It’s tough when totally new proposals come in at the last minute with no explanation,” Pratzon said.
Monitor Joe Bowring explained to RTO Insider in an email following the meeting that his staff provided PJM with its proposal on Oct. 29, more than a week before the MIC, and attempted to present it at a meeting of the Demand Response Subcommittee the following day. He said they were told they could not present on such short notice.
“The IMM’s proposal was included in the posted matrix on Monday prior to the Wednesday MIC meeting,” Bowring said. “The IMM agrees that there was some miscommunication among the IMM, the DRS and the MIC.”
Pratzon requested an explanation for basing all measurements off the PLC. Marzewski said the measurement should reflect how much the participant can reduce from its overall peak demand, not how much it can reduce at that moment. PJM proposed using different peak-demand calculations for summer and winter measurements.
He remained unmoved.
“As of right now, I’m not seeing the justification for the different treatment,” he said.
Gregory Carmean, the executive director of the Organization of PJM States Inc., argued the baseline should be the load that the RTO would have purchased if not for reduction.
“It’s PJM that’s trying to turn this into a seasonal product” by changing the definition of the PRD measurement between summer and winter, he said.
Delaware’s Price, Joe DeLosa of the Delaware Public Service Commission and Greg Poulos, executive director of the Consumer Advocates of the PJM States, also voiced support for the Monitor proposal.
Advocates “want residential customers to be able to respond to price,” Poulos said.
Dave Mabry, representing the PJM Industrial Customer Coalition, argued that the purpose of PRD is to get “the customer back to paying for the capacity that he needs.”
“There isn’t a payment that flows back,” he said.
Scarp argued that point, and PJM’s Pete Langbein confirmed the performance is paid as a credit.
“Call that a payment, call that a credit, but that’s effectively what will happen,” Langbein said.
Scarp said “PRD was supposed to get away from” the “hypothetical difference” between what was scheduled to be used and what was actually used.
James Wilson of Wilson Energy Economics, who consults for consumer advocates in several PJM states, disagreed that the proposal increases winter-adequacy risks. PJM’s reserve requirements study always shows zero loss-of-load expectation (LOLE) in winter, he said, and “there’s a huge margin of excess winter capacity before we get anywhere near where that changes.”
Big Support for Jurisdiction Mention in DERS Charter
Stakeholders voted overwhelmingly to include explicit deference to state and local regulatory authority in the charter for the new Distributed Energy Resources Subcommittee. (See “DER Subcommittee Charter Sent Back to MIC,” PJM MRC/MC Briefs 10-26-17.)
FirstEnergy had proposed what it hoped was an uncontroversial amendment, which stated “Market rules must respect the distribution system and state/local jurisdictional agency standards and protocols to ensure safety and reliability. Rules should adhere to all pertinent jurisdictions and respect the relevant electric retail regulatory authority (RERRA).”
DER companies saw it as a potential barrier to market entry.
“The vagueness of ‘respect the … standards and protocols’ concerns us,” said Tom Rutigliano, who represents providers of distributed resources.
“I think it’s just a matter of clarification. It’s motherhood and apple pie — we have to follow these things. I really wonder why there’s the apprehension to having it in there. … I really don’t understand all the pushback,” FirstEnergy’s Jim Benchek said.
Exelon’s Sharon Midgley agreed. “This would give us a lot of comfort moving forward if this is added,” she said.
They got their wish. The original version of the charter received 17% approval, or just 26 votes in favor, while the amended version received 92% approval, or 160 votes in favor.
Seasonal DR Aggregation Registration Rules
EnerNOC’s Steven Doremus presented a proposed revision to PJM’s DR aggregation registration rules, arguing that the current method fails to maximize use of available resources. The proposal accompanied the first read of a problem statement and issue charge.
The current method is to take as the CP capability the lesser of the registrant’s summer or winter capability. The CP capabilities of the registrants are then added together for a total capability, but this leaves a substantial amount of DR undispatchable.
“The problem we see is this is not the most efficient way to register the customers,” Doremus said.
EnerNOC proposed adding up the summer and winter capabilities of all registrants and using the lesser of the two summations at the overall CP capability “to maximize the value.”
“It wouldn’t change the value; it wouldn’t change the annual requirement,” PJM’s Langbein said of the proposal. “It’s just how do we sum up winter and summer capabilities to ensure there’s an annual capability at the [Reliability Pricing Model]-resource level.”
Meetings Reduction
Responding to a request from the Members Committee, PJM staff reviewed the status of all issues assigned the MIC and subcommittees. Of the 23 issues, seven are completed and will be closed. Three others have proposals awaiting endorsement votes.
