PG&E Corp. named a new utility chief Tuesday, submitted a broad outline of a bankruptcy reorganization plan and tried to fend off competing proposals during a federal court hearing in San Francisco.
The behemoth bankruptcy of California’s largest utility lumbered forward in the U.S. Bankruptcy Court for the Northern District of California, as pressure mounted to speed up the court proceedings, and stakeholders fought over control of the company and the billions of dollars they hope to win.
Judge Dennis Montali opened Tuesday’s hearing, one of the most significant in the case so far, with a reminder of the thousands of victims of fires sparked by PG&E equipment in the past four years. The company filed for bankruptcy protection in January, after November’s Camp Fire killed 85 people and destroyed most of the town of Paradise, Calif.
San Francisco Bay Area residents remember the smoke that filled the air last fall and the television images of the devastation in Paradise, but “that’s really not much,” Montali said.
“It’s nothing like the nightmares and the horrors that were experienced by all of the victims and their families and their loved ones, and that they are no doubt reliving endlessly,” he said. “And that’s why we’re here. That’s why we’re working in this community, in the bankruptcy world, to deal with one aspect of that tragedy.”
Next, Montali heard lengthy arguments from bondholders and insurance companies over why he should end PG&E’s exclusivity period — the time it has to file its own reorganization plan without the judge considering competing proposals.
Both groups want to make sure they get paid, and perhaps even profit from the process.
Efforts by the California Public Utilities Commission to broker talks among the competing parties broke down, a CPUC lawyer told Montali on Friday. (See Bankruptcy Judge Questions PG&E Exec Compensation.)
A proposal by company bondholders would inject more than $30 billion into PG&E, including about $18.4 billion for fire victims, lawyer Michael Stamer told the judge. Stamer represents an ad hoc committee of senior unsecured noteholders, including banks and mutual funds that collectively hold more than $10 billion in PG&E bonds.
Stamer and others argued for expediency because of recent legislative action. Under Assembly Bill 1054, passed last month, the PUC must approve a bankruptcy plan by June 30, 2020, for PG&E to be able to access a $21 billion fund to pay wildfire claims. (See California PUC Jumps into PG&E Bankruptcy Fray.)
PG&E attorney Stephen Karotkin argued the plan was a way for bondholders to seize control of the company for pennies on the dollar. He urged the judge to give PG&E until Sept. 9 to file its own reorganization plan with the court.
Court papers filed by PG&E on Monday gave a clearer idea of what that plan might entail. It would raise billions of dollars in equity capital to settle wildfire claims and would honor all pre-bankruptcy debts and power purchase agreements.
PG&E’s bankruptcy raised concerns that it would try to reject many of its 387 PPAs worth about $42 billion, especially contracts for solar and wind power. That led to a dispute with FERC about who had authority over the agreements. (See Judge Sides with PG&E over FERC in PPA Dispute.)
Montali took the motions to end exclusivity under submission. He could rule on them as early as Wednesday, when he’s also scheduled to hear arguments over estimates of wildfire damages.
New CEO
Also on Tuesday, PG&E announced its board of directors had appointed Andrew Vesey as president and CEO of its primary subsidiary, utility Pacific Gas and Electric.
Andrew Vesey
Vesey was employed as CEO of AGL Energy, a company based in Sydney, Australia, from 2015 to 2018. AGL has about 3.7 million gas and electric customers and controls around 20% of Australia’s generating capacity, PG&E said in a news release.
Before AGL, Vesey was a longtime executive, including serving as COO for AES.
Vesey starts Aug. 19, according to PG&E. His compensation includes a $1 million annual salary and a $1 million “transition payment,” according to a Securities and Exchange Commission filing. He may also be eligible for roughly $2 million a year in incentive bonuses if Montali approves PG&E’s Key Employee Incentive Plan.
“Andy is a focused and talented leader with the demonstrated experience to help PG&E improve our safety and operational performance, while also being a strong advocate for clean energy solutions,” PG&E Corp. CEO Bill Johnson said in a statement. “We have full confidence in Andy to lead change and deliver results across our safety and operational areas, including electric, gas, generation and customer teams.”
Texas power prices bumped up against the market’s cap as the state registered another day of soaring temperatures and demand on Tuesday, just as ERCOT CEO Bill Magness predicted early in the day.
Addressing the grid operator’s Board of Directors during its regular bimonthly meeting, Magness said, “It’s going to be a tight day on the ERCOT system as we go through the afternoon.”
And indeed it was. With triple-digit temperatures once again driving up the use of air conditioners, ERCOT was forced to call a Level 1 energy emergency alert at 3:12 p.m. — its first such alert since 2014. The grid operator asked for conservation measures as its operating reserves dipped below their 2.3-GW threshold.
Image from ERCOT’s website Tuesday afternoon | ERCOT
The EEA was canceled at 5:02 p.m., but not before demand came close to Monday’s record of 74.5 GW, topping out at 74.2 GW during the interval ending 5 p.m. Still, that broke the 2018 record of 73.5 GW, the sixth time in two days ERCOT has exceeded that mark. Eight of the system’s top 10 highest demand peaks have come since Monday. (See ERCOT Sets New Demand Mark, Smashes ’18 Record.)
Settlement prices hit quadruple digits during the 15-minute interval that ended at 2 p.m. and reached ERCOT’s maximum of $9,000/MWh at 3:45 p.m., staying in that range through the 5 p.m. interval. Monday’s prices had peaked at $6,537.45/MWh.
Day-ahead prices for Tuesday were trading in the $2,600 to $2,700/MWh range, said Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitor.
