Stakeholders reminded PJM on Thursday to tread lightly when it comes to determining the “reasonableness” of estimated construction costs as the RTO works on revisions for Manual 14F that will include its new fee structure for competitive transmission proposals.
The revisions, borne out of a stakeholder motion endorsed by the Markets and Reliability Committee last year, will codify the comparative cost framework the RTO will use to evaluate these projects. (See “PJM Unveils Flat Fee Cost-containment Plan” in PJM PC/TEAC Briefs: Aug. 8, 2019.) Since implementation of FERC Order 1000 in 2014, PJM has reviewed 850 competitive proposals, of which less than 20% included cost commitment provisions.
Transmission owners, in particular, took issue with PJM’s revisions in Section 8.4.3 that read “if a project proposal does not include a cost commitment provision, PJM will assess project specific risks (for example, the risk of a proposed project’s estimated costs being exceeded), scope of the project, magnitude of the proposed cost and the reasonableness of the estimated construction costs.”
“We still have some concerns with your language,” said Alex Stern, manager of transmission strategy for Public Service Electric and Gas. “A bedrock principle that the special TEAC’s coalesced around several years ago is that PJM is not and should not be suggested in any way to be a rate regulator.”
Stern was speaking on behalf of most of the TO sector, who collectively had initially conceived of presenting their own Manual 14F revisions but backed off the idea in favor of finding consensus with PJM instead.
Sharon Segner, vice president of LS Power, agreed with Stern, telling PJM “reasonableness should be cost-effectiveness.”
“I don’t think you need to put yourself in the place of judging reasonableness in that way,” she said.
Mark Sims, PJM’s manager of infrastructure coordination, said staff has no interest in influencing what costs are considered “reasonable.”
In a similar vein, Stern and other TOs found fault in supplemental revisions to PJM’s language from the Independent Market Monitor that would encourage a cap on operational and maintenance (O&M) costs.
“I just don’t think its good policy for PJM or anyone to support limiting O&M,” he said. “I’m not saying if the developer wants to limit it that they should be prevented from doing so … I just don’t think a reliability organization should be overtly encouraging entities to cap the O&M.”
David “Scarp” Scarpignato, of Calpine, agreed and suggested PJM focus more broadly on whether a proposal “met its cost commitments.”
“I don’t think you guys are in the regulating business itself, so I don’t think you should, even if you could, determine if the rates are correct in the end,” he said.
Joe Bowring, PJM’s Independent Market Monitor, defended his set of proposed cost caps, saying “it’s real, so it should be included in the list.” He also said PJM should consider, in the absence of a cost commitment provision, the “review of project specific risk, and reasonableness of each component of costs including the initial capacity costs, the annual revenue requirements and the cost of capital.”
“You need a metric that people know you are going to use,” he said. “If it’s not revenue requirement, then there’s no standard and no point of doing an analysis.”
PJM’s collected project proposal fees versus actual analysis expenses. The RTO is working on Manual 14F revisions that will codify its proposed comparative cost framework for competitive transmission proposals. | PJM
TOs also questioned the appropriateness of manual revisions that would memorialize an ongoing collaborative role between the PJM and IMM in reviewing competitive transmission proposals.
“PJM’s manual should not proscribe what the Market Monitor can and cannot do and, perhaps equally as important, what PJM can and cannot do in coordination with the Market Monitor,” Stern said. “The IMM is not necessarily supposed to be tightly coordinated with PJM. It is supposed to be independent and is supposed to monitor and is free to perform any independent analysis that it wants or none.”
PJM will bring the proposed fee structure and the Manual 14F revision to the MRC on Oct. 31 for a first read. Endorsement is slated for Nov. 14 at the PC and Dec. 5 at the MRC.
VALLEY FORGE, Pa. — PJM’s Planning Committee deferred voting on a problem statement and issue charge on critical infrastructure mitigation projects in light of a webinar planned by transmission owners to further discuss stakeholders’ transparency concerns.
Stakeholders agreed Thursday to delay voting on the proposal for one month after Exelon’s Pulin Shah suggested some of the issues raised in the proposal would be discussed in the meeting. The D.C. Office of the People’s Counsel, which proposed the initiative, said a delay was unnecessary but acquiesced nonetheless.
The issue came to a head at the Markets and Reliability Committee meeting in August when incumbent TOs asked for feedback on a proposed Tariff attachment that would establish a process for vetting transmission system enhancements designed solely to reduce the number of critical assets identified under NERC’s critical infrastructure protection standard CIP-014, of which fewer than 20 exist within the PJM footprint. NERC deems these assets “highly critical … that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.”
The Consumer Advocates of the PJM States and other stakeholders expressed concern about the opaqueness surrounding the TOs’ proposal. (See PJM TO Tariff Filing Stirs up Transparency Concerns.) The D.C. OPC then came to the September PC meeting with a problem statement and issue charge to create language for PJM’s manuals, Tariff and Operating Agreement that addresses future management of critical transmission assets on NERC’s CIP-014 list. (See “Consumer Advocates: CIP-014 Projects Need More Transparency,” PC/TEAC Briefs: Sept. 12, 2019.)
“One of the big concerns that we really heard from all quarters was that whatever process is looked at here, that we should cover not just the facilities covered by the Aug. 12 notice, but those that might become security-impacted facilities in the future,” said Erik Heinle of the D.C. OPC. “So, we want to make sure we have a process that works for a broad set of facilities in that respect.”
Shah said TOs hope to schedule the webinar early next month, ahead of the Nov. 14 PC meeting.
2019 Installed Reserve Margin Study Results
PJM’s Patricio Rocha Garrido said the final values of the 2019 Installed Reserve Margin study differ from those presented to the PC last month.
The annual study determines PJM’s installed reserve margin (IRM) and forecast pool requirement (FPR), which will reset key parameters for the RTO’s upcoming capacity auctions.
