PJM’s transmission owners have floated a proposal that would comply with FERC’s show cause order on their planning processes by adding input opportunities — along with complexity — for tracking project development.
PPL’s Frank “Chip” Richardson explained the process developed by the TOs and PJM during a conference call Tuesday. Instead of mirroring PJM’s existing processes for baseline projects, which are developed to address violations of regional or national reliability criteria, the process for supplemental projects will have a more detailed and structured pathway for stakeholder engagement.
A comparison between TOs’ current and revised processes for planning supplemental projects. | PJM
Supplemental projects are transmission expansions or enhancements developed by TOs to address their individual planning criteria and maintain their assets, so they sidestep PJM’s analysis for inclusion in its Regional Transmission Expansion Plan. The new planning process was outlined in FERC’s order but has received stakeholder focus as TOs developed the implementation details.
Of particular interest to planners has been FERC’s determination that the three steps of project planning — defining assumptions and criteria for analysis, identifying needs, and choosing a solution — each receive its own meeting with time before and after to provide input. Richardson cautioned that parts of the last two might bleed into each other. When talking about a problem, “the natural question is, ‘What are you going to do about it?’” he said. “It’s hard not to talk about the solution when you talk about the need, so you’ll have to have a little bit of forgiveness.”
The proposal also clarifies that TOs can submit revisions to their local plans (which include supplemental projects) to the RTEP throughout the year. TOs said they plan to maintain their existing practice of having an annual review of the models, criteria and assumptions that underpin the projects in December or January of each year. This information supports PJM’s development of base-case planning models that allow stakeholders to model any project to see how it might change flows on the grid.
PJM’s Aaron Berner said staff are still unsure whether they will create separate slide decks to review supplemental versus baseline high-voltage projects. The difference has come under consideration because the D.C. Circuit Court of Appeals ruled earlier this month that high-voltage supplementals should be eligible for regional cost allocation and PJM staff indicated that might mean the projects have to go through the RTEP analysis. (See AMP Offers ‘Best We Can Do’ on PJM Tx Planning.)
Complexities
American Municipal Power’s Ed Tatum, who has championed a proposal to add details and rules to the TOs’ plan, highlighted several concerns with the plan’s structure. For one, he said, it’s tough for stakeholders to be prepared for meetings when the project presentations are posted 10 days prior to the meeting. AMP has members in nine states and over multiple TO zones.
Richardson acknowledged that if the goal is to model all of the potential solutions that TOs consider, “that’s quite ambitious, and it will be challenging.” He suggested stakeholders focus “on those things that would actually have some impact on them directly.”
Tatum asked whether TOs will explain why their preferred solutions are chosen over other options. Richardson said he believed TOs agreed to discuss other options that they “seriously considered,” but that they don’t plan to work on solutions “that they are not intending to pursue but may have considered.”
“I think many people had the same reaction … ‘Wow this is pretty complex,’” Richardson acknowledged.
He said TOs plan to convene stakeholder reviews of the process in the first and third quarter next year.
Oklahoma Corporation Commission Chair Dana Murphy came up short Tuesday in her bid to become the state’s lieutenant governor, losing a runoff for the Republican nomination.
Murphy was bested by former state GOP Chairman Matt Pinnell, who received 58.1% of the vote to her 41.9%. Murphy beat Pinnell in a four-way primary in June, winning 45.8% of the vote to Pinnell’s 35.69%, less than the 50% required to avoid a runoff.
Only 295,132 Oklahomans cast ballots in the runoff, compared to 429,483 in the primary.
Pinnell will face Democrat Anastasia Pittman, a state senator from Oklahoma City, on Nov. 6.
In a concession statement issued Tuesday night, Murphy thanked supporters and called for cooperation at the State Capitol. Murphy campaigned as a problem-solver and made it a point to crisscross the state and visit as many residents as she could.
“It’s time to address the roots of problems and create lasting solutions,” Murphy said in her statement. “Going forward, I hope the next crop of leaders at the State Capitol will bring their best, put partisan politics aside and do something different.”
The lieutenant governor’s office is seen as a stepping stone to the governor’s mansion. Outgoing Gov. Mary Fallin served three terms in the higher office, but current Lt. Gov. Todd Lamb failed to make it out of this year’s Republican gubernatorial primary.