ERCOT’s website became sluggish during the afternoon as interested visitors watched the lines in a graph depicting capacity and demand nearly touch.
During his presentation to the board, Magness drew attention to a slide in his deck. It noted “warmer” temperatures during the second half of the summer, as opposed to the first half.
“Our expectations for August have advanced quite a bit in the last week,” he said.
Magness exuded confidence in ERCOT’s staff, which knew what was coming this summer. The grid operator had projected peak demand of 74.9 GW.
“If you ask any of the men and women working in the control room today, they’ll tell you this is what we train for,” Magness said. “That circle of support extends beyond the control room … into every part of ERCOT. This is what we train for; this is what we do; this is the service we’re supposed to provide. So let’s have it.”
After the meeting, ERCOT called on consumers and businesses to reduce their energy use through 7 p.m.
The Public Utility Commission of Texas also issued a press release calling for conservation, suggesting consumers make a few “simple choices” by raising their thermostats a couple of degrees, reducing lighting and using heavy appliances after sunset.
“When the energy demands of our state’s steadily growing population and booming economy intersect with hot summer temperatures, the supply of power can get a little tight,” PUC Chair DeAnn Walker said in the release.
ERCOT sent out a market notice Tuesday morning, alerting participants that the Texas Commission on Environmental Quality (TCEQ) will “exercise its enforcement discretion for exceedances of emission and operational limits of power generating facilities” should the generators exceed air-permit limits.
Generating facilities expecting to exceed their limits were directed to notify the TCEQ, and ERCOT said it would notify market participants when the agency’s “enforcement discretion” ends.
John Hall, the Environmental Defense Fund’s state director of regulatory and legislative affairs, suggested other alternatives to increased generation.
“While this may look like a zero-sum game, it doesn’t have to be,” Hall told RTO Insider. “Policymakers have a suite of tools — such as energy efficiency and demand response — to avoid the false choice between Texans’ air quality and a reliable grid.”
Ohio Attorney General Dave Yost on Monday rejected a draft petition to repeal the state’s nuclear subsidy program via ballot referendum, but the disgruntled parties behind the measure say they aren’t discouraged.
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts, told RTO Insider the development doesn’t change the group’s ultimate goal: overturning House Bill 6 in the November 2020 election.
Ohio Attorney General Dave Yost | Dave Yost
“We have a plan to get the signatures that we need, and we’ve been lining up the resources that we need to make this happen,” he said. “We are confident that we can make the deadlines to get on the ballot next year.”
The 90-day countdown to get the ballot petition approved began July 23, when Gov. Mike DeWine signed the Ohio Clean Air Act into law. The act replaces the state’s renewable energy mandates with ratepayer surcharges to support FirstEnergy Solutions’ Davis-Besse and Perry nuclear plants and two Ohio Valley Electric Corp. (OVEC) coal plants. (See Ohio Approves Nuke Subsidy.)
The controversial law makes Ohio the third state in Monitor: PJM Markets Remain ‘Under Attack’.) Supporters say keeping the reactors operating will reduce carbon emissions — a primary target of clean energy bills across the country — and provide around-the-clock reliability to support the intermittency of solar and wind power.
Pierce’s group argues the law amounts to a “corporate bailout” that wastes money on less efficient resources at the expense of continuing to expand Ohio’s renewable energy portfolio. And they’ve got some powerful, if not unlikely, allies on their side: the natural gas industry, independent power producers, environmental activists and clean energy groups.
“The bottom line is we will take the attorney general’s suggestions and critiques and work very quickly to provide another draft as soon as possible and hope that we can solve these issues very quickly,” Pierce said.The group filed its revised petition Friday and said the state has 10 business days to certify the draft.
Yost highlighted 21 errors in the petition summary that prevented him from certifying the document as “a fair and truthful statement of the measure to be referred.” The inaccuracies relate to misstated definitions for “electric distribution utility” and “renewable credits,” among other terms, as well as missteps in the way petitioners described the responsibilities, calculations and procedures detailed in the law itself.
“It’s not atypical for a first draft of a petition on a complicated bill like this one was to need some corrections,” Pierce said. “We are still on plan. We know how many signatures we have to get and we know how much time it takes to get them.”
ClearView Energy Partners agrees with Pierce’s cautious optimism, noting that while the 21 errors seem a bit excessive, Yost has rejected four of the last 10 petition drafts submitted to his office. Three of those drafts were subsequently approved upon resubmission — an outcome the analysts believe is likely in this case too, given that Yost expressed no opposition to the petition’s merits.
Timing also appears key for the group, the analysts said. With a broad coalition of allies, the “corporate bailout” narrative and the act’s structure itself — ratepayers won’t see those monthly surcharges until 2021 — ClearView suggests that a ballot referendum could succeed, overturning the subsidies before FirstEnergy and OVEC collect a single penny.
Pierce told RTO Insider that his group will disclose its financial supporters as required by Ohio campaign finance law.
“Until then, I can say that you will find that they are many of the same groups and individuals who testified against the bill in the legislative debate over the bill,” he said.
If the revised petition is approved, Pierce’s group will then begin collecting the roughly 265,000 signatures ahead of the Oct. 21 deadline for inclusion on the ballot next year.
DES MOINES, Iowa — MISO and SPP are making earnest efforts to coordinate transmission development along their shared seam, but much more remains to be done to manage an impending influx of renewable resources, regulators and industry participants said Monday.
And time is of the essence for making needed changes, according to some of the experts participating on a panel devoted to addressing shortcomings in the MISO-SPP interregional process at this year’s Mid-America Regulatory Conference (MARC).