The recommended IRM is now 14.8% and the recommended FPR is 1.0860 with an average equivalent forced outage rate on demand (EFORd) of 5.4%. Rocha Garrido said the new values account for deactivation withdrawals submitted in July.
He said the 2019 load model and capacity benefit of ties put “downward pressure” on both the IRM and the FPR. The retirement of 8,600 MW of generation and the addition of 15,000 MW of more efficient resources — mostly combined cycle plants — explained the 0.5% reduction in EFORd.
The PC endorsed the results by acclimation. The MRC will hear a first read of the results at its Oct. 31 meeting.
ELCC Methodology Revisited
PJM said it’s time to revisit its proposed methodology for calculating wind and solar capacity values after discussions last spring went nowhere.
The RTO wants to use an effective load-carrying capability (ELCC) calculation, which measures the additional load that a group of generators can supply without a reduction in reliability.
“The ELCC method is meant to be a consistent way of valuing all the resources in the system,” Rocha Garrido said.
The five-step ELCC process for delivery year 2022/23 would begin with an average of the ELCCs for each year since 2012/13. The RTO has determined that the composite ELCC is 4,181 MW, 21% of the 19,910 MW of nameplate wind and solar capacity projected for 2022/23.
After calculating the ELCCs for the two generation types separately, PJM would then prorate the shares between wind and solar, resulting in capacity factors of 12.3% and 45.1%, respectively. (See “PJM Pushes Change in Wind, Solar Capacity Measurements,” PJM PC/TEAC Briefs: Feb. 7, 2019.)
PJM’s ELCC formula represents a shift in thinking for the RTO, which had been pushing an alternative method using average values. The new methodology is more representative of the incremental value of adding a new unit to the existing fleet, PJM’s Tom Falin said in February.
Many stakeholders, however, felt the proposed method did not account for the improved performance of wind and solar seen in the last decade. (See AWEA Balks at PJM Plan on Wind, Solar Capacity.)
Rocha Garrido said Wednesday that staff will come back to the November PC with a plan to move forward. He agreed with stakeholders who saw the outdated methodology as a “prospective problem” rather than a current one and clarified that if the ELCC was adopted, it wouldn’t take effect for four years.
“We support the improved accuracy in calculating the actual capacity provided by all forms of capacity,” Independent Market Monitor Joe Bowring said. “Improved accuracy should be implemented as soon as possible. Waiting four years is not appropriate.”
TEAC: Artificial Island Cost Allocation Update
It’s been eight months since FERC told PJM to use the stability deviation method to allocate costs for the Artificial Island project, but the RTO has yet to get board approval or file the plan with the commission, staff said Thursday.
The stability deviation method determines that a measurement of the change in the voltage angle is higher for substations that are more impacted by a disturbance or stability event, also referred to as the angular deviation. This change would identify the loads that would be most impacted by a stability disturbance and would benefit from transmission projects that address stability-related issues.
PJM has long agreed it needed a different way of divvying costs for stability-related issues, noting those who cause these problems aren’t always the same ones who will benefit from it being repaired — such as in the cases of thermal violations, voltage/reactive issues, storm hardening, end-of-life/aging infrastructure or real-time operation concerns.
Under the existing solution-based distribution factor (DFAX) method, the Artificial Island project, for example, would have assigned 93% of the project cost to Delmarva Power & Light. Under the stability deviation method, the costs would fall 19% to Public Service Electric and Gas, 15% to PECO Energy, 12.5% to PPL, 12.4% to Jersey Central Power & Light, 10.4% to Delmarva Power, 7.2% to Atlantic City Electric and about 5% to Metropolitan Edison.
FERC agreed in February the latter method best suits the Artificial Island project. (See FERC: Stability Deviation Method Best for Artificial Island.) TOs requested rehearing, however, based on two Tariff changes the commission ordered in approving the new methodology: requiring PJM to perform stability simulations without the stability upgrade when technically meaningful angle deviations can’t be observed, and giving the RTO discretion to modify the 25% threshold for excluding deviations.
PJM said TOs plan to submit Tariff amendments to the commission that would remove the second revision entirely and require the RTO to “perform simulations with the stability upgrade and extend the fault duration to the critical clearing time in order to achieve technically meaningful angle deviations.”
Staff said they will bring the revised cost allocation to the board in December. After receiving approval, PJM will file the revisions with FERC and give designated customers 30 days to review. In January, PJM will assign cost responsibility for the project using the revised methodology.
ComEd, Dominion, AEP Supplementals
Commonwealth Edison’s Quad Cities-Cordova 345-kV line has obsolete relays and is becoming difficult to service, Exelon said Thursday. The line is an intertie between PJM and MISO and needs upgrades to address equipment condition, performance and risk.
In a second project, ComEd said it wants to rebuild 16 miles of the 345-kV Kendall-Lockport double-circuit towers beginning in 2022 to increase the line rating and eliminate 10.5 miles of wood poles that are 60 years old.
American Electric Power has identified a $3.16 million solution for a failed breaker at its Sullivan 765/345-kV substation in western Indiana: replace the failed unit.
The company also proposes upgrading the Dumont 765-kV substation in northern Indiana with a new 2,250-MVA transformer and two new 345-kV breakers. The substation suffered a catastrophic failure in 2018. The upgrade will cost $27.8 million.
Dominion also said it will cost $250,000 to install a 1,200-ampere, 50-kAIC circuit switcher to feed a new transformer at the Enterprise Substation in Loudoun County, Va. A similar project at the nearby Poland Road substation will cost $2 million. Finally, the company proposes spending $2 million to cut an existing 230-kV line between its Cannon Brand and Winters Branch substations to support the proposed Brickyard substation in Prince William County, Va. At Brickyard, Dominion will install four 230-kV breakers and terminate the two lines. Two 230-kV circuit switchers and any necessary high-side switches and bus work for the two initial transformers is also included in the solution.
LITTLE ROCK, Ark. — SPP Chairman Larry Altenbaumer last week took the wraps off an eight-month value and affordability study conducted behind closed doors.