At the October Members Committee meeting, Vice Chair Mike Borgatti of Gabel Associates announced that the MIC, MRC, Operating Committee and Planning Committee will be directed to determine if any timelines can be relaxed to “free up a little room in the schedule.” The directive came at the request of stakeholders, who have been complaining about the roughly 500 stakeholder meetings PJM conducts each year. (See “Reducing the Workload,” PJM MRC/MC Briefs.)
Adrien Ford of Old Dominion Electric Cooperative thanked PJM for developing the review and taking a “leadership role” in streamlining the issues.
Account Cleanup
PJM will be automatically terminating accounts on its website that have been locked longer than nine months. The terminations will reduce security risks, as well as improve system performance, staff explained.
PJM.com has 141,000 accounts, but 60,000 have already been terminated. Of the remaining 81,000, approximately 37,000 have been locked for more than nine months, or about 46%. Only about 20,000 accounts are actively used.
Accounts can be restored, but account managers at member companies have been notified to review employees’ accounts and delete any unneeded ones.
CARMEL, Ind. — MISO is proposing to once again revise the equation behind its yearly resource adequacy survey issued in partnership with the Organization of MISO States.
The new adjustment for the 2018 OMS-MISO survey adds a “likelihood” weighting to account for the in-service dates of potential new capacity still in the queue, said MISO Resource Adequacy Coordinator Ryan Westphal.
Including queue resources “is a pretty new process, so there’s no history of a success rate yet,” Westphal said during a Nov. 8 Resource Adequacy Subcommittee meeting.
Last year marked the first time the survey began including in its weighted resource adequacy averages a 35% capacity share of projects in the definitive planning phase of the interconnection queue. But MISO at the time didn’t contemplate adding likely in-service dates into the equation. The RTO is now proposing to weight projects represented within that 35% share based on the likelihood they’ll complete the queue by a certain year.
Under the proposal, next year’s survey will weight according to status — 10% for projects not yet started and in the first phase of the queue, 25% for projects in the second phase and 50% for those in the third phase. All projects with signed generation interconnection agreements will count fully toward offsetting resource adequacy requirements. MISO will also credit new wind and solar resources at 16% and 50%, respectively, of nominal capacity.
The new approach to weighting will result in a far lower forecast of potential resources. In last year’s survey, MISO predicted that 2.2 GW of potential resources in the definitive planning phase would come online in 2019. By applying the new weighting to the 2018 survey, MISO expects only 0.1 GW of potential resources will come online in 2019. By 2020, MISO sees 0.7 GW in operation instead of an earlier prediction of 3.3 GW. The in-service forecast climbs to 2 GW in 2021, but that represents just more than half the 3.8 GW predicted last year.
Comparison of MISO potential resources in OMS-MISO Survey | MISO
Before this year, MISO stakeholders had criticized the survey as being too alarmist for not including any potential new resources without signed interconnection agreements. Inclusion of a portion of those resources in this year’s survey showed MISO will have 2.7 to 4.8 GW of excess resources from 2018 to 2022, a departure from the shortfalls predicted in previous years. (See Capacity Survey Shows MISO in the Black.)
Saying the new survey style could “dramatically” impact some zones, Exelon’s David Bloom asked for a zone-by-zone comparison showing how predictions for potential new generation will change from this year to the next.
“By changing the assumptions from year to year, I think what MISO is doing is changing results,” said Kevin Murray, representing the Coalition of Midwest Transmission Customers. “You’re going to go from reporting a surplus in 2019, to reporting a deficit simply by arbitrarily shifting assumptions.”
Westphal asked stakeholders to keep in mind that the change deals only with potential resources still in the queue, which the survey only began including last year. He said all generation with signed interconnection agreements will continue to be counted.
“Did the queue get worse in the last year? Did a bunch of resources drop out? What happened to lose about 2.1 GW in 2019?” asked Indianapolis Power and Light’s Ted Leffler.
Laura Rauch, MISO manager of resource adequacy coordination, said the 35% of new generation used in last year’s survey was not adjusted for the more realistic in-service dates.
“Last year, we took the in-service dates that owners provided with their queue application. Some of those generators hadn’t been studied yet,” Rauch said. She said updated in-service dates for potential wind resources have the biggest effect on MISO’s numbers.
Madison Gas and Electric’s Megan Wisersky said she was concerned change would spark public concern about capacity shortfalls.
“You look at how the survey gets used and abused out in the public,” Wisersky said. “Two things happen when the survey is released to people who don’t deal with these kinds of things every day. One: I know what happens when you show these types of deficits — things get dicey. Two: [People ask if] the queue process is leading to resource inadequacy. And that’s what I’m worried about when people without knowledge of these get ahold of them.”