The panel marked the first time that MISO and SPP representatives appeared together on a stage to express support the creation of a smaller, interregional project category such as the MISO-MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)
MISO Director of Seams Coordination Jeremiah Doner said that MISO-SPP interregional projects — currently elusive — will become essential as more variable generation comes online. A larger transmission network is more beneficial because it can draw on more types of resources to firm up supply, he said.
“The bigger region you have to manage, that need for flexibility is going to be key,” Doner said.
MISO is eager to begin working with SPP to create a TMEP project template, he said.
“We don’t just want to take [the] PJM [TMEP model] and copy and paste it,” Doner said, although he added MISO has gained valuable experience through two rounds of TMEPs with its eastern neighbor.
SPP Director of Seams and Market Design David Kelley said his RTO would also like to develop something akin to TMEPs with MISO.
“We’ve seen the success between PJM and MISO. We’re very interested in getting a process like that in place,” Kelley said, adding that the idea must still be advanced through MISO’s and SPP’s separate stakeholder processes.
Missouri Public Service Commissioner Daniel Hall spoke about the recent endorsement by the Organization of MISO States and the SPP Regional State Committee to engage the RTOs’ monitors to conduct joint studies on seams issues. (See RSC, OMS Approve Monitors’ Seams Study.)
“There was a growing problem, and the problem is two RTOs run their grids independent of one another,” Hall said in explaining the need for the effort. “There are fundamental differences between MISO’s and SPP’s management styles: On the MISO side it’s, ‘If it’s built, use it.’ On the SPP side, it’s, ‘If it’s ours, you pay us.’”
Hall also noted that the RTOs’ executives don’t always agree: “I think those philosophical differences get overplayed, but they still exist.”
Neither OMS nor the RSC are under any illusion that they can force the RTOs to adopt new interregional planning processes, he said.
Invenergy Director of Regulatory Affairs Nicole Luckey said the RTOs’ current process is encumbered by voltage and cost thresholds that are no longer appropriate and an interregional planning approach that has “too many cooks in the kitchen,” preventing cross-border transmission projects that could deliver low-cost wind energy.
“We have a [joint operating agreement] that’s way too prescriptive,” she said. “If I were a regulator, I would be pissed that my customers weren’t getting access to the lowest-cost generation in the country.”
However, Luckey also acknowledged MISO’s recent failed proposal to lower voltages on interregional projects to 230 kV for regional cost allocation, calling the filing a good start. (See MISO Allocation Plan Fails on Local Project Treatment.)
“I do think we’re much too prescriptive in what we look at” for projects, Kelley allowed. He said simply sizing up projects based on adjusted production costs makes less sense as the marginal cost of renewable energy approaches zero.
Kelley expressed hope about changes, saying SPP would work to identify and remove barriers. But he also contended the two RTOs were unlikely to reach total transmission planning consensus without a national energy policy and “leadership on a national scale.”
“And I would argue we’d all be dead before we get federal energy policy,” Luckey said.
Hall said it’s not well understood that the cost of congestion on RTO seams is socialized among ratepayers situated far from those seams.
“Even if you’re not on a seam, your ratepayers are paying for congestion. … That has to be acknowledged,” Hall told attendees. “The more [efficiently] the entire grid works, it serves as a benefit. It’s not just a function of bringing cheap energy to market; it’s moving it around in the most efficient way.”
“You can’t look at just whether your state is going to benefit,” Luckey told regulators.
Hall said the dearth of interregional projects is best illustrated by Ameren Missouri’s proposed northwest Missouri wind farm, which originally had a $10 million interconnection price tag that later escalated to $40 million because of needed transmission upgrades. Ameren recently scrapped plans for the 157-MW project because of sticker shock.
“And the reason was all of the congestion in the area,” Hall said. He said the Ameren wind farm was a “poster child” for the lack of interregional transmission planning.
“We cannot build transmission plans interconnection upgrade by interconnection upgrade,” Hall said.
MISO and SPP have so far undertaken three 18-month coordinated system plan (CSP) studies — in 2014, 2016 and 2019. The first two CSPs failed to identify a worthwhile interregional seams project, and early indications are that the most recent hasn’t identified a contender either. The 2019 CSP relied on only the RTOs’ respective regional models, removing the additional joint model.
“I’m going to take a little shot at MISO, but I warned Jeremiah [Doner], so he knows it’s coming,” Luckey said before criticizing what she called the RTO’s “old, stale” planning assumptions in its annual Transmission Expansion Plan (MTEP). MISO is dramatically underestimating the amount of renewable penetration in its four future scenarios used to inform MTEP, she contended, especially considering carbon-reduction pledges by Midwestern utilities.
“No comment,” Doner joked, although he addressed the criticism by noting MISO is seeking to rework its futures for the 2021 MTEP cycle.
Luckey said “massive” energy infrastructure upgrades are needed, and they can’t wait until MISO can “perfectly forecast” renewable penetration.
DES MOINES, Iowa — The Mid-America Regulatory Conference (MARC) opened Monday with a study in local Iowa flavor and a grab bag of industry opinions gleaned from a round of questions styled after political interrogations in the spirit of state’s caucus activity.
Katie Greenstein, a chemist with Des Moines Water Works, opened the conference with a trumpet rendition of the national anthem.
“Fun fact about Iowa: We have more pigs than people,” Iowa Utilities Board Member Nick Wagner said in a welcome speech.