Altenbaumer, who created and chaired the Value and Affordability Task Force, presented a high-level overview of the group’s final report to both the Markets and Operations Policy and Strategic Planning committees.
“I thought we might find some silver bullets … $10 million, $20 million in savings,” Altenbaumer said. “Nothing that came out was that discrete, but we found certain attributes already with SPP that we can enhance.”
Instead of spotting areas of big savings, the report more modestly “supports continued efforts for broad-based process improvement” and “identifies meaningful opportunities to enhance other aspects of performance.” Those opportunities include refining analytics, tailoring information for individual members and improving stakeholder engagement, transparency, metrics and communications.
“While you can’t put a dollar value specifically on any of those items, I’m convinced that in three or five years, we’ll be a more effective, efficient organization,” Altenbaumer told the SPC. “While this initiative may have turned out a little different than expected going in, I’m happy where we landed with this thing.” (See “Altenbaumer Continues to Exert his Influence” in SPP Strategic Planning Committee Briefs: Jan. 16, 2019.)
The VATF defined affordability as “the degree to which a member can justify the financial, human-resource and time-related costs of SPP’s services, relative to viable alternatives.” It defined value as “the tangible and intangible benefits of SPP’s services weighed against associated costs and transmission investments.”
The report’s recommendations are broken out into three main categories, including those affecting the value of SPP and its transmission, the functioning of stakeholder groups and services and internal processes. They include improving the budgeting process by involving “appropriate” stakeholder input, including more transparency into the total costs and working with stakeholders to improve the usefulness and credibility of a value-of-transmission study in 2021.
“There is, candidly, a credibility issue when SPP issues a report on something,” Altenbaumer said. “Many of these initiatives speak to things we can do to make our processes more transparent. Stakeholder engagement and collaboration was another attribute that was emphasized.”
Members recalled recent transmission-value studies trumpeting SPP’s 14-to-1 return on every dollar members contribute and the benefits from $3.4 billion of investment during 2012-2014. (See SPP Begins Promotional Campaign to Tout Transmission Value.)
Some members have seen those reports used in regulatory proceedings.
“Reports can be misconstrued,” said Southwestern Public Service’s Bill Grant, who interacts frequently with regulators. “It needs to be worded such that the money spent on the project is providing value, but it’s value over time. Not that we’re saving X amount of money. It needs to be specific that, yes, we built this transmission, it adds this much value and will continue to add value over the next 40 years.”
“One of the things we need to do is better tailor that message from the eyes of our stakeholders,” Altenbaumer responded. “We don’t want what we put out there, even though it may be technically true, to be the basis for misinformation or misunderstanding.”
“This will help everyone on both sides of the equation,” said Oklahoma Gas & Electric’s Greg McAuley. “The input we’ll have in producing the scope of that [transmission] report and how it gets communicated afterward … going forward, we have an opportunity to make that work.”
One of the VATF’s three sub-teams spent considerable time looking at SPP’s cost areas, which included staffing and benefits, IT costs, meeting costs and transmission-study impacts and costs. The team found IT and human resources represent about 70% of SPP’s operating costs, Altenbaumer said.
“We can better engage members with respect to the priorities of the activities and projects being undertaken by SPP,” he said.
The SPC accepted the report, which will next be presented to the Regional State Committee and then the Board of Directors for final approval on Oct. 29. The SPC will oversee the recommendations’ implementation.
LEXINGTON, Ky. — FERC and the University of Kentucky’s EnVision Forum opened Monday with coal magnate Robert Murray lambasting the “feckless FERC” for refusing to rescue the coal industry and warning that “we’re going to have a lot of people die” if there is a repeat of the 2014 polar vortex because coal plants have been forced to retire.
FERC Chairman Neil Chatterjee, who listened impassively to Murray’s emotional 20-minute speech, insisted afterward he couldn’t have been happier with his comments.
“Thank you, Bob, for your passion and your candor,” Chatterjee, who organized the conference in his native state, said before introducing the next speaker. At too many conferences, Chatterjee said, panelists “don’t truly speak their mind.”
“What I want is what Bob just did — pull no punches. I’m sure others have different points of view. Don’t be afraid to be critical.”
He needn’t have worried. The morning panels featured vigorous discussions on eminent domain and pipeline siting; the viability of a national energy policy — and Murray’s insistence on the need for coal.
Murray, CEO of Murray Energy, noted that FERC opened a docket 20 months ago to address grid resilience after the commission rejected Energy Secretary Rick Perry’s request for an order requiring cost-of-service payments to coal and nuclear generators. “FERC should have already directed the regional transmission and independent system operators to conduct analyses designed to determine whether their grids are resilient against events having high impacts but low frequencies,” he said. “The commission could provide guidance regarding the scenarios and assumptions for this analysis, but it hasn’t.”
Murray said the electric industry’s faith in natural gas is misguided. “These wells only last 10 years, and they’re five years old now. So, we have a five-year national energy policy.”
He also hinted at a possible bankruptcy announcement, saying that despite having the lowest costs in the coal industry, “you’ll be reading about us in the days ahead. We’ve already announced that we have a forbearance agreement with our lenders. Lowest cost [and] didn’t make it.” The Wall Street Journal reported earlier this month that the company entered into the forbearance agreements to buy more time to avoid a bankruptcy filing “after skipping an interest payment on $1.7 billion in debt.”
In a later panel discussion, Michael Polsky, CEO of independent power producer Invenergy, said his company started building coal- and gas-fired generation and now does gas and “a lot of renewables.”
“Mr. Murray can say whatever he says. … Coal is just not the future. You’ve got to admit the reality at some point. … Chatterjee wanted reality. Coal is not the reality.”
Still, there was a heavy emphasis about the importance of coal to the state and to the U.S., and the need to value coal plants’ supposed benefits to the reliability to the grid. Many speakers cautioned that the increasing penetration of renewables was unaffordable to the state’s ratepayers.
