The Maryland Public Service Commission extended the schedule for its review of Transource Energy’s controversial Independence Energy Connection for 30 days to allow parties to provide additional evidence on proposed alternatives.
The PSC rejected a motion by the Power Plant Research Program (PPRP) of the Maryland Department of Natural Resources to dismiss Transource’s application for a certificate of public convenience and necessity (CPCN) or suspend the schedule.
But the commission’s Jan. 15 ruling set a new deadline of Feb. 25 for the PPRP, PSC staff, the Office of People’s Counsel (OPC) and local residents opposing the line to file direct testimony (Case #9471).
PSC staff and OPC supported PPRP’s argument that the PSC should reject the project because Transource failed to examine alternative solutions as required by state law. Staff recommended the commission grant the motion, suspend the procedural schedule and direct Transource to supplement its application.
The $372 million project would add two 230-kV double-circuit lines, totaling about 42 miles across the Maryland-Pennsylvania border.
Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | Transource
The PPRP said Transource had failed to meet requirements to examine alternatives if an existing transmission line “is convenient to the service area; or the use of the transmission line will best promote economic and efficient service to the public.”
The agency said the need for the eastern segment of the project could be met by the existing Furnace Run-Conastone and Furnace Run-Graceton 230-kV double-circuit transmission tower lines, each of which has only one 230-kV circuit and could carry a second. (See Cancel Transource Line, Md. Panel Says.)
Transource responded it was not required to study PPRP’s proposed alternative and said it met the requirements of state law by analyzing “over 30 study segments.”
“Disputes over whether the commission should consider an alternative are properly the subject of competing testimony at the evidentiary hearing,” Transource said.
The commission said it was modifying the procedural schedule to allow the parties to conduct additional analysis or discovery regarding the use of PPRP’s alternative.
“In response to PPRP’s motion, Transource acknowledges that as the CPCN applicant — the party with the burden of proof — it should be prepared to present evidence at the hearing to address any suggestions by other parties that the proposed project should be denied because there exists a clearly superior alternative,” the commission said. “This criteria includes the existing transmission line evaluation requirements set forth in [section 7-209 of the Public Utilities Article, Maryland Annotated Code].”
Rebuttal testimony will be due by March 18, with surrebuttal testimony and any PPRP response to public comments due April 1. The commission said it will allow live rejoinder testimony if needed during the evidentiary hearings.
Mary Urban, community affairs representative for Transource, issued a statement reiterating it has met all filing requirements under Maryland law.
“Transource has presented a substantial amount of information regarding alternatives,” Urban added. “As the case proceeds, the company will respond as is appropriate under commission rules.”
PJM said in November the project would reduce load costs by $707.3 million in net present value over 15 years, producing a benefit-cost ratio of 1.4. PJM declined to comment Tuesday.
Assistant Attorney General Sondra Simpson McLemore, who filed the motion to dismiss for PPRP, did not immediately respond to a request for comment.
PG&E Corp. and its subsidiary Pacific Gas and Electric will file for federal bankruptcy protection by Jan. 29, the companies announced Monday, capping a tumultuous week in which PG&E’s stock price plummeted and its credit rating was downgraded to junk status by two major ratings firm.
A day earlier, PG&E said CEO Geisha Williams would be stepping down and leaving the company. Her tenure with the company has coincided with major disasters, including the 2010 San Bruno gas line explosion as a senior executive, and the 2017 wine country fires and 2018 Camp Fire, the deadliest in state history.
Together, those three events killed 104 people, destroyed 28,000 structures and burned approximately 400,000 acres. PG&E was found criminally liable for the San Bruno explosion, which wiped out a suburban San Francisco neighborhood. The Tubbs Fire, which burned down the northern part of Santa Rosa, Calif., in October 2017 and the Camp Fire, which leveled the town of Paradise in November 2018, remain under investigation, though PG&E equipment is a suspected cause of both.
In a U.S. Securities and Exchange Commission filing Monday, PG&E said it faces $30 billion in liability for the last two fire seasons, not including punitive damages, fines or penalties, which could add up to billions more. As of Friday, 750 lawsuits had been filed against PG&E for the Camp Fire and the wine country fires on behalf of a total of 5,600 plaintiffs, the company said. Eleven of the lawsuits are seeking class-action status, it said.
PG&E said its liability insurance and liquid assets would cover only a small fraction of those claims, and that bankruptcy was its only recourse.
“Following a comprehensive review with the assistance of our outside advisers, the PG&E board and management team have determined that initiating a Chapter 11 reorganization for both the utility and PG&E Corp. represents the only viable option to address the company’s responsibilities to its stakeholders,” PG&E Chairman Richard C. Kelly said in a news release.
A recent state law requires the company to give a 15-day advance notice of its intent to file for bankruptcy.
PG&E, founded 114 years ago in San Francisco, announced it was seeking bankruptcy protection this week as it faces $30 billion in liability for deadly wildfires in 2017 and 2018.
Ensuring Operations
PG&E said it expects to continue to be able to provide uninterrupted electric and gas service to its 16 million customers across 70,000 square miles of Northern and Central California. PG&E’s service territory stretches from near the Oregon border in the north to Santa Barbara County in the south, and from the coast to the Sierra Nevada mountains.
The company told the SEC, however, that it does not plan to pay the $21.6 million in interest due Tuesday on its outstanding senior notes, although it had 30 days to make the interest payment before triggering a default.
It said it knows that parties it does business with will worry about getting paid too, but it expects to meet its obligations. (See related story, PG&E Credit Woes Spread, Worrying CAISO Members.)
“PG&E expects that the decision to seek relief under Chapter 11 will raise concerns among its constituencies, including customers, vendors, suppliers and employees, and may lead to a contraction in trade credit and the departure of key employees,” it said. “PG&E has taken steps, however, to mitigate the impact of these potential developments.”
That includes seeking debtor-in-possession (DIP) financing available to companies in bankruptcy.
“PG&E expects to have approximately $5.5 billion of committed DIP financing at the time it files for relief under Chapter 11 on or about Jan. 29, 2019, and has received highly confident letters from a number of major banks,” the company wrote. “The DIP financing will provide PG&E with sufficient liquidity to fund its ongoing operations, including its ability to provide safe service to customers.”