In lieu of speaker gifts, the event boasted corn kernel voting for four Iowa charities, similar to the Iowa State Fair’s famous polling for primary candidates. Wagner said all the charities would receive some level of donation.
Des Moines Mayor Frank Cownie regaled attendees with Saturday scenes from the fair, which not only boasted several presidential candidates but also Des Moines heavy-metal band Slipknot, along with their fan base, dubbed the “maggots.”
MARC also named Michigan Public Service Commissioner Dan Scripps its new president during the opening.
Lightning Round
With thunderstorms passing over the State Capitol, the first session of the conference was — aptly enough — a “lightning round,” in which Arkansas Public Service Commission Chairman Ted Thomas fired rapid questions at 14 industry players.
SPP General Counsel Paul Suskie fielded the first question, responding that, yes, the U.S. needs a singular energy policy, instead of a patchwork of subsidies. Suskie, a veteran of the wars in both Iraq and Afghanistan, also said national energy policy should consider the effects on other countries, referring specifically to oil impacts in the Middle East.
“I don’t know where those numbers are coming from,” Susan Williams Sloan, vice president of state affairs for the American Wind Energy Association, said in challenging an assertion by American Coalition for Clean Coal Electricity CEO Michelle Bloodworth that coal generation remains cheaper than bringing new wind resources online.
After that, Thomas jokingly asked panelists to cite research, if they could, within the time constraints.
Former FERC Commissioner Colette Honorable, now a partner with law firm Reed Smith, used her brief time to praise co-located resources — combinations of electric storage with either solar or wind generation — for its job-creating potential. However, she later noted she thought the industry was taking nuclear generation for granted for its reliability and zero-carbon attributes.
MidAmerican Energy CEO Adam Wright pointed out that his company raised rates one time in Iowa in 1999 and didn’t plan to raise rates again until about 2030, owing to steady coal and natural gas generation.
Wright also stressed the pressing need for cybersecurity, saying much of the onus was on employee vigilance because humans remain “surprisingly fallible.”
“We have employees pull an email out of the quarantine [folder] — and it’s got a warning on it — open it, say ‘OK’ to giving their passwords … and then they call the security desk to ask about [the email]. And they’re told, no, don’t do that, and the employee hangs up,” Wright said. “It’s insanity.”
He added that while it would be great if regulators greenlit cost recovery for utility cybersecurity, it remains a company responsibility to keep systems safe.
Thomas pivoted: “How about Order 1000? Is it working?”
“No,” ITC Senior Vice President Krista Tanner replied. “It’s created another level of bureaucracy and created hinderances where none existed before.”
Suskie also thought the promises of Order 1000 remain largely unfulfilled.
“We had one competitive project. … It went to the incumbent. The competitive component of competition is not working,” he said, also pointing to the litigation surrounding Texas’ recently passed right-of-first-refusal law and MISO’s Hartburg-Sabine project in that state. (See NextEra Takes Texas to Court over ROFR Law.)
When talk turned to China’s ever-increasing coal production, Honorable said the U.S. shouldn’t take that as permission to continue its own coal use.
“We can’t just say, ‘Oh they’re horrible, so we can be a little bad,’” Honorable said, adding that she was glad to see stepped-up carbon-reduction pledges from companies following the Trump administration’s withdrawal from the Paris Agreement on climate change.
New England utility regulators have gained a key ally in their call for an initiative to explore how the region’s wholesale energy market could be reshaped to accommodate the growth of state-sponsored resources.
The New England States Committee on Electricity (NESCOE) last month askedISO-NE to “dedicate market development and planning resources” next year to support states and stakeholders “in analyzing and discussing potential future market frameworks” compatible with the state energy and environmental laws that could alter the region’s resource mix.
The New England Power Generators Association (NEPGA) wholeheartedly agrees. In a letter to ISO-NE Tuesday, NEPGA President Dan Dolan said his group “strongly supports” NESCOE’s request to kick off the discussion and emphasized “the need to ensure that the future wholesale electricity market design preserves electric reliability, resource adequacy and other needed services in a robust competitive, market-based manner.”
NESCOE’s July memo noted New England adopted a wholesale market in the 1990s to ensure “market dynamics rather than regulatory orders” set electricity prices and to shift the risks of generation investment decisions from ratepayers to investors.
But the energy landscape has shifted drastically since then, with New England states boosting their renewable portfolio standards and mandating large solicitations of offshore wind. As a result, state-sponsored resources are expected to comprise more than half the generation participating in the ISO-NE market by 2027.
State-sponsored resources are expected to represent more than half the generation participating in the ISO-NE market by 2027. | NEPGA
NESCOE said the increasing reliance on resource procurements outside the ISO-NE market “make a conversation about the objectives of the wholesale markets, and what we are collectively asking it to do, sensible.”
NEPGA’s Aug. 13 letter says NESCOE’s request is similar to one NEPGA made last December, when it warned the RTO’s board of directors the region is “fast approaching a tipping point” as an increasing volume of state policy resources participating in the wholesale market leave competitive generators unable to recover their costs, putting them at risk of early retirement and forcing ISO-NE to rely on out-of-market mechanisms to keep vital resources online. (See FERC Approves Mystic Cost-of-Service Agreement.)
NEPGA said it was “unconvinced” by the board’s response to its letter: that ISO-NE would address the group’s concerns through its ongoing “energy security improvements” effort. (See ISO-NE Filing, Whitepaper Address Energy Security.)
“With the benefit of several months review of the ISO proposals and in light of the intention that such revenues would be considered a reduction to de-list bid offers, NEPGA remains unconvinced that [the energy security efforts] address the fundamental concerns of a lack of future competitive revenue opportunities for resources that provide reliability services,” Dolan said in the letter.