Murphy, 58, a petroleum geologist and lawyer, has sat on the OCC since 2009. Her current terms ends in 2022. She is also a past chair and current member of SPP’s Regional State Committee. (See Oklahoma Regulator Sets Sights on Higher Office.) She was applauded for not running negative ads during the two-month runoff campaign.
The SPP Regional Entity’s Board of Trustees on Thursday officially terminated the RE’s regional delegation agreement, shutting it down effective 5 p.m. CT Friday.
The trustees approved a motion to terminate the agreement during a brief phone call that was delayed until Trustee Steve Whitley could join Chair Dave Christiano and create a quorum. Staff patched Whitley in over a speakerphone from SPP headquarters. Trustee Mark Maher was unable to attend.
The meeting was a formality, as FERC in May approved the RE’s dissolution, effective Aug. 31 (RR18-3), and the transfer of its 122 registered entities to the Midwest Reliability Organization and SERC Reliability Corp. (See FERC Approves Dissolution of SPP RE.) The order ended a reliability oversight role that had been a source of concern at the commission and NERC and revised the delegated agreements among NERC, MRO and SERC to reflect their new geographic footprints.
The RE has been working since then to transfer data and files to its members’ new REs and purging its own files.
“We have absolutely nothing left, other than a bank account,” RE President Ron Ciesiel told the trustees. He said the RE’s books will be closed in about a week, and the remaining funds transferred to NERC, MRO and SERC.
“We’re ready to close the doors,” said Ciesiel, noting he and remaining RE staffers Kevin Perry and Joe Gertsch would be “mustered out” of SPP following the conference call. Ciesiel said the rest of the RE’s original staff have been placed elsewhere within the RTO or “made other decisions.”
MRO CEO Sara Patrick joined with Ciesiel, Christiano and Whitley in complimenting staff and the entities for their work during the transition.
“I know this was an unprecedented development, and certainly not something anyone anticipated,” she said. “I appreciate it’s gone as smoothly as it has.”
“I think our registered entities are in good hands,” Christiano said.
NERC will assume the compliance monitoring and enforcement of the RTO for two years following the delegated agreement’s termination date, after which it will determine a successor.
Christiano closed the call by uttering “sine die” — business adjourned, with no appointed date for resumption.
SPP Files for Cancellation of WAPA Operating Agreement
SPP filed with FERC on Aug. 28 to cancel its joint operating agreement with the Western Area Power Administration (ER18-2326).
The JOA was rendered moot by SPP’s integration of the Integrated System in October 2015, when the WAPA-Upper Great Plains Region transferred functional control of its transmission facilities to the RTO.
The agreement, which dates back to 2012, expired by its own terms on June 21. SPP filed a three-year extension in 2015 that was accepted by FERC.
SACRAMENTO — A bill that would require California to get 100% of its power from renewable and other zero-carbon resources by 2045 is headed to the desk of Gov. Jerry Brown.
Senate Bill 100 — the 100 Percent Clean Energy Act — passed a major hurdle Tuesday, clearing the state Assembly by a narrow margin, then sailed through the Senate Wednesday. Brown hasn’t said if he will sign or veto the measure, but it dovetails with his ambitious environmental agenda with regard to renewable power.
“This bill will continue California’s energy revolution,” said Sen. Ben Hueso (D), who voted for the measure.
Some Republicans argued against the measure, saying it would raise energy bills, while Democrats said wind and solar were now cheaper alternatives to fossil fuels.
In the Assembly Tuesday, the bill needed a majority vote in the 80-member lower house but remained on call, without the votes for passage, much of the day. It passed in the early evening by a vote of 44-32.
Other measures being weighed this week — the last of the legislature’s 2017-18 session — include a bill that would start CAISO on the road to being an RTO for Western states, letting California tap into wind power from Wyoming and solar power from New Mexico, for instance, while those states could buy California’s clean energy during times of low in-state demand. (See CAISO Regionalization Bill Set on Uncertain Course.)
CAISO’s leadership strongly supports Assembly Bill 813, which is currently being held in the Senate Rules Committee as a deal is worked out to bring it to the Senate floor. The legislature has until midnight Friday to send measures to Brown or watch the bills expire.