California’s new governor, Gavin Newsom, issued a press release Monday saying he’d been monitoring the situation closely.
“When I took office one week ago today, I immediately instructed my team to meet with the California Public Utilities Commission, CAISO, PG&E and labor unions representing the workers who work for PG&E,” Newsom said. “My staff and I have been in constant contact throughout the week and over the weekend with these stakeholders and regulators. Everyone’s immediate focus is, rightfully, on ensuring Californians have continuous, reliable and safe electric and gas service.
“While PG&E announced its intent to file bankruptcy today, the company should continue to honor promises made to energy suppliers and to our community,” he said. “Throughout the months ahead, I will be working with the legislature and all stakeholders on a solution that ensures consumers have access to safe, affordable and reliable service, fire victims are treated fairly, and California can continue to make progress toward our climate goals.”
‘Very Short Runway’
Some said it isn’t too late for California lawmakers to head off bankruptcy.
ClearView Energy Partners, a research firm based in D.C., said the State Legislature could pass a bill that extends provisions of last year’s Senate Bill 901. That measure allows the CPUC to apply a financial stress test for 2017 wildfire liability to determine how much a utility can afford to pay without harming its customers or destroying its business.
Lawmakers could extend that provision to cover 2018 fires, giving PG&E another route to remain solvent, ClearView said in an email to its clients.
“The 15-day notice offers a very short runway for lawmakers to act before Chapter 11 proceedings could begin,” the firm said. “We have observed lawmakers in California and other states move quickly when faced with an immediate concern. Still, the high degree of controversy and public outcry stemming from wildfire damages and perceived blame assigned to PG&E likely creates headwinds in the legislative process. Each day that passes without a legislative proposal could diminish the prospects for a legislative ‘fix.’”
Even after Jan. 29, it may be possible to stop the bankruptcy proceedings, ClearView said.
“We are not bankruptcy experts, but our state sources indicate that the initial steps in the Chapter 11 process are reversible. In other words, if state lawmakers do enact a law after January to change liability risk from wildfires that occurred last calendar year, PG&E could halt the proceeding. Still, we believe lawmakers need to take some action by the end of the month.”
SB 901 was a compromise measure put together hastily at the end of last year’s legislative session. (See California Wildfire Bill Goes to Governor.) Earlier, then-Gov. Jerry Brown called for lawmakers to overturn state court precedent that holds utilities strictly liable for all wildfire damage caused by their equipment, regardless of negligence. He was worried that PG&E might declare bankruptcy after the 2017 fires, undermining its support of clean energy and Brown’s ambitious goals related to climate change.
He may have had a point. Last week one of the nation’s largest solar arrays, the Topaz Solar Farm in Central California, had its credit rating downgraded to junk status because it had signed a 25-year power purchase agreement with PG&E. S&P Global Ratings said Topaz, owned by Warren Buffett’s Berkshire Hathaway Energy, could be harmed by PG&E’s inability to pay.
On Monday, the Natural Resources Defense Council said PG&E’s bankruptcy could spell bad news for California’s goals, enshrined in last year’s SB 100, of relying on 60% renewable energy by 2030 and achieving zero-carbon status by 2045.
“As NRDC warned months ago, potential adverse consequences include a loss of state oversight and damage to significant clean energy programs critical to reaching California’s climate goals,” including PG&E’s planned investments in electric vehicle infrastructure, NRDC said in a news release. “At risk could be billions of dollars of funding for PG&E’s nation-leading clean energy initiatives, which are designed to help fight the effects of climate change like these tragic wildfires.”
The legislature reconvened Jan. 7. Lawmakers, some of whom have backed away from supporting PG&E, have yet to offer any bills that could help the utility.
VALLEY FORGE, Pa. — Shell Energy N.A. came to the Market Implementation Committee on Wednesday to make its case against PJM’s attempts to recover charges from financial transmission rights that the company purchased from failed GreenHat Energy.
After PJM sought more collateral from GreenHat as its losses mounted in April 2017, the company gave the RTO the rights to collect money it said Shell owed it for purchasing some of its FTR portfolio.
PJM was left emptyhanded when Shell said it had already paid GreenHat all it owed. (See Doubling Down – with Other People’s Money.) But the RTO is hoping to recover some of GreenHat’s losses through its indemnification rules on bilateral FTR trades.
PJM Chief Financial Officer Suzanne Daugherty presented the RTO’s interpretation of its indemnification rules to the MIC, saying PJM’s Tariff requires secondary market buyers of FTRs to indemnify PJM and its members for “charges, not net charges” related to the position.
“That was purposeful, the way the wording was written,” Daugherty said.
She said PJM believes the rule is clear. “Shell also thinks it’s clear but disagrees with our interpretation,” she said.
After Daugherty spoke, Shell’s Matthew Picardi outlined his company’s position, saying the indemnification provision does not apply to its transactions. In a Jan. 2 filing opposing its Oct. 1 motion to withdraw proposed Tariff amendments related to its indemnification rules, Shell said that, “contrary to PJM’s characterization,” the company has never acknowledged it “sold” FTRs to GreenHat or otherwise triggered the Tariff’s guarantee and indemnification provision.
Even if the provision does apply, Picardi said, PJM is misinterpreting it by requiring indemnifying parties to pay more than the defaulting party would have owed — a heads-I-win, tails-you-lose proposition.
“PJM believes that netting is not allowed,” Picardi told the MIC. “We disagree with that.”
He presented an example in which the original holder of an FTR would net a profit of $1,859 over one month if it remained owner while a secondary market buyer of the FTR would owe PJM $1,210 because it was denied profits on days when the FTR was in the black.
Shell made the same arguments to FERC in the docket opened by PJM, in which the RTO proposed Tariff changes that would allow indemnifying sellers to assume negatively valued FTR positions on which its indemnified buyer defaulted.
“Such a provision would provide the opportunity for the indemnifying seller to assume ownership of and manage its exposure to the negatively valued FTRs, regardless of the disposition process for the remaining FTR positions in the defaulting member’s FTR portfolio,” PJM said. “At the very least, electing this option would not put the seller in any worse position, since indemnifying sellers are already responsible for the charges associated with those bilateral FTR positions if the indemnified buyer does not pay such costs itself” (ER19-24).