NEPGA suggested any discussions on market changes take place within the New England Power Pool (NEPOOL) committee process, which “would provide an important measure of structure and diligence to these efforts which, given their likely complexity, will require deliberate and long-term discussions and consideration in order to be fruitful.”
Dolan said the NEPOOL process would also foster “meaningful engagement on the paramount question of how to preserve and reinforce competitively produced reliability services in the region.”
The generator group said it agrees with NESCOE that initial meetings should be devoted to “certain threshold questions,” including “an agreement as to the scope of future efforts related to potential improvement to existing markets or even consideration of new competitive market designs.” NEPGA said it believes any problem statement should focus on maintaining ISO-NE’s “core function” of using competitive markets to ensure reliability and resource adequacy
“Articulation of this ‘problem statement’ is critical to the commitment to priority use of ISO-NE and stakeholder resources for these purposes,” Dolan said. “NEPGA offers that this should be completed prior to embarking on the deliberative process to analyze and discuss potential market design enhancements.”
NEPGA asked that ISO-NE work with NEPOOL and NESCOE to schedule a NEPOOL committee meeting in early 2020, adding that NEPOOL sectors and states should come to the meeting equipped with their own problem statements.
“This is a critical moment for the ISO, states & all invested stakeholders in New England to chart the path forward in a dramatically changing market. Just as NEPGA said nearly a year ago, if we’re going to have agency in our future, we must act — quickly!” NEPGA tweeted Wednesday.
SPP and MISO will hold a conference call Aug. 19 to discuss their interregional process and joint projects — of which there are currently none.
The RTOs’ staffs have already shared potential interregional solutions in their coordinated system plan study, having shortlisted seven projects, none of which have met the 5% minimum benefit threshold for each grid operator.
“But that’s not indicative that the process is flawed,” Adam Bell, the RTO’s interregional coordinator, told the Seams Steering Committee on Wednesday. “We would have ended up in the same place where we are now [with the previous process], after months and months of work to build the joint model.”
SPP and MISO have yet to agree on any interregional projects across their shared seam. | SPP
SPP and MISO have replaced the cumbersome joint model process by instead using their regional processes. Their inability to agree on a single joint project in three attempts has drawn increasing attention from state regulators in their areas. (See MISO-SPP Interregional Process Scrutinized at MARC.)
Bell said Monday’s Interregional Planning Stakeholder Advisory Committee call with MISO will not be without its benefits.
“We’ll have a discussion with MISO in the room about where it makes sense to go from here,” he said.
MISO Earns Positive M2M Settlement
Staff’s market-to-market (M2M) settlement report for June indicated MISO incurred nearly $2.4 million in payments from SPP, the ISO’s first positive month since last October.
June M2M Update | SPP
M2M payments typically flow in MISO’s favor during the summer months. Still, SPP has racked up $63.7 million in distributions since the two seams neighbors began the process in March 2015.
Temporary flowgates accounted for most of the M2M settlements, binding for 675 hours. That resulted in $2.3 million in settlements from SPP to MISO.
VALLEY FORGE, Pa. — PJM staff told the Market Implementation Committee on Wednesday that they will not file waivers for upcoming capacity auction deadlines and will instead rely on FERC to issue an order on its minimum offer price rule (MOPR) before the end of the year.
Pat Bruno, senior engineer for PJM’s capacity market operations, said it’s unlikely the commission would respond in time even if staff submitted a waiver for the upcoming Sept. 1 deadline in the 2023/24 Base Residual Auction. The next round of deadlines comes in December, he said, at which point FERC will have “hopefully” issued a ruling.
Last month, FERC halted the 2022/23 capacity auction scheduled for this month, refusing to “rule prematurely” on PJM’s request for clarification that if it ran the BRA using the existing MOPR that the commission would also agree to enforce any new rates prospectively, saving the auction from being rerun (EL16-49).
The last-minute directive from FERC came just hours after PJM staff told the Markets and Reliability Committee they would move ahead with the auction as planned. The RTO confirmed it would comply with FERC’s guidance — though it was the commissioners themselves who expressed frustration about their role in creating market uncertainty for participants. (See FERC Halts PJM Capacity Auction.)
‘Winter is Coming’ … Along with Gas Contingency Plan (Hopefully)
Thomas DeVita, senior counsel for PJM, told stakeholders that staff are preparing to file a revised gas contingency proposal with FERC by October, with hopes that the commission will give its approval by December.
“Winter is coming,” he warned repeatedly, reiterating stakeholder concerns about surviving a third cold weather season without a cost recovery plan for generators forced to switch fuel supplies at PJM’s discretion.
On Feb. 19, FERC rejected the member-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or fuel source because of pipeline breaks or the loss of compressor stations (ER19-664). The proposal included nine categories of switching costs, such as park-and-loan service charges and overrun charges. (See FERC Rejects PJM’s Gas Pipeline Contingency Proposal.) The commission also argued that the conditions for switching belong in the Tariff — not just business manuals — and gave PJM a chance to revise the proposal over the spring and summer.
DeVita said FERC staff dropped some hints about how to tweak the filing for better success the second time around. (See PJM Revisits Gas Pipeline Contingency Plan.) He said staff discouraged the RTO from submitting an itemized list of switching costs, as it did in the first filing, and instead focused on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs.
In the draft language presented Wednesday, staff added “pre- or post-contingency” into the switching process triggered by a manual load dump and removed a requirement that generators must have documentation of unauthorized switching costs before filing for cost recovery at FERC. A reference to opt-in and opt-out intraday offers was also removed.