SB 100’s fate was unknown until the last minute Tuesday. Sen. Kevin de Leon (D), the bill’s author, had to work his Assembly colleagues on the Senate floor to get the last votes needed to pass the measure before the lower house adjourned for the day. There were a number of Democratic holdouts who had to be persuaded. Former Gov. Arnold Schwarzenegger, former Vice President Al Gore and others weighed in to encourage lawmakers to pass the measure.
In addition to requiring investor-owned utilities, publicly owned utilities and community choice aggregators to obtain 100% of their energy from renewables by 2045, the bill sets milestones along the way: 40-44% by 2024; 45-52% by 2027; and 50-60% by 2030.
The Long Island Power Authority’s proposal to exempt “beneficial electrification” from carbon charges received a mixed reaction Monday at a meeting of the Integrating Public Policy Task Force (IPPTF).
Ground source heat pumps are cited as a type of “beneficial electrification” which causes a net reduction in carbon emissions. | EPA
LIPA’s David Clarke said beneficial electrification (BE) — load growth that improves load factors and results in net reductions in carbon emissions — could increase generator margins while reducing fixed costs and should be supported by policymakers. Clarke cited as examples vehicle electrification and switching from oil-fired boilers to ground source heat pumps.
Clarke acknowledged the complexity of carving out BE loads for separate rate treatment but said it could be accomplished without skewing dispatch. He proposed treating BE load growth as having no marginal carbon impact, meaning it would not pay the carbon component of the LBMP.
“I think the question here is: Is there a consensus … around the idea of trying to include beneficial electrification in this proposal?” Clarke asked. “I’m willing to at least try to illustrate that it might benefit large groups of stakeholders.”
Kevin Lang, representing New York City, said Clarke had proposed an “interesting concept.”
But other stakeholders indicated no appetite for including the issue in their current deliberations, saying it should be delayed or handled by retail regulators rather than in the wholesale market.
One stakeholder who asked not to be named said the proposal raised numerous issues. “If you include extensive switching to heat pumps, a utility can very quickly become a winter peaking operation rather than a summer peaking operation. This then raises the question of forward capacity markets and so forth. How much does it cost to have the extra capacity in place for winter weather?”
Because thermal loads tend to be very “peaky,” resulting in more start-up operations, adding such loads raises issues of environmental justice, the stakeholder said.
“Any policy maker who gets into the subject of electrification should be able to stand up in front of a crowd of people like this and draw a curve of carbon monoxide, unburned … carbon emissions during the startup of even a natural gas turbine, and be able to comprehend how ugly that start-up process is during the first hours of operation and where that exhaust is going. We need to be very careful about increasing peaky types of grid loads.”
Mark Younger, of Hudson Energy Economics, said measuring carbon savings from beneficial electrification is very complicated.
“We would be going through a huge amount of complication to try and address something that realistically should lower the average carbon cost … fairly little,” he said. “I look at this and I say this seems like a perfect thing to not try and address at all at the wholesale level. … If someone wants to put together a retail rate design that is targeted to beneficial electrical uses and therefore has some degree of savings on maybe some of the fixed costs, the distribution costs … that’s a perfectly appropriate thing certainly for DPS [Department of Public Service] to consider.”
Clarke recommended awarding the social cost of carbon offsets through load-serving entities, which he said would allow for continued funding of LSE carbon abatement programs and incent LSEs to encourage BE load growth. The state Public Service Commission would retain its jurisdiction over how offset revenues are treated at the retail level.
Erin Hogan, director of the state Utility Intervention Unit, agreed with Younger, saying “it’s premature to try and address this now.”
She said the issue could be revisited once policymakers develop criteria for BE and once the NYISO develops its bottom-up forecast.
“The issue that I take issue with is that all beneficial electrification is good. To the extent there’s low penetration, the fixed costs could be spread over more megawatt hours. However, if the penetration is so high that the utilities then have to revamp their systems, all those little transformers in neighborhoods might have to be resized. Those costs could go up exceptionally high,” she said, noting that her office filed comments in the “New Efficiency New York” docket asking the PSC to develop criteria for defining BE.