“Such an assumption would allow the indemnifying seller the ability to manage its exposure from its indemnification, but it also protects PJM and its members because the indemnifying seller is assuming the volatility and of course providing the requisite credit,” the RTO added.
Shell Energy presented an example in which the original holder of an FTR would net a profit of $1,859 over one month if it remained the owner while a secondary market buyer of the FTR would owe PJM $1,210 because it was denied payments on days when the FTR was profitable. | Shell Energy N.A.
After FERC staff issued a deficiency notice seeking more information on its indemnification procedures, however, the RTO asked to withdraw its filing, saying “the proposal does not provide sufficient benefits to the PJM membership to justify PJM continuing to seek approval.” (See “Bilateral FTR Retraction,” PJM MRC/MC Briefs: Dec. 6, 2018.)
Although it opposed PJM’s proposed Tariff change, Shell asked FERC not to end the docket, saying the withdrawal would prevent the commission from ruling on its dispute with the RTO over the existing indemnification rules.
“Members subject to a guarantee and indemnification claim by PJM should be able to assume all of the FTRs subject to the claim,” Shell said. “Under PJM’s proposed tariff amendment, only negatively valued FTRs subject to the claim could be assumed, which leaves the party with PJM’s improper calculation of guarantee payments for any FTRs not assumed.”
Shell said the commission should only close the docket if it simultaneously opens a Section 206 proceeding to determine whether PJM’s interpretation is correct or unjust and unreasonable. “Allowing PJM to withdraw its Tariff amendment without initiating a Section 206 proceeding will leave members with little choice but to file a complaint for relief,” Shell said.
Separately, the RTO has asked a judge in Harris County, Texas, to compel depositions by GreenHat’s principals as a prelude to a potential civil suit against the traders. GreenHat responded with a counterclaim alleging Shell reneged on $70 million it owes for the transactions (Case No. 2018-69829).
Shell responded that the Texas court lacks jurisdiction over GreenHat’s claim. The court rejected Shell’s argument and created a second docket for the companies’ dispute.
VALLEY FORGE, Pa. — PJM’s proposed revisions to how it prices reserves in its energy market necessitates changes in the RTO’s capacity market to prevent substantial overpayment by customers for electricity and the exercise of market power by generators, Independent Market Monitor Joe Bowring said Friday.
Without a true-up, PJM’s package of changes, being developed under a Jan. 31 deadline imposed by the RTO’s Board of Managers, would result in the overpayment of at least $6 billion to generators over four years after its implementation, Bowring told the Energy Price Formation Senior Task Force (EPFSTF), as well as significantly higher overpayment after that without specific market design changes in the capacity market.
“PJM’s apparent goal is to shift revenue from the capacity market to the energy and reserve markets,” Bowring said in a presentation. If so, he said, “there must be a clear and verifiable mechanism to ensure that the shift occurs effectively, equitably and efficiently.”
The RTO has proposed raising the maximum price in the operating reserve demand curve (ORDC), used to set prices for reserve products, from $850 to $2,000. The proposed ORDC would raise both energy and reserve prices significantly. PJM would also use the same ORDC in the day-ahead and real-time markets for reserves, introducing the ability to procure primary reserves in the day-ahead and secondary reserves in the real-time. (See Section 206 Filing on PJM Reserve Pricing Likely.)
Bowring said increased energy market revenues won’t result in lower capacity prices without changes to the variable resource requirement (VRR) demand curve. The curve is based on the net cost of new entry (CONE), which considers all generator revenues from energy and ancillary services markets.
The Monitor proposed setting net CONE as the maximum price on the curve. As a result, Bowring said, capacity prices could be $0 under some circumstances when energy market revenues are high.
“You can’t have it both ways,” Bowring said. “If you shift this high level of revenue from the capacity market to the energy market, you’re effectively eliminating the capacity market.”
The Monitor first raised its concerns at the task force’s previous meeting Jan. 4, but Friday’s meeting marked the first time it made explicit its proposals for why the VRR curve needs to change in response to PJM’s proposal.
Capacity markets serve the same function as scarcity pricing, he said: to provide enough revenue to ensure there is adequate supply to meet demand. “I’m not arguing that we should get rid of the capacity market, but if PJM’s changes to increase energy and reserve prices are implemented, we have to make sure people are not paying twice for the same product.”
Bowring said PJM’s logic for the package of revisions “escapes me.” But, he said, if that was what the RTO wanted to do, his concerns would need to be addressed to prevent overpayments.
“I am not sure why PJM believes that there is urgency to this,” Bowring said in an email. “It is not a simple matter, and PJM’s approach has not been adopted by other RTO/ISOs.”
Bowring also said an increased reliance on the energy market will reduce PJM’s ability to “pick the reserve margin quite so precisely.”
“It’s the same lesson ERCOT learned,” he said of the Texas grid operator, which does not have a capacity market.
Adam Keech, PJM executive director of market operations, did not directly dispute Bowring’s arguments. But he did take exception to the idea that the RTO was trying to eliminate the capacity market. “The goal [of PJM’s proposal] is not to shift revenue,” he said at the meeting. “The goal is to price energy and reserves correctly.”
Keech told RTO Insider after the meeting that PJM was waiting for information from the Monitor, “because we have thought about it and not been able to identify what the issues are that they see.”
Bowring said that PJM has explicitly ignored the potential revenue impact on the capacity market during the transition period. “In other words, PJM is proposing that customers pay twice for the same product during the transition period.”
The RTO proposes to use simulations to estimate the increase in energy revenue in defining the VRR curve in the capacity market auctions after the transition period. “PJM clearly has thought about the issues,” he said, “but they have a very different proposal than the IMM’s proposal.”
RTO VRR curve comparison | Monitoring Analytics
Stakeholder reaction to Bowring’s presentation was mixed. Brock Ondayko of American Electric Power said that, without further modifications to the VRR curve, he expected capacity to clear at lower prices under the proposed rules because of the increased energy and reserve revenues. Bowring’s predictions “just seem counterintuitive,” he said.
But consultants James Wilson and Roy Shanker, and Susan Bruce, attorney for the PJM Industrial Customers Coalition, agreed the IMM had identified a problem that needed to be addressed.
With the PJM board’s deadline looming, however, it may not matter.