Staff also added the following paragraph to the proposal, meant to ease members’ concerns about the vague definition of switching costs: “PJM will commit to analyze, assess and address through a stakeholder process whether adequate compensation exists for any future operating instructions associated with gas switching that fall outside of the criteria established in this Tariff filing. Such analysis will also consider the mechanisms through which such compensation shall be obtained.”
Independent Market Monitor Joe Bowring asked DeVita whether PJM’s proposed language would permit companies to include the cost of penalty gas in their offers and therefore charge customers for the much higher cost of power that would result. Bowring pointed out that if the pipeline approved the use of the gas, it should not be treated as penalty gas. PJM indicated that the issue needed to be clarified.
Bowring also noted that the gas contingency procedures did not have a clear requirement that PJM take other emergency actions prior to the contingency, including calling on demand-side resources.
DeVita said the language is on track for endorsement at the September MIC and MRC meetings, with filing scheduled for Oct. 15.
Opportunity Cost Calculator Vote Delayed
Stakeholders delayed votes on several options for a more unified opportunity cost calculator after confusion over the implications of proposed changes left many unsure of how to move forward — if at all.
Bob O’Connell, executive director of regulatory affairs and compliance for Panda Power Funds, sponsored a motion to vote on three packages, drafted in consultation with Dominion Energy, that would streamline PJM’s calculator to varying degrees. (See PJM Stakeholders Push Unified Opportunity Cost Calculator.)
During a first read of the plans last month, O’Connell said the first package makes small changes that don’t force PJM to rewrite its calculator. The second revises PJM’s modeling process to mimic the Monitor’s, which many stakeholders prefer for its reliability. The third consolidates the former package into one single calculator, “eliminating all compliance risk,” O’Connell said.
Under current procedure, market participants can either use PJM’s calculator in Markets Gateway or the Monitor’s modeling system to build energy cost offers with appropriate adders that help ensure a generator will recoup opportunity costs when its resources have limited run hours for environmental reasons and are scheduled outside of their most economic operating intervals. Some of these opportunity costs arise when regulatory agencies impose environmental run-hour restrictions, physical equipment limitations trigger operational restrictions and force majeure events constrain access to fuel.
The problem for O’Connell and other stakeholders, however, is the riskiness associated with PJM’s calculator, which is designed to give market participants more control over submitted data and, therefore, more opportunity for operator error. PJM staff said the majority of stakeholders — perhaps up to 98% — use the Monitor’s calculator already, with just two choosing to use the RTO’s within the last year.
“When I look at the Market Monitor’s calculator, I view that as very little compliance risk,” O’Connell said. “The only issues we have are — are we being honest and forthright with the information we provide to the Market Monitor, and did we copy and paste correctly? From my [compliance] perspective, something like the IMM’s calculator is preferable.”
Glen Boyle, manager in PJM operations analysis and compliance, pushed back against the simplified explanation of the Panda/Dominion proposals, noting that the calculator changes being suggested raise “serious concerns” — including those that would set aside hours from the performance assessment interval.
“There’s already a process in [PJM Manual 13] where if you start to run out hours, you can put those remaining into max emergency,” he said. “FERC was very clear in its order on opportunity costs. Only things related to environmental, insurance carrier and [original equipment manufacturing] should be in the calculator. We agree with that, and some of these things shouldn’t be included.”
O’Connell said the changes deserved further consideration.
“If you look at the situation right now, there’s sort of a disconnect between actions a company takes to put a resource into max emergency versus assumptions that are made in the capacity market,” he said. “This serves to link them more closely. … [It’s] an expectation [of] how market participants should behave with respect to a decision that they are getting down to too few hours. Really, the status quo lacks that linkage.”
He did, however, agree that the goal of “getting to one calculator” took priority over approving changes and agreed to drop those elements from the third proposal in the interest of moving forward — prompting Bowring to question the necessity of voting on a plan that appears to require PJM to make its calculator mirror the Monitor’s.
“If the point is to force PJM to create a calculator exactly like ours, then I believe that’s a demonstrable waste of time and money,” he said. “It seems to me you have what you want here.”
O’Connell agreed that there was no reason to force PJM to spend money to modify their calculator and that the Monitor’s calculator addressed the requirements of members.
MIC Chair Lisa Morelli suggested delaying the votes until the September meeting so that stakeholders could take more time to review the changes contained within.
Modeling Units with Stability Limitations
Stakeholders unanimously endorsed a problem statement and issue charge from Panda that address concerns over proposed revisions to Manual 10 that would require generators to use outage tickets for stability-related limitations, possibly encouraging price distortion. (See “Generation Outage Revisions Delayed,” PJM OC Briefs: May 14, 2019.)
O’Connell told the MIC last month that PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. (See “Modeling Units with Stability Limitations,” PJM MRC Briefs: July 10, 2019.) Under the RTO’s rules, only the affected generator would know of the constraint, O’Connell said, therefore gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers.
As a solution, O’Connell suggested PJM implement a closed-loop interface around the affected resource that restricts the output to below the stated stability limit — and that it must be used in each of the RTO’s markets. He also encouraged PJM to publicize stability limits on OASIS prior to contacting the affected generator.
The MIC will work on possible solutions during the committee’s meetings over the next few months.
Price Formation
The MIC continues its review of how prices are formed every five minutes in PJM based on a problem statement and issue charge created by the Monitor and approved by the MIC in June.