Under Clarke’s proposal, loads qualifying as BE would have to improve load factors and prevent increases in regulated natural gas customers’ fixed costs. Policymakers should consider offsetting increases in fixed costs to electric customers resulting from load growth at sub-transmission feeders and distribution lines, he said.
Lang said New York City “is looking closely” at beneficial electrification, predicting it “will be bigger” than Younger suggested.
“If [the impact is] tiny, it’s tiny,” said Clarke. “That’s not the issue. I’m thinking down the road this is going to be big. Beneficial electrification, especially if [carbon emissions] were only monetized in the electric sector, is going to be a huge thing. And we’re going to be penalizing — if we keep doing what we’re doing — load growth that reduced carbon … by charging it a carbon charge even though its net effect on carbon is negative.”
Import Carbon Pricing
Clarke also gave a presentation on addressing imports from grid operators that already incorporate carbon prices. NYISO staff have suggested treating imports as if New York had no carbon policy, saying it may be too complicated to use the actual hourly marginal energy rate [MER] of external RTOs.
Clarke said the ISO’s proposal “gives neither an efficient carbon-free dispatch nor efficient dispatch when damage costs are considered” using the social cost of carbon.
Under Clarke’s proposal, the ISO would back out the price of carbon in each external zone and compare it to the New York price, less its carbon price based on the New York MER. “If MERs are similar, why not get more power from ISOs/RTOs where the cost of power absent carbon charges is lowest?” he asked.
The draft assumes the status quo — known as Option 1 — of treating imports as if New York had no carbon policy.
NYISO’s Mike DeSocio said, “I haven’t heard compelling arguments” for considering ways to value clean resources outside New York, known as Option 2.
Pallas LeeVanSchaick, of the ISO’s Market Monitoring Unit, challenged the “premise that Option 2 is complicated and hard to implement, and Option 1 is straightforward. … I don’t think it’s as straightforward as you think it is.”
Jordan Grimes, of Morgan Stanley, said beginning with Option 1 and later switching to Option 2 would be “untenable for markets.”
He asked whether the ISO had considered how the decision would be viewed under the U.S. Constitution’s Interstate Commerce Clause.
“The courts could say … you guys looked at two options, and Option 2 was the less discriminatory option — and that’s on record — and the ISO decided to go with Option 1 because it was easier.”
He said NYISO could learn from CAISO. “The way they tax imports largely works,” he said.
ISO attorney James Sweeney responded, “We haven’t identified anything from the interstate commerce area that would be a deal breaker for either option.”
Mike Mager, representing the Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said the draft is missing many details that must be decided before NYISO stakeholders vote on any proposal. “It’s problematic to expect people to [vote] to implement one of the most significant market rule changes in the history of the NYISO without any clarity on what the social cost of carbon would be and how and when it would be updated,” he said.
NYISO’s DeSocio said “it’s difficult to foreshadow the kind of process the Public Service Commission would undertake” to set the cost of carbon. “We would hope they would be consistent with other [PSC] programs. From an efficiency standpoint, having different costs of carbon doesn’t seem like a good path forward.”
HOUSTON — The long transition between incoming Mexican President Andrés Manuel López Obrador’s July 1 election and his Dec. 1 inauguration has provided an early glimpse into how the new administration will approach the country’s energy reforms.
Unfortunately, the competing messages have left many observers confused, said political scientist and long-time Mexico watcher Tony Payan.
Members of López Obrador’s administration “don’t seem to have full agreement on what they want to do,” Payan told the International Society for Mexico Energy Monday night.
Payan, fellow and director of the Baker Institute’s Mexico Center at Rice University, said one official will call for NAFTA to stay in place, another will say, “No NAFTA is good NAFTA.” Another official will say the new government will review the 107 energy contracts signed with mostly foreign companies, then somebody else will say, “No, we’re not.”
“Then somebody says, ‘Put the energy reform to a referendum,’ and someone else says, ‘No, we’re not,’” Payan said. “The reality is there’s a lot of chaos. The incoming administration is spending too much time deliberating in public. They should put together the entire team, lock themselves in a room, agree on what they want to do, then come out and provide details to the public on what they want to do.”