“We’re in an interesting spot, both from a timing and scope perspective,” said Dave Anders, PJM director of stakeholder affairs and chair of the task force, explaining that the capacity market curve is out of scope under the issue charge the Markets and Reliability Committee approved. The MRC’s next meeting is Jan. 24, when the committee is expected to vote on PJM’s proposal.
Anders said stakeholders offering alternatives to PJM’s proposals should include any measures to address the capacity curve issue as an addendum, not as part of the packages to be voted on by task force members Jan. 17. “I don’t want to use the process to ignore what may be a significant issue,” he said.
Bowring said PJM would be foolish to ignore the impact of such a “radical change” to the energy market on the capacity market. “It is going to be part of the scope in front of FERC,” he said.
Transparency Proposal
Wilson, a consultant to consumer advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C., ended the session with a brief presentation in which he said PJM should make public appeals for conservation when administrative shortage prices reach a threshold so that customers know they are facing high prices and have an opportunity to reduce their consumption. He said the trigger could be the shortage price component hitting $300/MWh.
“It shouldn’t be just a quiet little press release on the PJM website,” Wilson said. “It ought to be on the nightly news.”
PJM’s current rules call for such appeals only when reliability is at risk.
Concern about the ripple effects of Pacific Gas and Electric’s financial meltdown had already spread last week as CAISO addressed worries about the utility’s potential to default on its payments to the ISO, and a solar farm owned by Warren Buffett’s Berkshire Hathaway saw its credit rating cut to junk status because of its dependence on PG&E.
Those worries will grow after PG&E announced Monday it would file for Chapter 11 bankruptcy protection by Jan. 29 because it faces $30 billion in liability for the catastrophic wildfires of 2017 and 2018. (See related story, PG&E Says It Will File Bankruptcy, as CEO Steps Down.)
On Friday, CAISO issued a market notice aimed at easing concerns about how PG&E’s problems could affect the ISO and its participants.
“The California ISO has received inquiries relating to the financial status of Pacific Gas & Electric Co. in light of recent media reports,” the notice said. “The ISO wants to assure market participants that PG&E has posted collateral with the ISO to cover its outstanding and upcoming obligations.”
Should PG&E default, however, the ISO’s other members would have to pick up the tab. CAISO rules require each market participant to cover default losses “in proportion to the benefits it receives from its activity” in the market. When GreenHat Energy spectacularly defaulted in June in PJM’s financial transmission rights market, other members were angry that they had to cover tens of millions of dollars in payments. (See Greenhat FTR Default a ‘Pig’s Ear’ for PJM Members.)
GreenHat was a relatively small player in PJM, whereas PG&E, California’s largest utility, is a huge part of CAISO. The total volume of energy delivered in CAISO in 2017 was 228,191 GWh, according to the ISO’s annual Market Issues and Performance Report. PG&E’s total deliveries that year were 82,226 GWh, the utility said in its Annual Report to Shareholders.
Bankruptcy Imminent
The question of PG&E’s default isn’t academic. The company’s circumstances have been quickly worsening, raising questions about its ability to continue making ISO payments.
Hours before Monday’s bankruptcy announcement, PG&E said CEO Geisha Williams was stepping down amid the growing turmoil.
Both Moody’s Investors Service and S&P Global Ratings cut PG&E’s credit rating to “junk status” last week, citing the utility’s financial exposure for two years of massive, deadly wildfires along with the waning will of politicians to bail out the state’s largest utility. (See PG&E Stock Plunges, Credit Downgraded to ‘Junk’ Status.)
PG&E’s stock price plummeted after November’s Camp Fire and continued plunging this week amid talk of the company declaring bankruptcy and selling off its gas division. | Google
“The downgrade reflected our assessment of a weakening of the company’s governance, the souring political environment that we expect will lead to a weakening of the regulatory construct, what we see as the company’s limited capital market access, and the possibility of a voluntary bankruptcy filing given the immense pressures and uncertainties still facing the company,” S&P said in an update posted on its website Friday.
As of Monday afternoon, PG&E had lost about $32 billion, or nearly 78% of its market value, over 15 months starting in October 2017, when 21 major fires swept Northern California’s famed wine country. Those fires killed 44 people and destroyed thousands of homes, including a substantial part of the city of Santa Rosa.
State fire investigators blamed PG&E for at least 17 of those blazes, and its stock price sunk from more than $70/share to about $38/share. For months, the utility’s stock price hovered in the range of $40 to $50/share, then the Camp Fire struck Nov. 8. The deadliest fire in state history killed 86 people and wiped out the town of Paradise in the Sierra Nevada foothills of Butte County.
PG&E’s equipment quickly fell under suspicion after the company reported to the Public Utilities Commission that it had experienced a problem with a transmission line, and that employees saw flames near the Camp Fire’s point of origin on the morning it started.
The company saw its stock price drop to less than $18/share last week as S&P downgraded its credit rating from investment grade to junk status.
News reports, quoting unnamed sources, suggested the utility might be getting ready to file for bankruptcy — or to put its downtown San Francisco headquarters on the market or sell off its gas division.
By Monday afternoon, PG&E shares were selling for about $8 on the New York Stock Exchange.
‘Negative Implications’
The uneasiness about PG&E’s future has started to spread to companies with which it does business
On Friday, S&P slashed the credit rating of the 550-MW Topaz Solar Farms in San Luis Obispo County to junk, citing its reliance on PG&E, with which it has a 25-year sales contract. Topaz is owned by BHE Renewables, a subsidiary of Buffet’s Berkshire Hathaway Energy. The solar farm was completed at a cost of $2.4 billion in 2015.
The 550-MW Topaz Solar Farms in central California, one of the largest photovoltaic power plants in the world, has been caught up in PG&E’s financial meltdown. | NASA Earth Observatory
“Topaz Solar Farms receives all of its revenue from PG&E under a long-term power purchase and sale agreement,” S&P said. “Our rating on the solar project is currently capped by our view of the credit quality of PG&E, its utility offtaker.”
S&P put Topaz on its credit watchlist with “negative implications.”
“The CreditWatch negative listing reflects the increasing risk that we will downgrade PG&E by one or more notches over the next few months. If we lower our ratings on PG&E again, it could lead us to take an equivalent action on our ratings on Topaz Solar Farms.
“If PG&E files for Chapter 11, this could, subject to it being a material adverse effect, trigger a cross default under Topaz Solar’s financing documents unless the power contract is replaced within 90 days of the bankruptcy event,” S&P added.