Catherine Tyler of IMM Monitoring Analytics provided education on the relationship between the megawatt dispatch and price signals sent to generators by PJM systems for each five-minute interval. Tyler explained that the signals should be for the same point in time but are not. She said the practice is inconsistent with basic economic logic and creates incentive issues for generating units that are given price signals inconsistent with dispatch signals and are paid in a manner that does not match their dispatch instructions. This is the case for both energy and reserves.
Manual Revisions Endorsed
The MIC endorsed the following revisions to PJM manuals:
Manual 11 (Energy & Ancillary Services Market Operations): Revisions will document procedures for addressing missing historical performance scores in the regulation market and also clarify that the reserve requirements used in the market clearing process are based on the potential largest single contingencies that are communicated by PJM operations and modeled in the markets clearing software. Scheduled for MRC first read later this month and endorsement in September.
Manual 18B (Energy Efficiency Management & Verification): Updates to conform with Tariff revisions that detail energy efficiency rules issued by authorized relevant electric retail regulatory authorities and those dealing with seasonal capacity resources.
Manual 27 (Open Access Transmission Tariff Accounting and Manual 28 – Operating Agreement Accounting): Revisions include language to comply with electric storage participation mandates from FERC Order 841-A.
VALLEY FORGE, Pa. — PJM staff on Thursday unveiled to the Planning Committee a proposed new fee structure for a more involved cost-containment process.
The proposal suggests charging a $5,000 nonrefundable flat fee to all developers who submit competitive projects. Itemized study costs will be added as necessary. Mark Sims, PJM’s manager of infrastructure coordination, said the intent is to bill projects that incur the extra expense. Late payment and nonpayment conditions have yet to be determined.
Sims previously told the PC that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: June 13, 2019.)
Sims said PJM will host a special PC workshop on Aug. 29 to discuss this structure in more detail, which will eventually be added to Manual 14F.
Cost Allocation Dispute Leaves Tariff Changes in Limbo
PJM staff said required Tariff changes covering cost allocation for transmission projects remain in limbo as the RTO waits on FERC to respond to a motion to address a remand related to the issue.
Pauline Foley, PJM’s associate general counsel, said transmission owners made the motion after the D.C. Circuit Court of Appeals “set aside” a 2016 FERC ruling that allowed transmission projects driven by local planning criteria to be exempt from competitive bidding. (See FERC Sides with Incumbent TOs; OKs Limits on Competition.)
On clarification, the court, citing its original opinion, said it held “‘only that FERC did not adequately justify its approval of the [Tariff] amendment at issue.’ Nothing in the opinion prevents FERC on remand from attempting to ‘provide a better justification for its approval of the Tariff amendment.’”
Petitioners Old Dominion Electric Cooperative and Dominion Energy filed motions for an order on remand arguing that the court’s decisions leave no doubt that the 50/50 cost allocation for regional facilities is in effect pending further action by FERC. LS Power commented that it is appropriate for the commission to bring the matter to an end.
FirstEnergy, Dominion Solutions
Dominion proposed the following solutions for several proposed supplemental projects in Virginia:
Cut an existing 230-kV line between Roundtable and Buttermilk substations. Construct a 1.8-mile, 230-kV loop to Lockridge substation. At Lockridge, install four 230-kV breakers to terminate the two lines. Install two 230-kV circuit switchers and any necessary high-side switches and bus work for two initial transformers (five ultimate). Cost estimate is $35 million and in-service date is July 31, 2022.
Install a 1,200-amp, 50-kAIC circuit switcher and associated equipment (bus, switches, relaying, etc.) to feed the new transformer from the existing 230-kV bus No. 5 at Beaumeade. Cost estimate is $750,000, and in-service date is March 31, 2020.
Re-conductor Cochran Mill-Ashburn 230-kV and Ashburn-Beaumeade 230-kV line segments using a higher capacity conductor, as well as upgrade the terminal equipment to achieve a rating of 1,572 MVA. Cost is $15 million and in-service date is June 1, 2023.
FirstEnergy solutions for Pennsylvania projects include:
Replace line trap and substation conductor at the Shawville 230-kV substation and replace line relaying, line trap and substation conductor at the Shingletown 230-kV substation. Cost is estimated at $900,000 with an in-service date of Dec. 1, 2020.
Replace line relaying, line trap and substation conductor at Elko-Shawville 230-kV Line 546/666 and Elko 230-kV substation. Replace line relaying and line trap at Shawville 230-kV substation. Estimated cost $1.3 million, with an in-service date of June 15, 2020.
Replace the Homer City North 345/230/23-kV transformer and associated equipment with 345/230/23-kV, 336/448/560-MVA transformer. Estimated cost is $6.6 million, and in-service date is Dec. 31, 2021.
Rebuild and reconductor approximately 33 miles of wood pole construction for the Armstrong-Homer City 345-kV line. Estimated cost of $138 million and in-service date of Dec. 31, 2023.
The Texas Public Utility Commission last week asked for more information on eight small municipal utilities’ appeal of ERCOT’s definition of transmission operator (TO) (48366).
The PUC directed the State Office of Administrative Hearings to return ERCOT’s order to the commission so that it could solicit feedback from stakeholders in a docket. Given legal briefs and other information, the commission would then be able to dismiss the ruling and open a rulemaking or project.
PUC staffer Stephen Journeay offers advice to the commission.
The Small Public Power Group (SPPG) — composed of utilities for the cities of Bartlett, Bridgeport, Farmersville, Goldsmith, Hearne, Robstown, Sanger and Seymour — is appealing the ERCOT Board of Directors’ 2018 rejection of a proposed change to the Nodal Operating Guide (NOGRR149).