“Low-cost energy is the key” to eliminating poverty, “whether it be in this country or in other countries,” Joe Craft, CEO of coal production company Alliance Resource Partners, said during a luncheon speech. “We should not convert our low-cost, reliable system that has been proven to be an economic engine that has made our economy the envy of the world … to a high-cost energy strategy, one that may not be reliable as well.”
“Shutting down coal plants and shutting down coal mines is inconsistent with sound business principles because it’s imprudent,” said Frederick Palmer, a former lobbyist for Peabody Energy and a senior fellow with the Heartland Institute. “And how do I know it’s imprudent? Because we just had a million people in the state of California that didn’t have electricity for a week or two weeks.” (Palmer was referring to Pacific Gas and Electric’s public safety power shutoff, done to prevent the utility’s equipment from sparking wildfires during a period of windy, dry conditions in the state. It had nothing to do with California’s generation sources.)
The conference, which included 12 panels, attracted a who’s who of electricity policymakers, including numerous state regulators and trade groups, former FERC Commissioners Colette Honorable, Phil Moeller, Joseph T. Kelliher, Vicky Bailey, Tony Clark, Robert Powelson, Jon Wellinghoff and Suedeen Kelly; NERC CEO Jim Robb; interim PJM CEO Susan Riley; ISO-NE CEO Gordon van Welie; MISO CEO John Bear; and Carl Monroe, chief operating officer of SPP.
[Editor’s Note: RTO Insider will have additional coverage of the conference later this week.]
Showcase for University
The forum, which was held in conference rooms in the University of Kentucky’s football stadium, also provided a showcase for the university, where Chatterjee’s parents worked as professors and cancer researchers.
“This is what we’re all about: convening experts, disseminating knowledge and seeking solutions. It reflects our innate desire to expand what is possible,” university President Eli Capilouto said in opening remarks.
The forum was sponsored by FERC and the university’s Center for Applied Energy Research, which Capilouto said “develops technologies to improve energy efficiency, protect the environment and create new economic opportunities that [improve] the lives of Kentuckians.”
“We’re not just thinking about solutions,” said Capilouto. “We’re making them.”
The conference also featured several panels that were unusual for an industry event and covered topics not in FERC’s jurisdiction. Among them was a panel on transitioning coal and nuclear plant workers and miners displaced by the shifting generation mix into different lines of work. Another was dedicated solely to the electricity industry in Kentucky, featuring several utility executives and Public Service Commissioner Talina Mathews. Others discussed the energy industry’s intersections with telecommunications, water and the opioid epidemic.
“People have been able to come here and establish connections, get to know each other, and I think that’s really, really important,” Chatterjee told reporters. “I’m hopeful that speakers will make connections and will continue this dialogue beyond here.”
Closing out the EnVision Forum, Chatterjee said attendees told him that “they had never been to a conference like this before, with this diversity of participants all under one roof, all engaging in meaningful dialogue and conversation. I hope that relationships were formed; I hope that conversations were started that will continue into the future.”
Chatterjee also said he wanted “people to appreciate how gorgeous Kentucky is. It is not an industrial hellscape.” Many of his fellow native Kentuckians who spoke on panels echoed that sentiment.
“For the folks in the room who aren’t from Kentucky, sometimes Kentucky gets a bad reputation because people outside the state just hear ‘coal’ … ‘dirty old company, dirty old state. It has nothing but coal in it.’ And that’s just not who we are,” Big Rivers Electric CEO Robert Berry said.
A federal judge approved FirstEnergy Solutions’ reorganization plan last week after the company reached a settlement with workers at its Perry and Beaver Valley nuclear plants to preserve union contracts post-bankruptcy.
According to documents filed in the U.S Bankruptcy Court in Akron, Ohio, FES will keep pensions for existing employees as detailed in collective bargaining agreements with the Utility Workers Union of America and the International Brotherhood of Electrical Workers. The deal calls off the utility’s original plan to renegotiate the unions’ contracts and transfer employees into a 401(k) retirement fund after claiming the company could no longer afford pensions. (See FES Seeks Bankruptcy, DOE Emergency Order and Labor Dispute Stalls FES Reorganization.)
“This is a remarkable victory for workers and unions,” Joyce Goldstein, attorney for both unions, told RTO Insider in an email on Monday. “The agreement reached between the debtors and the unions means that the workers do not lose a penny on their pensions, their wages or any other benefits.”
The news comes six weeks after Judge Alan M. Koschik told lawyers for FES he could not approve its reorganization plan — which included shedding $3.6 billion in debt, cutting ties with former parent company FirstEnergy Corp. and possibly changing its name — until the issue was resolved.
FirstEnergy Solutions won court approval for its restructuring plan last week.
“This is a landmark day in the history of our company,” FES CEO John W. Judge said in a statement Tuesday. “We are now in a position to successfully conclude the Chapter 11 process and will emerge from the restructuring as a fully independent energy company well-positioned to continue serving the needs of our 800,000 customers.”
Judge said more than 93% of creditors approved the restructuring plan, keeping the company on track to exit bankruptcy proceedings before year’s end.
FES also agreed to pay $400,000 in attorneys’ fees for the unions. FES attorney Lisa Beckerman told the court last week without Goldstein’s advice “it would have been very difficult to resolve the complex legal and contractual issues regarding the modifications to the collective bargaining agreements.”
“You know, we feel that it took a long time, but we’re happy that we were able to ultimately reach a deal with our workforce,” she said.
Goldstein described the resolution as a “national success story” in line with strikes organized by teachers and Marriott employees within the last year. In the latter case, 8,000 service workers from Marriot hotels in eight cities walked off the job until the company ratified a new contract in December including pay raises and enhanced security measures to prevent sexual harassment and assault.
“So many workers and retirees — in the airline industry, the auto industry, the steel industry, to name just a few — have lost their pensions through bankruptcy over the last couple of decades,” Goldstein said. “Here, we preserved everything.”