In a separate post on its website Friday, S&P explained why it had downgraded PG&E’s credit rating from BBB- to B Jan. 7.
“A number of events, over several weeks, contributed to our … multinotch downgrade,” it said.
Immediately after the Camp Fire, it appeared that state lawmakers and regulators would try to keep PG&E afloat to protect ratepayers and to achieve the state’s ambitious renewable portfolio standards, S&P said. A new law, SB 100, requires the state to obtain 60% of its energy from renewable sources by 2030.
But public anger intensified, with protests at PUC hearings and PG&E headquarters. That anger has undermined the will of state regulators and politicians to protect PG&E, S&P said.
An allegation by the PUC in December that PG&E had falsified natural gas safety records made things worse. Politicians who had supported the utility expressed distrust.
On Jan. 4, PG&E issued a press release saying it was planning to shuffle its board of directors and reviewing “structural options,” including in its operations, finances and management. Speculation quickly followed that PG&E might file for bankruptcy.
“It was the totality of these events that led to S&P Global Ratings’ downgrade of PG&E into speculative grade,” the credit rating firm said.
VALLEY FORGE, Pa. — PJM is considering changing interconnection rules to accommodate transmission serving offshore wind generation.
Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO.
PJM’s Sue Glatz presented the Planning Committee a problem statement to consider allowing merchant transmission developers to request capacity interconnection rights, or equivalents, for non-controllable AC transmission facilities.
Glatz said transmission developers have expressed interest in building AC transmission to accommodate future generation interconnection requests. The developers want to acquire capacity interconnection rights so PJM can identify the necessary network upgrades, she said.
The key difference is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses, Glatz said.
PJM hopes to develop a FERC filing on Phase 1 of the initiative — focusing on rules for a single offshore generator lead line — by July.
Phase 2 will consider networked offshore transmission for connecting multiple wind sites. A FERC filing is targeted for September 2020. “We view this as much further down the road,” Glatz said.
John Brodbeck of EDP Renewables N.A. asked PJM to offer education on what open-access rights generators will have to the lines.
Theodore Paradise, ISO-NE’s former assistant general counsel for operations and planning, who has joined transmission developer Anbaric as special counsel, asked for a discussion on how HVDC facilities are modeled in PJM.
The committee will be asked to approve the problem statement at its next meeting.
PJM Seeks Fix on Queue Filing Errors
PJM is proposing a one-sentence rule change to help developers avoid being removed from interconnection queues because of minor errors or omissions.
Interconnection customers are generally granted up to 10 business days to resolve deficiencies found by the RTO. But under changes initiated in 2016, requesters must clear all deficiencies by the last day.
The changes were intended to dissuade developers from late submissions. But PJM said requests are not being submitted any earlier and the changes were undermined by FERC rulings reinstating applicants removed for minor errors.
PJM’s Susan McGill presented the PC a proposed problem statement to ensure that all applicants have up to 10 business days to correct deficiencies, whether they enter on Day 1 or the last day of the six-month queue.
“We can’t have another queue where people get bumped out … they go to FERC and get waivers [to return]. It’s very disruptive,” Vice President of Planning Steve Herling said.
Since the AA1 queue opened in May 2014, 50 to 60% of interconnection requests were submitted in the last month of the queue.
Prior to the 2016 changes, which resulted from the Earlier Queue Submission Task Force, about 18% of projects submitted in the last month of the queue were withdrawn for deficiencies. After the EQSTF changes, that withdrawal rate increased to 24%.
PJM is proposing to give all projects 10 days to address problems by removing the following sentence from the Tariff: “Any queue position for which an interconnection customer has not cleared the deficiencies before the close of the relevant new services queue shall be deemed to be terminated and withdrawn, even if the deficiency response period for such queue position does not expire until after the close of the relevant new services queue.”
“We’re not looking for reasons to get rid of you,” McGill explained.
PJM’s Dave Anders said Manual 34 allows the first discussion of a problem statement to include a proposed solution if the committee chair determines “the problem presented is sufficiently simple.”
Herling said, “We do have more changes we think need to be made [to interconnection queue rules]. But that will require a more robust conversation.”
PJM Pondering Wind Capacity Measures
Wind generators could see lower capacity credits under rule changes being considered by the RTO.
PJM’s Tom Falin presented the PC with the updated results of the RTO’s analysis of wind and solar resources’ effective load carrying capability (ELCC) — a measure of the additional load that a group of generators can supply without a reduction in reliability.
Effective load carrying capability is a measure of the additional load that a group of generators can supply without a reduction in reliability. | PJM Renewable Integration Study (2014), General Electric
The new results use the 2018 reserve requirement study (RRS) capacity model, which shows nameplate capacities for 2022/23 of 14,620 MW of wind and 5,290 MW of solar.
PJM found the average wind ELCC between delivery year 2009/10 and 2017/18 was 11.5%. That suggests the RTO’s current practice of using wind’s average capacity factor of 17.1% overstates wind’s value, Falin said. The median capacity factor over that period was 8%.
“We feel [the median is] a much, much better indicator of the reliability value” of the resources than the average, Falin said.
PJM found the average solar ELCC since 2012/13 is 42.3%, close to the average capacity factor of 42.1% and median capacity factor of 40.9%.
Falin posed two questions to stakeholders: Should PJM continue with its original proposal to change the intermittent resource capacity credit calculation from an average value to a median value? Or should it base the calculation on the ELCC methodology?
He said the advantage of changing from average to median capacity factor is “it’s much less of a black box” than ELCC.
Although the figures represent ELCC values RTO-wide, PJM said the ELCC must be allocated to individual generating units based on individual unit performance.
PJM calculates capacity credits for existing wind resources by multiplying the ELCC by the total nameplate. The RTO has three options for prorating the total capacity credit for existing units:
The average output of an individual unit during a specified number of daily peak hours in each year for which the unit was in-service;
The average output of an individual unit during the daily peak hours in which the loss-of-load expectation (LOLE) is non-zero in each year for which the unit was in-service; or
The average output of an individual unit during hours ending 3, 4, 5 and 6 p.m. during the summer season in each year for which the unit was in service.