Westphal said MISO has time to collect stakeholder advice and refine the survey over the next several months.
BOSTON — Atlantic Canada, New York and New England are one region geographically, and the jurisdictions will be drawn into ever closer cooperation on energy.
That was the consensus among a dozen or so speakers at the 25th Annual Energy Trade & Technology Conference hosted by the New England-Canada Business Council on Nov. 8-9. Speakers also discussed proposed price supports for coal and nuclear generation and how FERC is likely to treat New England states’ contracting for renewables.
Battery for New England
Hydro-Québec CEO Eric Martel said that his company last year exported more than 15 TWh of electricity into New England, about 12% of what the region is consuming now. The company has partnered on six different projects being bid into Massachusetts’ recent clean energy procurement. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
“Our large reservoirs have a combined annual energy storage of 176 TWh,” Martel said. “Today we are producing for the Canadian people 170 TWh/year [and] we are exporting about 30 TWh, which makes our production today at 200 TWh. But today our limit [on exports] is the number of transmission lines.”
Hydro-Québec began developing non-hydro renewable generation in the early 2000s and has since added 3,500 MW of wind capacity in Québec, Martel said.
“We firm up our domestic wind generation using our hydropower resources, so it’s very important that our source for firming is a renewable resource also,” he said. “We’ve been planning for this energy transition that is taking place, but what needs to happen now is to build those transmission lines. At peak periods, hydropower can be adjusted almost in real time, so Hydro-Québec can be the battery for northeastern America.”
NB Power CEO Gaëtan Thomas suggested how to connect the region to that huge battery.
“The only way to do that is more transmission,” Thomas said. “Transmission is king; transmission is going to solve these issues. Our vision should be to tie the whole region together and get to net zero [emissions]. That’s the only way we’re going to avoid the hits [caused by climate change] on the Eastern Seaboard. We’re all connected to it; we have that in common.”
DOE NOPR DOA?
Many speakers agreed that the U.S. Department of Energy’s recent Notice of Proposed Rulemaking in support of coal-fired and nuclear baseload generation wouldn’t amount to much, if anything.
But Concentric Energy Advisors CEO John Reed cautioned about being too optimistic.
“If we have one lesson from this administration, if you look at immigration or health care, the answer is, if at first you don’t succeed, tweet, tweet again,” Reed said. “If this doesn’t go somewhere, and if you look at the initiatives that have occurred in Ohio, Illinois and New York to support baseload generation, what is going to come down as the next mandate, the next executive order on these issues? Because I don’t think the administration’s concerns in terms of supporting coal and nuclear and other baseload generation are going to go away.”
“What I would expect — and PJM is already looking into it — is how to price things perhaps differently,” said Avangrid CEO James Torgerson. “And I think the other organized markets will probably be told to do the same thing. I think each RTO and ISO is going to be looking at it from their perspective, and [if there is] an issue in their area that needs to be dealt with. FERC will probably push it back to the different regions to get it resolved on a regional basis, because you can’t just say it’s a national or international problem at this point; it’s in certain pockets.”
Michael Twomey, vice president for external affairs at Entergy, defended nuclear energy’s role as an emissions-free resource. Nuclear power’s contribution to New England’s energy needs has remained generally unchanged because the retirement of Vermont Yankee was offset by upgrades and increased capacity from other units, he said.
“Oil has effectively disappeared from the landscape, coal is reduced significantly, and hydro and renewables honestly haven’t moved that much,” Twomey said. “We’ve seen tremendous gains in carbon emissions reductions in New England over the last 15 years, but that’s mainly been attributable to the substitution of natural gas for oil and coal. Well, the oil and coal is going to be gone — soon — and there’s not going to be any more low-hanging fruit to achieve carbon reductions, so what we’re going to see is probably an increase in carbon emissions from where we are now, going forward, as you see new retirements.”
An Accommodating FERC?
FERC is entering a much more “state-centric” cycle, according to Rob Minter, vice president for government and regulatory affairs at ENGIE.
“Confidence in the markets for maintaining things like fuel diversity to keep nuclear plants alive, to integrate renewables, to achieve public policy goals like carbon reduction does not fit with the market structure that we now have,” Minter said. “Everyone’s trying to build the type of plants they want for their own objectives, for their own fuel reliability, for economic development, to save stranded assets that are uneconomic and underwater but make sense, like a nuclear plant you need to continue to have low carbon. These are not compatible with the current wholesale market that was created in the 1992 Energy Policy Act.”
“You start wondering how much of this [NOPR] is about reliability and fuel diversity versus some of the generators who have coal and nuclear plants aren’t really making as much as they did in the past,” Torgerson said. “So those are things being debated right now.” He predicted FERC will set a technical conference so industry participants can examine the issue more thoroughly.