Advocates contesting Ohio nuclear plant subsidies missed the deadline on Monday for gathering enough signatures to get their referendum to overturn House Bill 6 on the 2020 statewide ballot.
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts, released a statement blaming the organization’s shortfall on illegal tactics implemented by well-funded opposition groups and a 38-day delay in getting the petition approved for circulation.
“Nuclear bailout supporters of House Bill 6 have stooped to unprecedented and deceitful depths to stop Ohioans from exercising their Constitutional rights to put a bailout question on the ballot for voters to decide,” Pierce said. “We may never know how much money the corporate backers spent in their campaign of deceit, but we estimate their television, digital and radio advertising, direct mail and their blocking and fake petition to cost over $50 million.”
The Davis-Besse nuclear plant in northern Ohio | NRC
Pierce’s group led the campaign against HB 6 and began organizing petition efforts the same day Gov. Mike DeWine signed the legislation in July. It took 38 days, however, for the group to get approval from State Attorney General Dave Yost before they could start collecting the necessary 265,774 signatures — costing them more than a third of the 90-day deadline afforded to ballot petitions.
Pierce remains optimistic that the U.S. District Court for Southern Ohio will grant its request for an additional 38 days to gather signatures to make up for this “blackout period.” An evidentiary hearing is scheduled for Tuesday at which Judge Edmund Sargas Jr. could issue a bench ruling in the group’s favor. Sargas waived the preregistration requirement for petition circulators last week after the group successfully argued the state law violated free speech rights. (See Court WaivesOhio Preregistration Law.)
“We are fully prepared to continue circulating petitions if the court rules in our favor and grants us a full 90 days to collect signatures,” Pierce said.
FirstEnergy Solutions spokesperson Angela Pruitt told RTO Insider on Monday the company will resubmit deactivation notices for its Perry and Davis-Besse nuclear plants should Ohioans Against Corporate Bailouts succeed in their efforts.
FES rescinded deactivation notices for both facilities in July after the state approved HB 6 — which would funnel $150 million in ratepayer fees to the plants beginning in 2020 — but Pruitt says the ballot petition to overturn the law could reverse that decision, placing 4,300 jobs at risk. (See Ohio Approves Nuke Subsidy.)
“Unfortunately, any additional negative news from the courts or the successful submission of petitions to put a referendum on the ballot will destabilize the financial situation of those plants,” she said. “This will force the company to move back on a path to deactivation if alternative measures to provide needed financial support do not arise quickly.”
VALLEY FORGE, Pa. — PJM’s Operating Committee put manual revisions for its gas contingency rules on the fast track to endorsement on Tuesday after approving the changes on the first read.
Chris Pilong, PJM director of dispatch, told members old gas contingency procedures will be deleted from Manual 3 Section 5 and changes in Manual 13 Section 3.9 will remove references to PJM-directed precontingency fuel switching. Instead, the RTO will “discuss” any threats to fuel supply with the generator and request notification should that generator voluntarily decide to take any precontingency action to mitigate those risks.
The subtle language change signals a victory for generators who repeatedly expressed concern about PJM’s authority to direct pipeline switches — particularly after its revised gas contingency filing significantly redefined how resources can seek cost recovery after-the-fact. (See PJM Stakeholders: Gas Contingency Filing ‘Too Vague.’)
PJM will seek endorsement from the Markets and Reliability Committee on Oct. 31, with a scheduled effective date of Nov. 1.
PJM’s second analysis of resources that provide primary frequency response (PFR) looked a lot like its first — low participation across the board. (See “First Primary Frequency Response Evaluation Reveals Low Participation” in PJM OC Briefs: June 11, 2019.)
PFR is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.
PJM said 583 units with capacities of 50 MW or greater were evaluated for PFR across 10 events between March and September. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-mHz deadband, frequency stays outside the +/- 40-mHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 mHz.
No more than 28 units provided PFR during any of the selected events. In some cases, no units responded. PJM said most critical load and black start units evaluated did not provide PFR because many were offline, operating at maximum capacity or had inconclusive results.
PJM will continue outreach to generators to better understand the low participation rates. A final analysis will be presented to the OC in January.
Winter Weekly Reserve Target
PJM’s weekly winter reserve targets for 2019 remain unchanged from last year.
The targets — part of the reserve requirement study — help the Operations Department coordinate planned generator maintenance scheduling during the winter and cover against uncertainties associated with load and forced outages.
PJM also sets a 0% goal for its loss of load expectation (LOLE) in the winter, preferring instead to expect higher LOLEs throughout the summer. The 2019 targets for December, January and February are 22%, 28% and 24%, respectively.
The OC will endorse the targets at its November meeting.
PJM’s day-ahead scheduling reserve requirement decreased slightly from 5.29% to 5.12%.
The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations.
PJM will seek endorsement for the change at the November MRC and implement the new requirement in Manual 13 revisions.
PJM/NYISO Operational Base Flow Set to Zero
PJM and NYISO agreed to set an operational base flow (OBF) that once provided flexibility between the systems down to zero by month’s end.
The OBF, established in May 2017, carried a 400-MW limit and managed power flows over the Waldwick and ABC phase angle regulators (PARs) to account for natural system flows over the JK and ABC interfaces. PARs are power system transformers that have tap changing capability and can change the phase angle across the transformer and thereby increase or decrease power flow.
Outages on the Hudson-Farragut and Marion-Farragut lines resulted in a decreased limit of just 100 MW as of January 2018. PJM said on Tuesday both systems agreed to set the limit to zero at 11:59 p.m. on Oct. 31.
AUSTIN, Texas — The 20th anniversary of the landmark law that deregulated ERCOT’s market and paved the way for electric competition provided the theme for this year’s Gulf Coast Power Association fall conference Oct. 15-16.