Falin said the second option could involve as few as three hours or as many as 12 per year. The last option — PJM’s current method — has the advantage of being based on a lot of data, making it more stable than the other choices. But Falin said it also includes many hours with no LOLE risk.
For new resources, the credit can be calculated by:
multiplying the systemwide ELCC by the nameplate of the new unit (as MISO does);
multiplying an estimated zonal ELCC by the nameplate of the new unit; or
multiplying an estimated unit-type ELCC by the nameplate of the new unit.
RTO-wide ELCC values will be updated each year as part of the installed reserve margin study.
New units will continue to have the option to provide data justifying capacity credits greater than the ELCC value. As under current rules, new units’ actual performance will be rolled in over a three-year period.
PJM wants to develop manual language and request MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August.
The changes would be effective June 1, 2022; thus, they would not affect UCAP values from prior auctions.
Transmission Expansion Advisory Committee
Dominion Plans $7.5M Substation Project
Dominion Energy plans to spend $7.5 million on a new substation to accommodate a new data center campus in Fauquier County, Va., with a total load of more than 100 MW.
The company will interconnect a new Lucky Hill substation between the Remington and Gordonsville substations on line #2199, a 230-kV circuit.
The requested in-service date is Sept. 15, 2020.
Supplemental Projects More than Double Baseline Additions in 2018
Transmission owners proposed $5.7 billion in supplemental projects in 2018, more than double the $2.065 billion in baseline projects included in the 2018 Regional Transmission Expansion Plan, PJM’s Aaron Berner told Transmission Expansion Advisory Committee members Thursday.
Most of the supplemental projects were presented by American Electric Power ($2.4 billion) and Public Service Electric and Gas ($1.46 billion).
More than half of the baseline projects were attributed to aging infrastructure.
Transmission owners’ supplemental projects have outpaced baseline projects in all but one year since 2015, totaling almost $15 billion. Baseline projects totaled only $8.1 billion over the same period. | PJM
Reliability Window Likely in June
In an update on the assumptions for the 2019 RTEP, Berner said the RTO expects to open a reliability window for proposals in June.
The 2010 RTEP will include 27 locational deliverability areas and Ohio Valley Electric Corp. FERC approved OVEC’s integration into PJM last February.
Generation with executed facilities study agreements (FSAs) will be modeled offline along with associated network upgrades, which will be analyzed separately. Berner said PJM could “turn on” FSA generation and their upgrades if there are many generation retirements but said the RTO does not expect to do so.
Travis Stewart of Gabel Associates said the American Wind Energy Association would like PJM to analyze the consumer benefits of states sharing the costs of transmission to accommodate their renewable portfolio standards. Stewart said AWEA wants more information on projects that could relieve congestion and allow PJM to access higher quality wind in the Midwest. The group may request PJM consider an RPS build-out as an RTEP future, he said.
PJM to Sunset Regional Planning Process Task Force
PJM notified stakeholders Friday that it plans to sunset the Regional Planning Process Task Force on Feb. 1 unless it receives objections from stakeholders within the task force, PC or the Markets and Reliability Committee.
The MRC voted in April 2015 to place the task force on hiatus in case it needed to be reconvened to address FERC Order 1000 or other issues. (See “Regional Planning Process Senior Task Force Placed on Hiatus,” PJM Markets and Reliability Committee & Members Committee Briefs.)
VALLEY FORGE, Pa. — It was one of the shortest Market Implementation Committee meetings in memory Wednesday as stakeholders clocked out in only two and a half hours following discussions of the must-offer exception process, FERC’s energy storage order and PJM’s indemnification rules on bilateral trades of financial transmission rights. (See related story, Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
PJM May Split Rule Changes on Must-offer Exceptions
PJM may seek approval of widely supported changes to the must-offer exception process while having further discussions on revisions that lack consensus, RTO officials told the MIC.
The process behind the rule changes was initiated by Exelon to investigate issues including the process for existing capacity resources with a must-offer requirement to become energy-only resources.
The changes with widest support would allow market participants to voluntarily remove a generator from its capacity resource status by making a request to PJM and the Independent Market Monitor. It would also permit participants to request exemptions from multiple auctions in a single exception request. It would allow such changes for new resources that cannot be completed by the start of the delivery year for which it cleared.
There is less consensus on a rule that would require generators to forfeit their capacity injection rights (CIRs) if they are repeatedly approved for CP must-offer exceptions and not offered in capacity auctions for three consecutive delivery years.
Monitor Joe Bowring said the proposed changes failed to strike the right balance.
Bowring said PJM should discourage generators from holding on to CIRs for a long period of time because “they can’t make up their mind” about being a capacity resource.
“If someone has a clear plan, and they’re following it, that’s fine,” Bowring said. “We think this [proposal] allows more than that.”
Carl Johnson, representing the PJM Public Power Coalition, was also critical. “I’m struggling to find anything I like about any of this,” he said. “This doesn’t hang together to me as an effective set of rules.”
Sharon Midgley of Exelon asked PJM to move forward on the parts of the package with wide support, saying the only issue in dispute was over the RTO involuntarily seizing CIRs from generators after three years of successive must-offer exception requests.
PJM stakeholders are still debating a rule change that would require capacity resources to become energy-only after three consecutive years of exemptions from must-offer rules. | PJM
But Marji Philips of Direct Energy said her company would not support a “quick fix” based on what has been proposed to date. “The process as proposed is a little bit loose yet,” she said, adding that CIRs are “a very serious barrier to new entry.”
A few stakeholders rekindled an earlier debate over whether CIRs are generators’ “property rights.”
Gary Greiner of Public Service Enterprise Group said stakeholders need PJM’s opinion on the issue. “We’ve kind of danced on the periphery, but we’ve never come at it head on,” he said.
PJM’s Pat Bruno said the RTO may split the issue so it can seek approval of its non-controversial elements. He said the RTO will conduct additional discussions with stakeholders before the next MIC.
Electric Storage Rules Require Manual Changes
PJM’s Laura Walter gave stakeholders an update on the RTO’s implementation of rules opening its markets to electric storage, saying as many as 15 manuals may require revisions.
PJM made two filings to comply with FERC Order 841 on Dec. 3, one covering markets and operations (ER19-469) for which comments are due Feb. 7, and a second governing accounting (ER19-462), for which the comment period closed on Jan. 4. The RTO plans to implement the changes by Dec. 3.