To implement different state public policies on clean energy requires out-of-market actions that are fundamentally incompatible with the wholesale market design, Minter said.
“You can find a way to price those attributes into the markets, but my god, you end up putting dozens of pricing mechanisms and algorithms into an already complicated market,” Minter said.
He said although he would prefer fully competitive markets, they have “very little chance of success.”
“I would like for it to work; I would like to see fully competitive wholesale markets,” he said. “But regulators are not willing to accept the risk of very high energy prices that happen during periods of scarcity.”
Leo Desjardins, CEO of Conservation Resource Solutions, said the new, fully staffed commission has arrived at an inflection point for markets.
“Massachusetts probably gets its way on Canadian imports [and] FERC figures out how to accommodate regional and state carbon pricing,” Minter said. “And I think you’ll see that [the] large renewable procurements that states want, that end up being out-of-market, get accommodated. Only for so long can a commission like FERC fend off states. If the number of states [asserting their public policy] grows, and as the frustration level grows, they eventually have to cave in and accommodate.”
VALLEY FORGE, Pa. — PJM’s Asanga Perera presented stakeholders at last week’s Planning Committee meeting with a problem statement and issue charge to address issues the RTO sees with its current process for evaluating market efficiency projects.
“We have conducted two cycles to date since FERC Order 1000 was established, and during these two cycles, we recognized various challenges that we think are important to address going forward,” he said.
One of the issues, Perera explained, is that PJM’s benefit-to-cost calculations beyond 10 years are extrapolations, not more accurate simulations.
“We have discovered, in certain instances, we may end up either overstating benefits or understanding benefits, especially on a longer horizon,” he said.
PJM also must address modeling issues, timing of the proposal-window process, interregional analysis and project re-evaluation, Perera said.
Sharon Segner of LS Power applauded the focus on the process but asked if it could go further.
“This is a great discussion in terms of some of the challenges that the market efficiency window is facing,” Segner said. “Is there anything missing?”
PJM staff resisted suggestions to include a review of cost calculations, saying that’s being handled elsewhere.
Segner also warned against making any retroactive changes.
“It’s important to not undermine the work of the past, because that’s going to create a lot of regulatory uncertainty,” she said.
If the initiative is approved, the work would be assigned to a task force, Perera said.
PJM has compiled some data to begin updating parameters for modeling light-load conditions. PJM’s Mark Sims presented the data.
“There’s definitely plenty of activity happening out there to draw some conclusions,” he said.
One focus is comparing high-voltage alarms with instances when high-voltage emergency procedures were taken. The alarms, which require generators receiving them to take action, precede emergency procedures that PJM takes.
“The alarm data is a good proxy to use moving forward to look for statistical values to develop parameters” for a test, Sims said.
PJM is also considering how to address the lag between recognizing an issue and compiling all the information to address it effectively.
“Between it happening and us fixing it, it could be a couple of years,” Sims said.
Mild weather meant load never came close to reaching the peak summer forecast, PJM’s John Reynolds said.
The summer peak of 145,331 MW on July 19 was 5% below the forecasted peak of 152,999 MW and 4.4% below the 2016 peak of 151,945 MW. “The champ still reigns,” Reynolds said, referring to PJM’s all-time peak of 166,876 MW on Aug. 2, 2006.
There were 0.4 MW of load management July 19, he said, and there have been anecdotal accounts of a “significant amount” of peak shaving this summer.
The decline in weather-normalized load won’t mean an immediate drop in load forecasts.
“That would be an assumption that people should not make,” Reynolds said. “It will take time for that to work its way in full.”
The call for patience confounded Calpine’s David “Scarp” Scarpignato.
“I don’t want to wait 18 years to get the forecast right,” he said.
ARR Analysis IDs Constraints
An analysis of Stage 1A 10-year auction revenue rights found “infeasible facilities” both within PJM’s footprint and in market-to-market interactions with MISO, Perera said.
The internal constraint will be addressed by a project (b2774) in the Regional Transmission Expansion Plan, which is expected to be in service in 2020. Of the remaining nine M2M constraints, one will be addressed by a MISO Transmission Expansion Plan project that is expected to be in service this year. Three others have projects under consideration, two will be included in a future targeted market efficiency project proposal window and three are pseudo-tie flowgates.
Asked specifically about lines connecting to the Ohio Valley Electric Corp. — which is attempting to join PJM as a transmission zone — Perera said no new issues were identified. A project between OVEC’s Clifty Creek Power Plant and the Trimble County substation is one of nine M2M constraints under consideration.