In keeping with the idea that everything’s bigger in Texas, the GCPA conference filled a supersized ballroom at the Hyatt Regency Austin with 650 attendees, many wearing cowboy boots with their suits and blazers. Some wore Stetsons.
In panels on the history of Senate Bill 7 and ERCOT’s restructuring under the law, utility executives called Texas’ wide-open energy landscape the “greatest market in the world,” where some 200 retail electric providers (REPs) compete for customers.
“That’s the ERCOT miracle,” Mauricio Gutierrez, CEO of NRG Energy, said on a panel of chief executives from ERCOT’s three largest power producers. The panel included Thad Hill of Calpine and Curt Morgan of Vistra Energy.
Texas remains an independent republic when it comes to energy, panelists said.
The ERCOT market is the most deregulated in the U.S., they noted. Its transmission grid is largely separate from the rest of the nation’s high-voltage lines and therefore not regulated by FERC, they repeatedly pointed out. And ERCOT is a unique energy-only market, more like Australia than its U.S. counterparts, speakers said proudly.
In ERCOT, consumers pay only for the generation they need. They don’t pay to place additional generation on standby to ensure longer-term reliability, as do the organized capacity markets that serve much of the U.S. That can cause reliability challenges, especially during Texas summers, panelists acknowledged. (See Magness, Walker to Explain ERCOT Reliability to NERC.)
Nevertheless, supporters contended the ERCOT market provides the greatest benefits of any organized market in the nation — or perhaps even the world — for consumers and utilities alike.
“To me, this is the market that should be an example, not just to this country, but to many other countries,” Gutierrez said.
A panel of big-money investors, however, expressed skepticism about risking their funds in the Lone Star State, where volatile prices, often based on weather and resource adequacy, create an unpredictable environment.
Denise Persau Tait, president of Starwood Infrastructure Finance, based in Stamford, Conn., said her firm has a $2 billion to $2.5 billion “book” of energy investments in the U.S., but with less than 7% of it in Texas. The intense competition and low margins in ERCOT mean Texas is not a good bet, she said.
Only peak prices, fueled by heavy air conditioning use during Texas’ notoriously hot and humid summers, can guarantee an ample return on investment, but even those profits can be wiped out by milder weather, Persau Tait and other investors on the panel said.
For instance, June and July were not as hot as expected, keeping electricity prices down, while part of August was so hot it drove prices to ERCOT’s maximum of $9,000/MWh and triggered fears of rolling blackouts. (See ERCOT Survives Another Day in the Roaster.)
Starwood has no investments in Texas’ thermal generation, partly because of such unpredictability, Tait said.
“The issue that we’ve had anytime we’ve looked at deals in thermal generation in ERCOT has been volatility in the revenue streams and not being able to underwrite those deals,” she said. The fast-growing solar market in Texas is better, but “we don’t like to invest in deals where you’re relying on the weather.”
A panel on SB 7, passed in 1999, kicked off the conference with a look-back at efforts to deregulate ERCOT.
Those efforts began in 1995 with a bill to promote competition in the wholesale market, but things really got moving when SB 7 unbundled ERCOT’s vertically integrated utilities into generators, retail providers and operators of transmission and distribution systems. Municipal utilities and electric cooperatives were exempted from the bill but allowed to opt in to the market.
Steve Wolens, a longtime member of the Texas House of Representatives and the bill’s drafter and main proponent, shepherded its journey through the Legislature’s lower house. Policymakers at the time knew of deregulation failures in banking, airlines and telecommunications and didn’t want to repeat mistakes, so they went out of their way to get it right, he said.
“What we decided is that to deregulate, we had to worry about predatory pricing,” Wolens said. “How would we deregulate and not undergo predatory pricing so that the little guys could be run out of business?”
Texas lawmakers traveled to other deregulated states, including California and Pennsylvania, both of which began deregulating in 1996, to educate themselves.
“They went to California to find out how not to do a lot of things,” said John Fainter, former president of the Association of Electric Companies of Texas, which represented regulated utilities at the time. “They went to Pennsylvania and had some things that they learned how to do. ‘Price to beat’ [a major component of SB 7] was one of them.”
“Price to beat” helped small utilities gain a foothold in Texas’ freewheeling electricity market. It created a price floor below which established utilities couldn’t go to get rid of upstart competitors. New retailers, however, could set their prices lower than the price to beat.
Wolens said it may have seemed counterintuitive, but it worked.
“It’s not logical to say, ‘We’re going to deregulate, but we’re going to keep the price high,’ and nonetheless that is what we did,” he said.
When SB 7 took effect in 2002, “price to beat” led to a rapid increase of REPs, creating robust competition and lowering prices for consumers, he said.
A study published in January by researchers at Rice University concluded competitive markets in Texas had retail prices that corresponded more closely with wholesale costs and were generally lower than in markets where the state’s municipal utilities and electric cooperatives continued to operate non-competitive markets.
‘Everybody Signed It’
Wolens said the legislative process around SB 7 was successful because it included a broad range of stakeholders, with 27 people at the negotiating table representing investor-owned utilities, environmental groups, consumer advocates and others.
Each had something they wanted and something they feared losing, he said. The bill provided opportunities to profit from deregulation, but also included increases in renewable portfolio standards and financial support for low-income customers.
“None of these things would have passed as separate bills,” Wolens said. “It took putting together this 200-page bill like a Rubik’s cube so that everything fit together,” Wolens told the GCPA audience. “There was something in there for everybody to like and something in there for everybody to dislike.”
Wolens said he made it clear the bill wouldn’t pass if those who’d agreed to the deal later tried to alter it with legislative amendments. They all had to sign a piece of paper accepting the entire package.
“Everybody signed it — most of us in blood,” Fainter said. “Some of us were accused of not having any blood.”
The bill passed in the House, 145-4, and by an equally large margin in the Senate. It’s remained on the books with few changes for 20 years, standing the test of time, Fainter said.