Walter said stakeholders will be asked for feedback on energy storage cost offers at the February MIC meeting. Among the items to be discussed will be whether cost offers should be based on inventory cost (historical weighted average cost of stored energy available for discharge, adjusted for round-trip efficiency); opportunity costs (expected lost net revenue from operating in a given hour); or replacement cost (estimated future weighted average cost of charging energy over the next available operating period).
First drafts of manual revisions will be presented before July, Walter said.
VALLEY FORGE, Pa. — During an Operating Committee presentation last Tuesday on changes to Manual 12, Carl Johnson of the PJM Public Power Coalition said he was “stunned” by reports of generators’ poor performance in providing primary frequency response (PFR).
In October, PJM reported on an analysis of 454 generating units’ responses to 13 events between December 2017 and April 2018. It found that 36% failed to respond or responded in the wrong direction, while only 42% provided 75% or more of the response required.
“It seems to me you would be having more problems than you are if performance was as poor as it appeared,” Johnson said. “Are we measuring the right thing?”
Johnson’s comments came as PJM’s Danielle Croop gave a first read of an updated Manual 12 that includes a new section to describe how the RTO will measure PFR and respond to poor performers.
In 2012, NERC reported that only 30% of units online provide PFR — automatic adjustments that begin within seconds of detecting frequency variations — and only 10% of units online sustain it. FERC cited the data when it issued new PFR requirements in Order 842 last February.
The Markets and Reliability Committee agreed to continue monitoring units’ PFR performance during 2019 after suspending the Primary Frequency Response Senior Task Force, which failed to come to consensus on any proposals to require existing units to provide the service. (See “PFR Task Force on Hiatus,” PJM MRC Briefs: Dec. 20, 2018.)
The task force was put on hiatus after stakeholders soundly rejected PJM proposals to enforce PFR requirements beyond those in Order 842.
The order requires all newly interconnecting generation be capable of providing PFR. But the commission declined to order existing generators to retrofit their facilities to provide the service, saying it would be “prohibitively expensive” for some. (See FERC Finalizes Frequency Response Requirement.) PJM incorporated FERC’s requirement into its interconnection service agreements in October.
With some generators already providing sufficient frequency response, stakeholders said it was unnecessary to force all units to spend money to install the equipment needed to provide the service.
The manual changes detail calculations for high- and low-frequency events, explain when a resource will be evaluated for PFR and how the RTO will respond to resources that fail to perform. PJM will work with generation owners to identify whether the poor performance is because of telemetry, operating scenarios, generator hold points or malfunctioning governors.
Brock Ondayko of American Electric Power noted that FERC’s order did not require scoring of PFR and said PJM had little stakeholder support for it. “To put forward parts of that concept [after the stakeholder rejection] is a bit interesting,” he said.
The manual is scheduled to be brought to an OC endorsement vote at the Feb. 5 meeting.
Unit-specific Parameter Updates due Feb. 28
PJM reminded stakeholders that generating units unable to meet proxy parameters because of operating constraints must submit an adjustment request to unitspecifcpls@pjm.com by Feb. 28.
Unit-specific parameters will be applied to all Capacity Performance, base and fixed resource requirement resources effective June 1, the beginning of delivery year 2019/20.
Approved parameters remain in place unless PJM is notified of a change. Parameters approved and implemented in previous years do not have to be resubmitted.
Parameters affected include turn down ratio, minimum and maximum down time, maximum daily and weekly starts. Adjustment requests will be evaluated by April 15.
Cold Weather Generation Testing Continues to Shrink
PJM will spend only $162,000 to test the winter capabilities of 21 generators totaling 477 MW in 2018.
That’s a fraction of what it spent when it launched the program following the 2014 polar vortex, when up to 22% of the RTO’s generation was unable to operate.
PJM spent $4.9 million to test 168 units representing 9,900 MW before winter 2015. Last year, it paid $1.6 million to test 39 units (3,935 MW).
PJM’s Ray Lee said the decline is a reflection of the transition to CP resources, which are not eligible for testing. All capacity resources will be required to meet CP requirements beginning with delivery year 2020/21.
Lee said it’s unclear whether PJM will continue the program for energy-only generators in the future.
PJM will spend only $162,000 to test the winter capabilities of 21 generators in 2018, a fraction of what it spent when it launched the program following the 2014 polar vortex. | PJM
Black Start Fuel Requirements
The OC held its first meeting last Tuesday on an initiative to develop fuel assurance requirements for black start units.
Members approved a problem statement creating the initiative in July, noting that only 50% of black start units were able to demonstrate fuel assurance through dual-fuel capability, on-site fuel storage or multiple gas pipeline connections.
Although fuel supply capabilities are among the criteria PJM uses in evaluating black start proposals, there is no fuel assurance requirement except that units have enough for 16 hours of run time.
The opening session featured a series of educational presentations by PJM staff and Independent Market Monitor Joe Bowring. The OC will return to the issue following its regular meeting Feb. 5.
The Texas State Capitol, home to the 86 Texas Legislature.
As part of its 2019 Scope of Competition in Electric Markets report to the Texas Legislature, the Public Utility Commission is asking legislators to help provide clarity on whether transmission and distribution utilities (TDUs) can own and operate energy storage devices (Project 48017).
The PUC said that the ownership and deployment of electricity from battery storage devices “has emerged as an issue that would benefit from legislative clarity.”
“I don’t want the state to get behind on the development of batteries into our system,” Commission Chair DeAnn Walker said during an open meeting last month.
The PUC opened a rulemaking on the issue (48023) in January 2018, shortly after it rejected AEP Texas’ request to connect two battery storage facilities in West Texas to the ERCOT grid. (See “PUC Opens Rulemaking on Distributed Battery Storage,” LP&L Finalizing Agreements in ERCOT Move.)
The commission has received 63 responses to its request for comments. The TDUs argued the state’s Public Utilities Regulatory Act permits their ownership or operation of energy storage devices as long as the TDUs don’t sell electricity or participate in the market for electricity (except as a customer). The generators asserted that PURA requires an owner or operator of storage facilities or equipment to register as a power generating company, and that a TDU can’t legally be a utility and a generator.
“One side says PURA is clear, that TDUs can’t own [battery storage]. The other side said PURA is clear, that TDUs can own it,” Walker said during the December open meeting. “I think that speaks to whether PURA is clear.”