Payan said the resulting confusion is “wearing them out” and reducing the Obrador administration’s political capital.
“The public debates is one of the worst things they can do, and they’re doing it,” he said. “Just two months after the election, and there’s already too many things up in the air.”
Most of the early focus has been on Mexico’s floundering petrochemical industry, which produced 1.88 million barrels of oil per day in the first half of 2018, compared to 3.4 million barrels per day in 2005. López Obrador has announced a $16 billion investment plan to increase the country’s oil production and refinery capacity.
Payan said Pemex, Mexico’s state-owned petroleum company, will take precedent over other companies and industries. Many in Mexico hold the ideological belief the country’s petroleum resources belong to the Mexican people. (See Opening of Mexico’s Market at Risk from New President.)
In the meantime, Payan said, the electric industry could very well continue to work on flexing its newly deregulated muscles.
“My guess is the electricity production landscape and markets are changing so quickly, and the technology is moving so fast, that it will be harder to restore any type of centrality to the state,” he said. “I think electricity is a little bit easier because it’s not wrapped in all that nationalism like oil is. Regulatorily, technologically, that market is so different. It’s a completely different ballgame. It’ll be hard to set them back.”
James Fowler, a senior Americas energy analyst for the ICIS Mexico Energy Report, agreed with Payan that the incoming government is sending mixed messages to participants in the electricity sector.
“On the one hand, they are talking about supporting private investments in the country and its infrastructure, whereas, on the other hand, they have talked about strengthening the role of state utility [Comisión Federal de Electricidad],” Fowler said. “Until energy market participants have a clear idea about where the new government’s energy policy is headed, we expect to see a slowdown in both new investment and the entrance of new companies into the Mexican power market.”
The Goodness of Competition
López Obrador’s $16 billion investment package includes plans to build more hydro facilities. However, he has also called for reducing the consumption of imported natural gas for power generation and cancelling a proposed retirement of 12 GW of inefficient and outdated power plants to boost the country’s energy independence, Fowler said.
“In reality, the new government will find it very hard to achieve these goals, while at the same time encouraging private investment in much needed new infrastructure, so something will have to give,” he said.
“When I look at the numbers, I can’t figure out how they’re going to do it,” Payan said, noting the disconnect between reduced taxes and increased infrastructure spending.
Renewable energy could also face some obstacles, Payan said. He pointed out López Obrador, a left-wing populist who emphasized social inequality on his way to a resounding victory, “wants to give a greater voice for farmers and indigenous communities.”
“If the federal government gives them a great voice in these deliberations, energy projects could be further delayed,” Payan said. “My guess is López Obrador will rediscover the goodness of private competition.”
Payan, a political scientist who spent 15 years on the U.S.-Mexico border at the University of Texas at El Paso, took a moment to address the trade agreement between the two countries trumpeted earlier in the day. He called it “much ado about nothing” and forecast a frosty reception in Mexico.
“I don’t think it’s going to go well in Mexico, once the critics begin to parse the agreement,” he said. “I think it actually strengthens the American manufacturing industry … steel, aluminum, cars. It weakens the car industry in Mexico and places it at a greater disadvantage than before.”
In the end, Payan said, López Obrador just wants NAFTA off his plate and may instruct his supporters in Congress to approve whatever the outgoing administration sends them. In the new Congress that began convening Sept. 1, the three parties that nominated him together hold commanding advantages in the Senate (68 of 128 seats) and Chamber of Deputies (307 of 500 seats).
“There’s a lot of uncertainty in the air. It’s not as amicable as you would think,” Payan said. “López Obrador has a lot more to clarify and define. He will have a tough time maintaining political discipline in Mexico. In general, I think we’re in for a rougher ride than we think.”
[Editor’s Note: A previous version of this story incorrectly reported that López Obrador’s MORENA party held 68 Senate and 307 Chamber seats. MORENA joined with the Social Encounter and Labor parties to nominate him and form a coalition government.]
SACRAMENTO — Members of California’s Senate and Assembly hastily passed a conference committee report Tuesday night intended to protect ratepayers and help utilities pay for wildfire damages.
Both utilities and ratepayer advocates were unhappy with the measure, leading the committee’s co-chairman to suggest he and his colleagues had done an OK job.