Troy Fraser, a Texas senator at the time of the bill’s passage, said SB 7 worked because “It wasn’t [written] in the old proverbial smoke-filled room, in the back with no one else [present]. We had all the participants. Everyone knew what was going on. Everyone signed off.”
The bill provided for ERCOT’s board to include 25 members representing the diverse constituencies that negotiated SB 7. Some worried a governing board so large would be unwieldly, but it worked perfectly at the time, Wolens said. Later, the size of ERCOT’s board was cut to 14, where it stands today, he noted.
As the panel wrapped up, Fraser, who described himself as a conservative Republican, told Wolens, a Democrat: “That diversification you put on the board gave us the feeling that the fox was not guarding the henhouse. We had a very diversified board making sure everyone was treated fairly.”
ERCOT’s Job Performance
ERCOT’s role managing its deregulated market got a once-over during a panel moderated by Brad Jones, former CEO of NYISO and chief operating officer of ERCOT. Jones, who said he’s retired, now serves as an advisory member of the GCPA board.
With some knowing encouragement from Jones, panelists jumped on the “Texas-is-best” bandwagon.
Eric Schubert, director of U.S. regulatory affairs for BP Energy, said SB 7 meant FERC doesn’t regulate ERCOT, and that’s proven beneficial.
“FERC’s great,” Schubert said, eliciting chuckles from the audience. “But the fact is that, again, Texans had the ability to negotiate with Texans. They didn’t have to worry about other states. They didn’t have to worry about federal jurisdiction. That simplified matters quite a bit in terms of the development of the ERCOT market.”
It also made it easier to build the $7 billion Competitive Renewable Energy Zones (CREZ) transmission project, he said, bringing wind power from the Texas panhandle and West Texas to the population centers of Dallas, Austin and other cities. CREZ resulted in the construction of 2,400 miles of high-voltage lines, capable of carrying 18.5 GW of West Texas wind to ERCOT’s major load centers. (See Overheard at Infocast’s Texas Renewable Energy Summit.)
ERCOT’s energy-only market has been better at integrating new technologies and renewables than systems with more layers of regulation, Schubert said.
Clifton Karnei, general manager of the Brazos Electric Cooperative and a longtime ERCOT board member, said Texas has a robust grid because of SB 7. The “postage stamp” transmission rates in Texas means everyone pays the same price for transmission access, he noted.
Kenny Mercado, chief integration officer at CenterPoint Energy and an ERCOT board member, said Texas is delivering cleaner, more reliable electricity than ever before.
“We have got it right in almost every aspect today,” Mercado said. “ERCOT has been the critical link to our success over the journey. I’ve learned from the inside out how important the role of ERCOT is. They see everything in real time. They see the electron in real time. They see the dollar in real time. They understand the current state of our market. And they understand the future needs and the future responsibilities.”
Scott Hudson, senior vice president of Vistra Energy and president of its retail business added, “This is the best market to work in in the world.”
Reliability Challenges Ahead
After all the accolades were over, Jones asked about the downsides of SB 7.
Karnei said the long-term sustainability of ERCOT’S energy-only market remains in question. “I think the jury is still out on that,” he said.
Karnei said he calls ERCOT a “casino market.” Some years are great for energy providers; others aren’t. It’s like pulling on the handle of a slot machine. You win some, you lose some, he said.
The future of thermal generation, in which coal and natural gas plants convert heat to energy, is especially problematic, he said. Older plants are being retired and new ones aren’t getting built, panelists said. (See NERC: ERCOT, CAISOFace Summer Reliability Concerns.)
Bill Berg, vice president of wholesale market development at Exelon Corp., said consumers benefit from lower prices in ERCOT, but investment is needed that will increase costs. Otherwise, summer reliability will be at risk.
“It should be an exciting time for the next couple of summers,” he said.
SAN FRANCISCO – Even promoters of renewable energy are starting to worry about reliability as fossil-fuel plants retire and dispatchable renewable resources are slow to take their place.
At the American Council on Renewable Energy’s Renewable Grid Forum on Thursday, speakers talked about the need to replace gas peaker plants with batteries or other resources that can ramp up quickly on demand. Some floated the idea of installing battery storage at natural gas plants to have an instant-on solution to meet peak load. It would be less polluting, at least until the batteries ran out and the gas kicked in, they said.
About 75 people attended the event at a Hilton hotel adjacent to San Francisco’s Chinatown and just down the street from the Transamerica Pyramid.
Big utilities have joined the push for renewables, and some utility executives spoke at the meeting.
During one panel on the role of utilities in the transition to renewable energy, Frank Prager, with Xcel Energy, said the company committed in December to carbon-free energy — the first large utility to do so — but is still trying to figure out how to get there by its stated goal of 2050.
Xcel is likely to obtain an 80% reduction in carbon emissions by 2030, but then costs go through the roof, Prager said. The last 20% will be the hardest to achieve, he said.
Because wind and solar production tends to be seasonal, “you’d have to store terawatt-hours of energy for months at a time,” and that would cost trillions of dollars, he said.
Older technology such as pumped hydro could help. So could advanced nuclear generation, he said. Some developers are working on nuclear units that are much smaller than traditional plants. (See West Wrestles with Resource Adequacy, Grid Reliability.)
Excess energy might be used to create hydrogen that could then be pumped through natural gas pipelines. Fossil fuel with carbon capture and sequestration is another possibility, albeit an expensive one, he said.
Or “Mr. Fusion could come to the fore,” he said, a joking reference to the movie “Back to the Future Part II.”
Federally funded research into new technologies is needed for the nation to totally eliminate carbon emissions from electricity production, Prager and others said.
In the meantime, more utilities are joining the states and cities that have vowed to go all-green. Duke Energy, one of the nation’s largest power producers, pledged in September to go carbon-free by 2050. And PacifiCorp, another energy giant, said last week it planned by 2030 to cut its carbon emissions by 60% below 2005 levels.
“At PacifiCorp, we share a bold vision with our customers for a future where energy is delivered affordably, reliably and without greenhouse gas emissions,” the company said in a statement posted on its website.