The commission appears to be just as divided. Walker found herself siding with some of AEP’s arguments last January, while Commissioner Arthur D’Andrea expressed his concerns over regulated utilities “playing in [the generators’] space.”
The PUC is scheduled to take up the rulemaking during its Jan. 17 open meeting.
The commission’s report will be filed with the 86th Legislature on Monday. The Legislature went into its biennial session Jan. 8 and will finish May 27.
In the report, the commission recommends that the threshold for reviewing mergers and acquisitions of power generation companies be changed from 1% to 10% of installed generation capacity in ERCOT. It doesn’t recommend changing the 20% ownership limit of installed generation capacity.
Other recommendations include:
Requiring retail electric brokers to register with the PUC in a manner similar to retail electric aggregators;
Establishing a collaborative cybersecurity outreach program with utilities; and
Considering a person in default if they don’t respond to a commission’s notice of violation within 20 days.
Energy Consumption Exceeds Expectations
The ERCOT market consumed more than 376 million MWh of power in 2018, a 5.3% increase over the year before, according to the grid operator’s year-end Demand and Energy report.
The final total of 376,357,477 MWh was almost 5 million above the forecast of 370,619,525.
Combined cycle gas units accounted for 38.19% of the energy consumed, with coal-fired generation at 24.78%, wind at 18.55% and nuclear at 10.93%.
ERCOT’s energy use was a dramatic increase from the previous two years, a sign of the state’s booming economy. The market consumed 357,408,316 MWh in 2017 and 351,559,301 MWh in 2016.
Texas added 365,000 jobs in the 12 months that ended in November, and its 3.7% unemployment rate is the lowest on record, according to the Labor Department.
Two years ago I wrote a column: “Electric Cars: Three Ugly Facts.”1
The column showed that electric cars are:
Uneconomic relative to gasoline cars;
Contribute more to global warming than gasoline cars; and
Cause more death and disability than gasoline cars.
All still true today. I included a photo of a 1922 electric car (reprised here) to make the point that electric cars died about a hundred years ago, and they ain’t coming back any time soon (except as niche Veblen goods like Tesla).2
1922 Detroit Model 90 | Detroit Electric
I sent my column to The Wall Street Journal car columnist Dan Neil, who even then was an electric car devotee. No acknowledgement or response. Not that I expected one.
The Band Plays On
It’s timely to reprise this subject because Neil just wrote another fawning piece for electric cars where he claims — without any support whatsoever — that a gasoline car is more expensive than an electric car over a 10-year ownership horizon.3 And that within “the reasonable service life of any vehicle I buy today,” the demand for gasoline cars will be zero. And he trashes the amazing technological improvements of gasoline cars as feeling “junky and compromising.” (I suppose every iPhone enhancement could get such a dissing.)
Irony abounds here because the very next day the WSJ itself ran an editorial arguing that electric cars are very expensive, and the electric car tax credit subsidy is very regressive.4 And that electric cars lose money for their makers and are being made only because of federal and state mandates.
General Motors loses $9,000 on every Chevrolet Bolt. When you lose $9,000 on every electric car, you can’t make it up in volume, especially not on gasoline cars that Neil claims won’t exist anymore.
Paris Agreement
Neil writes that after the Paris climate talks, “most nations of the world have put the IC [internal combustion] vehicle under a death sentence.” This is profoundly false. A mere handful of nations have adopted future — very future — limitations on gasoline cars, and most of those are purely aspirational.5
The reality is this: No nation is going to commit economic harakiri by mandating uneconomic cars for its citizens. Well, except maybe the nation of California.
Piece de Resistance
Now the piece de resistance. Not about electric cars, but electric trucks. Neil extolls a future pickup truck from a company called Rivian that supposedly in two years will be producing an electric pickup with 400-plus miles of range, that will make the gasoline pickup a financial albatross, and that will provide “a wading depth of 3 feet” with which you can go “through the river to grandmother’s house.”
OMG. For starters, Rivian is a company with demonstrated success only in selling investors. Its Wikipedia listing is enlightening.6 Multiple name changes, initial product to be a high MPG (gasoline) car, then autonomous electric vehicles, and now electric pickups.
Rivian R1T (left) and Ford F-150 | Richard Truesdell (left) and Jesus David Piña
The pickup per Rivian’s promotion would provide 400 miles of range at the $100,000 price range.7 In the base model, providing 230 (not 400) miles of range, the promoted base price is $69,000.
Here’s a true-false question for those of you playing the electric vehicle game at home.
The base price of the base Rivian is $30,000 more than the price of a similarly configured Ford F-150:
True.
False.
The correct answer is True. The base Rivian, with 230 miles of range and a base price of $69,000, is $30,000 more than the price of a similarly configured Ford F-150 (same truck bed, four doors, 4×4) of $39,050.
Did I mention that the truck bed length of the Rivian is said to be 55 inches, while the standard truck bed of the F-150 is 78 inches? Last time I checked, pickup owners cared about how much stuff their pickup could carry.
Now, as for the financial albatross assertion about gasoline pickups, it is true that electricity generally costs less on an MPG-equivalent basis than gasoline. But let’s do a little math.
The Ford F-150 gets 20 MPG. The average annual miles for a pickup is 12,000 miles.8 At the current annual average cost of gas, that’s $1,350 for gas per year (12,000 miles divided by 20 MPG times $2.25/gallon).
Neil talks about a 10-year ownership horizon of a purchase. So that’s $1,350/year for gas times 10 years equals $13,500. Let’s see. That’s $13,500 for gas plus the price of the similar Ford F-150 of $39,050 for a total of $52,550.
Compare the F-150 price plus gasoline of $52,550 with the base price of the range-limited Rivian of $69,000, and assume that electricity for the Rivian is free.9
Any questions on the economics — or practicality? Which — just guessing here — matter big time to pickup buyers.
Finally, there’s Neil’s gushing about a future Rivian’s 3-foot wading depth in rivers. Here’s the term for anyone “wading,” aka “floating,”10 in 3 feet of river water: Foolish. Very foolish.
9- BTW, on top of the regressive income tax subsidy, electric vehicles enjoy tax avoidance from not contributing toward our interstate highway system through the gas tax. Another subsidy.