“It may be a little bit encouraging that utilities and ratepayers both have a problem with this,” said Sen. Bill Dodd, a Napa Valley Democrat.
Wildfires ravaged Santa Rosa, Calif., in October 2017. | Army National Guard, Capt. Will Martin
The final conference committee report on Senate Bill 901 was approved in a confused rush Tuesday night as a deadline approached to get the bill in print 72 hours before the legislature reaches the end of its two-year session at midnight Friday.
Earlier versions of the bill would have removed the strict liability that California imposes on utilities if electrical equipment is a substantial cause of a wildfire.
Under the legal doctrine, Pacific Gas & Electric potentially faces billions of dollars in damages for last year’s devastating wine country fires, which leveled a swath of the city of Santa Rosa. State fire investigators said the utility was at least partly to blame for a number of those blazes because trees or branches hit PG&E power lines.
The conference committee deleted the provision eliminating strict liability and replaced it with a procedure that would allow the utilities to issue revenue bonds to cover wildfire costs. Charges would be added to customers’ bills to pay off the bond debts. (See Bond Sales Eyed to Fund Utility Wildfire Costs.)
That didn’t make utilities happy. A lobbyist for San Diego Gas & Electric told the committee Tuesday it was a step backward from the prior version of the bill.
Ratepayer advocates were outraged.
“We strongly oppose this bailout for PG&E,” said Mark Toney, executive director of The Utility Reform Network. “Billions of dollars at stake should not be decided in such a rushed process.”
Other groups, including cities, counties and plaintiffs’ attorneys, supported the conference committee’s report because it left intact the strict liability standard, sometimes called “inverse condemnation,” which allows those harmed to be compensated without proving negligence.
The conference committee report also contains measures to prevent wildfires, including provisions governing forest management and tree removal. And it allows the California Public Utilities Commission to consider the reasonableness of a utility’s conduct in determining whether to allow it to recover wildfire costs from ratepayers.
The conference committee report will be incorporated into SB 901, which now goes back to the Senate and Assembly. Both houses must approve the bill by Friday if they want it to reach the desk of Gov. Jerry Brown.
Lawmakers have unveiled a new plan to help California’s investor-owned utilities cover the costs of wildfires sparked by transmission lines.
The new plan calls for the California Public Utilities Commission to authorize the IOUs to pay for wildfires by selling revenue bonds and passing on the costs to customers through charges on their utility bills. It would also direct the PUC to look at whether a utility acted unreasonably by disregarding fire risks, or whether outside factors such as extreme weather contributed to fires. The proposal includes provisions for managing vegetation near power lines and easing regulations for tree cutting.
The new plan was outlined Friday by State Sen. Bill Dodd, one of the co-chairmen of a legislative conference committee tasked with mitigating wildfire risks and addressing their costs.
A prior plan proposed by Gov. Jerry Brown would have lessened the legal liability of the companies but was tabled after critics called it a multibillion-dollar bailout. (See California Utilities Lose Bid to Reduce Wildfire Liability.)
Senate Bill 901, the vehicle for the governor’s wildfire proposals, will be amended to include parts of the governor’s original proposal and the new changes, which Brown’s office vetted, Dodd said. “We can all agree that the status quo is unacceptable,” he said.
The committee must decide soon on the final provisions of SB 901. The current two-year legislative sessions ends at midnight Friday, when bills not sent to the governor will expire.
State Assemblyman Chris Holden, the other co-chairman, said lawmakers faced a daunting job in trying to prevent wildfires, protect fire victims and ratepayers, and ensure the stability of the state’s utilities. “The ramifications and the stakes are clearly very high, no matter which way we go or how we go there,” Holden said during Friday’s hearing.
The governor’s initial plan would have done away with California’s unique system of holding utilities strictly liable for all damage caused by power-line sparked fires. Instead, it would have required courts to weigh the reasonableness of the IOUs behavior and factor in other causes that contributed to fires.
The new plan maintains strict liability but provides a clearer route for passing on the damages to ratepayers.