Atlanta-based Southern Co. said in April it planned to go low-to-no carbon by 2050. NextEra Energy, which owns Florida Power and Light, said in June it would reduce carbon emissions by 40% from 2005 levels by 2025. And DTE Energy, a Detroit-based company, said in September it would seek to achieve net-zero-carbon emissions by 2050.
Julia Hamm, CEO of the Smart Electric Power Alliance (SEPA), a group that advocates for carbon-free energy by 2050, said much of the movement toward cleaner energy sources is being driven by cost; renewables, including wind and solar, are among the cheapest forms of energy available now.
But Xcel still deserves credit for its “big, bold commitment,” which prompted other energy companies to jump on the carbon-free bandwagon, she said.
“Since Xcel’s announcement last year,” Hamm said, “the announcements from utilities are coming fast and furious.”
It remains to be seen, however, whether they can meet those commitments.
FERC rejected for a third time a bid by developers to obtain transmission status and cost-based rates for a proposed $2 billion pumped storage project in CAISO (EL19-81.)
The commission dismissed Nevada Hydro’s complaint that CAISO failed to follow its Tariff in studying the Lake Elsinore Advanced Pumped Storage Project (LEAPS) in its transmission planning process.
LEAPS, which has been in development since the late 1990s, would be located about midway between Los Angeles and San Diego in Riverside County, with Lake Elsinore serving as the lower reservoir. Developers say it would produce 6,000 MWh daily, based on 12 hours of operation at the full plant capacity of 500 MW, serving the transmission systems of San Diego Gas & Electric and Southern California Edison.
In a 2008 order, FERC rejected LEAPS’ request to be treated as a transmission asset, saying it would not be appropriate to require that CAISO assume operational control of the project as requested (ER06-278).
Last year, the commission rejected the company’s request for a declaratory order finding that LEAPS is a transmission facility eligible for recovery of its costs through CAISO’s transmission access charge (TAC). The commission sided with CAISO and the California Public Utilities Commission, which had argued that Nevada Hydro’s petition was an end run around the ISO’s transmission planning process (EL18-131). (See FERC Tells LEAPS to Get in Line.)
As a result, Nevada Hydro submitted the project for CAISO’s 2018/19 transmission planning cycle. CAISO’s study of LEAPS was included in its final transmission plan on March 29, 2019, which concluded there was no need for any new transmission projects in Southern California, including LEAPS.
Illustration of proposed Lake Elsinore Advanced Pumped Storage Project | Nevada Hydro
Eight Overloads
Nevada Hydro submitted LEAPS as a transmission solution to eight thermal overloads that CAISO identified on the SDG&E system over CAISO’s 10-year planning horizon. But CAISO did not study it for those violations because the ISO had already decided on other solutions, including remedial action schemes and battery storage and demand response selected by the CPUC in its integrated resource planning (IRP) process.
Nevada Hydro complained that CAISO did not attribute any cost to the batteries, demand response or remedial action schemes, or compare them to the cost of LEAPS to determine which would be more cost-effective. CAISO said because those solutions were already in operation or under construction, they presented no new additional capital costs to consider.
Nevada Hydro also argued that CAISO failed to follow its Tariff requirements for evaluating LEAPS as an economic study request, underestimating its benefits.
The PUC; Six Cities (Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside); the California Municipal Utilities Association; NextEra Energy; and the California Department of Water Resources’ State Water Project opposed Nevada Hydro’s complaint and backed CAISO’s analysis. Opponents contended that LEAPS is primarily a generation facility whose costs should be recovered through market revenues rather than the TAC.
The company did not respond to a request for comment.
Lake Elsinore | City of Lake Elsinore
No Tx Need
In its ruling, the commission said CAISO’s analysis had followed its Tariff.
“Because CAISO’s studies found no need for new transmission solutions, and because the existing solutions present no new capital costs, we find that CAISO’s Tariff does not require it to compare the cost-effectiveness of LEAPS with that of reliability solutions that are already in operation or under construction, or discuss the pros and cons of relying on existing measures that adequately ensure reliability versus investing in new transmission assets,” FERC said.
“… We continue to find that CAISO’s transmission planning process is designed in a manner that considers the full benefits of any proposed transmission solution, and that CAISO applied its process correctly with respect to its study of LEAPS,” the commission added.
The commissioners also rejected Nevada Hydro’s complaint over CAISO’s use of 4,183 MW of generation and a 2,000 MW export limit identified in the CPUC “default scenario” portfolio, saying the company should have objected during the transmission planning process. “Once the planning assumptions and study plan are adopted, those assumptions are locked in for the rest of the transmission planning cycle,” FERC said.
“We find no merit in Nevada Hydro’s assertion that CAISO abdicated its responsibilities as a regional transmission organization by adopting the CPUC default scenario portfolio. As noted by CAISO, its role is transmission planning, not resource procurement, and nothing in its Tariff requires CAISO to second guess or reverse CPUC’s resource procurement decisions or dictate what resources CPUC-jurisdictional entities can or cannot procure.”
FERC Rejects Rehearing on CAISO Capacity Market
Also last week, FERC denied rehearing on its 2018 order rejecting a request to direct CAISO to develop a capacity market (EL18-177-001).
The request had been made by CXA La Paloma, the operator of a 1,124-MW gas-fired plant in Kern County, Calif. CXA La Paloma contended California’s lack of a centralized capacity procurement was unjust and unreasonable because of falling energy prices that undermined the finances of independent generators. (See FERC Rejects Request for CAISO Capacity Market.)
On rehearing, the commission dismissed contentions that it ignored evidence and misread the law in rejecting La Paloma’s complaint. It also rebuffed requests to conduct a technical conference to examine the state’s existing resource adequacy framework. “The record evidence did not persuade the commission that additional processes, other than those [stakeholder proceedings] noted in the complaint order that were already underway, were necessary.”