“We will, of course, provide comments on the questions the commission [poses] and look forward to the discussion that follows,” Clark Hill Strasburger’s Tom Anson, legal counsel for SPPG, told RTO Insider.
The NOG requires every transmission or distribution service provider in ERCOT to either register as a TO or designate a representative on its behalf. The TOs communicate with ERCOT during emergency events and the management of load-shed activities, among other responsibilities.
NOGRR149 would have exempted municipal distribution service providers without transmission or generation facilities from having to procure designated TO services from a third-party provider if their annual peak load is less than 25 MW. SPPG developed the revision request in 2015 to settle the noncompliant status of six municipally owned utilities with loads of 9 to 21 MW. Goldsmith and Bartlett joined the proceeding later. The Technical Advisory Committee and its Reliability and Operations Subcommittee also rejected the change. (See “Small Public Power Group’s Appeal Again Meets Defeat,” ERCOT Board of Directors Briefs: April 10, 2018.)
Transmission and distribution operators AEP Texas and Oncor are the only two intervenors.
“When I looked at the docket and who intervened, I was shocked there were only the two intervenors,” PUC Chair DeAnn Walker said during the commission’s open meeting Thursday. “This has been a hard-fought issue at ERCOT where a lot of people put stakes in the ground, and they’re not putting them here, and I don’t understand why.”
“This commission can operate better in a project when we can hear from all the stakeholders and ask them questions,” Commissioner Arthur D’Andrea said during the commission’s debate over how to proceed.
The SPPG says its proposal would conform operating guides to the “existing factual situation.” None of the SPPG members is or ever has been in the ERCOT load-shed table, the group said, and the revision would not “in any way, affect the reliability of the ERCOT system.”
“Several SPPG members are so small, they are physically limited in their ability to comply with the relevant ERCOT requirements,” according to the group’s filing.
ERCOT has asked that the PUC deny the appeal because SPPG “has not demonstrated any legal basis for reversing the [board’s] decision to reject NOGRR149” and because it has not alleged “any credible violation of law.”
Walker said she wanted to ensure the commission was protecting its oversight of ERCOT.
“There are policy decisions made at the ERCOT board we don’t agree with. I believe we still have the authority to set that policy and the obligation to set that policy,” she said. “I don’t want to take away our oversight of those policy decisions.”
Walker Warns SPP Recs Could Raise Tx Costs
Walker briefed D’Andrea and Commissioner Shelly Botkin on the SPP Regional State Committee’s recent discussions and disagreements over the Holistic Integrated Tariff Team’s (HITT) recommendations. The RTO’s Board of Directors approved the 21 recommendations, despite some minor pushback. (See SPP Board Approves HITT’s Recommendation.)
Calling the conversations at the RSC “a whole lot of mess,” Walker said the three recommendations assigned to the committee will affect Texas because of changes to cost-allocation methodologies. The committee has until next July to:
propose how to decouple two transmission pricing zones under SPP’s Tariff, creating new, larger zones in one, and smaller sub-zones in the other;
evaluate the byway facility cost-allocation review process; and
charter a study of the generator injection rate (based on energy produced by resources without network or point-to-point service).
“While most of the utilities here [in Texas] support the decoupling, how those zones would [be] set up is important,” said Walker, the lone RSC member to vote against the HITT proposals. “Almost every recommendation I have seen has Texas paying more.”
Noting the HITT study was pushed by utilities in wind-rich areas concerned that their transmission spending was benefiting customers elsewhere, Walker said, “We’re not wind rich. We’re just under wind rich.”
“My concern is we end up at the end of the day with everyone else getting what they wanted and us needing to make a fight at FERC,” she said.
D’Andrea, who sits on Organization of MISO States’ board of directors, said some of the same discussions are being held there. OMS is currently working on long-term transmission planning principles, he said. “That conversation is almost impossible to have without cost allocation,” D’Andrea said.
SPS to Refund $14.5M in Fuel Costs
The PUC signed off on Southwestern Public Service’s request to refund its Texas retail customers $14.5 million for over-collected fuel costs from January 2016 through May 2018. SPS reached a unanimous settlement with commission staff, Texas Industrial Energy Consumers (TIEC) and the Alliance of Xcel Municipalities (AXM) (48718).
SPS has a separate docket before the PUC, in which it has asked permission to replace its two seasonal formulas used to determine its fuel factors with a single formula (49616).
The company said the move is necessary because its new 478-MW Hale Wind Project has changed its resource mix and because SPP’s market has affected its system-average fuel and purchased power costs. The new formula will ensure the wind facility’s benefits are passed on to customers “timely,” SPS said.
TIEC, AXM and the Office of Public Utility Counsel have intervened in the proceeding.
Residential customers will see about a 3.25% increase on their bill from June through September, or about $3.73/month for those using 1,000 kWh/month of electricity, the company said.
Broker Registration Forms OK’d
The commission approved electric broker registration forms to comply with Senate Bill 1497, which requires representatives paid for brokerage services to register with the state (49711).
The bill goes into effect Sept. 1. The PUC will maintain a list of registered brokers on its website.
Thoughts, Prayers for El Paso Victims
Chair DeAnn Walker shares the PUC’s thoughts and prayers for El Paso Electric employees affected by the Aug. 3 mass shooting.
Walker opened the meeting by extending thoughts and prayers on behalf of the commission to three El Paso Electric employees who she said had family involved in the city’s deadly Aug. 3 shooting. She said one of the employees lost their mother.