A wall of flame in Southern California. | Tim Walton, Photo One Productions, CAL FIRE
The details of the new plan remain sketchy, including whether it would cover the October 2017 fires in the Napa and Sonoma valleys, which caused death and urban destruction on a scale rarely seen in Northern California. Investigators for the California Department of Forestry and Fire Protection blamed nearly a dozen of the worst blazes on Pacific Gas and Electric power lines and equipment coming into contact with trees and branches. PG&E faces billions of dollars of damages in those cases.
Some critics, including ratepayer advocates, remain concerned that lawmakers are primarily focused on helping utilities, not fire victims or utility customers.
“The ratepayers are the ones that are number one on my list. I want to be sure that they are not the ones that suffer because of mismanagement,” Assemblywoman Eloise Gomez Reyes said.
But Sen. Hannah-Beth Jackson, an outspoken critic of the utilities, thanked her fellow conference committee members Friday for focusing more on residents and less on IOUs in the new outline. “This is a massive undertaking for a massive problem,” she said.
VALLEY FORGE, Pa. — A planned vote on a proposal to expand PJM stakeholder input on end-of-life (EOL) transmission projects was revised to a second “first” reading last week after it was agreed that revisions to the plan since it was initially discussed made it substantially different than originally proposed.
American Municipal Power and Old Dominion Electric Cooperative developed the proposal to give stakeholders “meaningful input” in transmission owners’ planning of baseline and supplemental projects for EOL facilities. It was introduced after members agreed, at AMP’s suggestion, to terminate the Transmission Replacement Processes Senior Task Force at the July Markets and Reliability Committee meeting. (See PJM Stakeholders End Tx Replacement Task Force.)
Since last month, however, proponents abandoned enough of the proposal that they agreed to reintroduce it. The proposal no longer requires alternative dispute resolution (ADR) before a project can go forward or that the stakeholder process occur prior to TOs finalizing their budgets. Also eliminated is the requirement for additional meetings outside the TOs’ approved processes, or detailed-criteria examples and how they would be applied.
The revised proposal presented to the MRC would require TOs to explain their criteria for determining EOL projects, provide details about the asset and its condition, and make them available for PJM to post 30 days before the first applicable meeting of the Regional Transmission Expansion Plan cycle. It would also define the EOL processes and offer three choices for where to include TO-specific procedures in PJM’s governing documents.
“We are concerned about the transparency … as well as the ability once we have that transparency to comment in a timely manner,” AMP’s Ed Tatum said. “We think [TOs] are doing a pretty good job when it comes to assessing your systems.”
In response to a question from LS Power’s Sharon Segner, he acknowledged that the proposal could “not really” halt a project.
“If a TO is bent on getting a project built, I’m not sure how any of this could stop it,” he said. “I think what it does is it gives the opportunity to fully discuss the need for a project.”
TOs “may not wish to respond” to input on a project and “we honor that,” he said.
The opportunity for ADR before projects are finalized was removed, he said, because “it’s very clear to me that PJM did not want that part of our proposal to be memorialized.”
It was proposed as manual changes, he said, because he felt that he wouldn’t be able to get the two-thirds majority approval necessary for including it in the Operating Agreement.
“We think this is the best we can do. That’s all I got,” he said.
“While we would like to get it in the OA, we’re not sure that it’s necessary,” AMP attorney Lisa McAlister said.
Consensus
PJM’s Ken Seiler said the RTO is optimistic that TOs and their opponents may be reaching consensus after a nearly two-year stalemate created by FERC ruling that TOs weren’t properly complying with their obligations under Order 890 to provide stakeholders with adequate information on supplemental projects — transmission expansions or enhancements not required for compliance with reliability, operational performance or economic criteria. PJM and its TOs submitted compliance filings in March, which they are implementing now, and refused to engage AMP and others in additional negotiations on the issues.
“We’re certainly committed to transparency around the entire process, and that’s including supplementals,” Seiler said.
AMP and PJM “have certainly moved much closer to where we think we need to be,” and they’ve also “closed the gap” with the TOs, he said. “We’re not there yet.”
PPL’s Frank “Chip” Richardson asked for patience as TOs implement their plan for complying with FERC’s show cause order earlier this year requiring them to increase stakeholder engagement in the development of supplemental projects. (See “TO Supplementals Discussion,” PJM PC/TEAC Briefs: Aug. 9, 2018.)
TOs plan to initiate stakeholder processes in the first and third quarter next year to review the implementation of the TOs’ new M-3 Tariff attachment, an outline of TOs’ responsibilities that had formerly been in the Operating Agreement. He suggested that the “appropriate place” to continue analyzing the process is in the Planning Committee, although a special session of the MRC was announced for Sept. 13 to discuss transmission replacement processes.
Seiler confirmed that the new processes under M-3 will begin their transition into the RTEP in September, but that it will take some operating experience with it before integration can be improved. He noted that supplemental, aging infrastructure and EOL projects are often incorrectly used interchangeably, which obscures meanings.
“We’ve got to get a little tighter with the words, a little more consistent with the words,” he said.
Exelon’s David Weaver reiterated calls for consensus. “We really got into a stalemate in the TRPSTF, [but] the TOs really do want to provide additional transparency,” he said.
Despite Weaver’s conciliatory words, not all TOs appear ready to support the AMP-ODEC proposal.
Duquesne Light’s Tonja Wicks criticized the proposal as having “a number of flaws” and said it’s “inappropriate to ask stakeholders to vote on specific language rather than concepts when the language isn’t defined.”She took issue with what she saw as the proposal imposing additional requirements and obligations on TOs through the manuals and outside of the OA, the latter of which she noted would require FERC approval to be implemented.
She accused Tatum of “forum shopping” for the proposal, a remark he dismissed as “a pejorative comment.”
“And it was,” she shot back.
Can High-voltage Still be Supplemental?
PJM Vice President of Planning Steve Herling indicated the potential for supplemental projects involving high-voltage lines to go through the RTEP analysis because they will likely become eligible for regional cost-sharing. (See DC Circuit Court Rejects PJM Tx Cost Allocation Rule.)
“It doesn’t tell us what to do, so we have to wait until FERC decides,” he said of the D.C. Circuit Court of Appeals’ decision to remand back to the commission its denial of cost sharing for high-voltage lines in PJM’s territory. “I believe that’s been FERC’s general direction, and we do whatever FERC tells us to do.”
FERC last week approved portions of a Louisiana Public Service Commission complaint against Entergy subsidiaries System Energy Resources Inc. (SERI) and Entergy Services, denied and dismissed other portions, and set the remainder for settlement proceedings (EL18-142).
The PSC filed the Section 206 complaint in April, contending that the return on equity in the unit power sales agreement (UPSA) formula rate for calculating the costs of the Grand Gulf Nuclear Station billed to Entergy’s operating companies is unjust and unreasonable. The state regulator contested SERI’s capital structure and the depreciation rates currently incorporated into its rates, and it asked FERC to set the complaint for hearing and reset SERI’s ROE, equity ratio and depreciation rates to a just and reasonable level.
The commission’s Aug. 24 order granted the PSC’s complaint about the ROE element, establishing hearing and settlement judge procedures and setting a refund effective date of April 27. It denied the capital structure elements and dismissed the depreciation rate elements.
Louisiana regulators charged that SERI’s ROE of 10.94% was calculated based on a record “developed in the mid-1990s,” saying that conditions have changed significantly since then, as investor return requirements, interest rates and inflation have decreased. They argued that SERI’s equity investor and shareholders faced almost no risk because the company sells Grand Gulf’s entire output to four utilities that are wholly owned by Entergy and are obligated by the UPSA to buy the power regardless of the amount delivered.
FERC found the Louisiana commission raised issues of material fact that it couldn’t resolve, and it set the complaint for investigation and a Section 206 trial-type evidentiary hearing. It encouraged the parties to make every effort to settle their disputes before hearing procedures begin.
Commission Approves Settlement Between Entergy, Parties
The commission last week also approved a settlement among SERI, the Arkansas, Louisiana and Mississippi commissions, Cooperative Energy, and New Orleans City Council, addressing issues regarding the depreciation rates to be applied under SERI’s UPSA (ER17-2219).
SERI amended the agreement between itself and its operating companies in 2017 to revise the depreciation rates used to calculate Grand Gulf’s depreciation and amortization expenses and update the depreciation rates for use in calculating the plant’s annual revenue requirement for decommissioning costs.
