American Electric Power’s third-quarter figures beat expectations with earnings of $734 million ($1.49/share), up from $578 million ($1.17/share) over the same period in 2018. Operating income was $722 million ($1.46/share), against Zacks’ consensus estimate of $1.33/share.
The company said the difference between GAAP and operating earnings was driven primarily by the mark-to-market impact of economic hedging activities.
CEO Nick Akins told financial analysts Thursday that the company’s overall load is “making a comeback.” Industrial sales, driven by oil and gas production in Oklahoma, were up 3.4% during the quarter, and the footprint’s GDP grew at a 2.4% rate, ahead of the 2.1% national average, AEP said.
AEP territory | AEP
“I think you’re seeing some resiliency from an industrial and manufacturing standpoint. You’re starting to see it pick up,” Akins said. “We’ve got the oil and gas activity going gangbusters. … There’s no question people have more money in their pockets and people have more jobs. That’s reflected in what we see.”
The Ohio-based company increased and narrowed its 2019 operating earnings guidance range to $4.14 to $4.24/share, up from $4 to $4.20/share and reaffirmed its long-term growth rate of 5 to 7%. AEP’s share price is up 26.4% since the year began, beating the S&P 500’s 19.9% pace.
Wall Street greeted the news by driving the share price up 75 cents to $95.74 in after-hours trading.
NEW ORLEANS — MISO executives and some of its state regulators last week provided sharply contrasting visions of the grid’s move away from fossil fuels and toward renewables.
MISO President of Market Development Strategy Richard Doying arrived at the Organization of MISO States’ annual meeting in the Big Easy to discuss the RTO’s 2019 Forward Report, which concluded that market changes are necessary as the RTO footprint experiences demarginalization, decentralization and digitalization. (See New MISO Report Starting Point for Major Grid Change.)
The RTO had only about 400 MW of wind in 2007, CEO John Bear said. Doying noted it is now nearing 20 GW of wind generation in its mix, which can have zero marginal costs.
“That is the right economic price, but it’s terrible for baseload generation,” Doying said.
MISO’s generation interconnection queue currently contains 59 GW of solar projects and 27 GW of wind projects.
But 15 years ago, coal was king in the footprint, holding more than 75% of the generation mix; now MISO predicts that share will drop to less than 25% by 2030.
But Kentucky Public Service Commissioner Talina Mathews offered a starkly different picture. She said her state, with its continuing flat loads and lack of a renewable portfolio standard, still seems perfectly happy with 94% of its energy needs being supplied by coal and natural gas.
Kentucky doesn’t yet see a need to add renewable generation, Mathews said. For customers that do want renewable energy, she pointed out that western Kentucky, as a MISO member, can access other states’ renewable generation.
“We’re seeing change come more slowly,” she said. And as far as those “green kilowatt-hours? We’re going to sit back and let that come to us.”
“Would some people say my head is in the sand?” she mused. “Maybe.”
But many of Kentucky’s residents simply can’t afford to think about clean energy, Mathews said. To them it doesn’t matter “what color the kilowatt-hours are” as long as they come cheap.
“When your home is a pre-1970s trailer with resistance strip heating, you can’t respond to [energy] market signals,” she said, adding that many in Kentucky’s formerly booming coal country are barely scraping by.
“We have counties that are at 12% [unemployment],” Mathews said. “We have counties that are taking the hit for other people’s energy decisions. And that’s fine. That’s how economies move.”
Minnesota Public Utilities Commissioner Matt Schuerger offered yet another view. He said while renewable adoption was stimulated in the beginning by state renewable targets, they’re no longer a catalyst in 2019.
“We’ve moved beyond that several years ago. In fact, most utilities met these goal several years early,” Schuerger said.
Arkansas Public Service Commission Chairman Ted Thomas argued that energy innovation isn’t a one-step process and markets are best positioned to encourage and accommodate the series of steps — not a federal rule.
“Imagine if we still had the Clean Power Plan. You would have state policy in response to federal mandates clashing with” FERC rules, he said. Storage remains the most potentially disruptive technology that is close to mass deployment, he said. Consumer-oriented demand response is a close second.
Thomas said he agreed with Supreme Court Justice Oliver Wendell Holmes Jr.’s position that laws should be written with the “bad guy” in mind, or the one person that will try to exploit the law for personal gain. He said that advice should be carefully considered when states target certain levels of fuel mix diversity.
“There’s going to be some ‘slick’ that is going to free-ride. That’s human nature,” Thomas said.
He also said the manner in which decentralized generation is adopted remains debatable: “There’s a lot of talk that we’re going to be decentralized, but the question is how — decentralized at scale or decentralized on rooftops?”
Doying took notes during the exchange; MISO plans to release an updated version of its Forward Report in 2020.
TROY, N.Y. — The state must put a price on carbon in its wholesale electricity market if it hopes to meet the aggressive timelines of the decarbonization goals set out in a new law, the co-author of NYISO’s carbon pricing study told stakeholders last week.
“If New York does not do this in the electric-sector engine that the law hopes to rely upon to decarbonize the economy, it’s tying two hands behind the state’s back,” Analysis Group’s Sue Tierney said on Oct. 22 in delivering a summary of the study to NYISO’s Installed Capacity and Market Issues Working Group (ICAP/MIWG). “You will not get the efficiency, or timing, or depth, or pace of change without having this electric system engine on acceleration to get it.”
Delivery of the long-awaited study was delayed a couple months to perform additional analysis on the impacts of the Climate Leadership and Community Protection Act (CLCPA), signed into law in July by Gov. Andrew Cuomo. Among other provisions, the law requires 70% of the state’s electricity to be generated by renewable resources by 2030 and the whole economy to be carbon-neutral by 2040. (See NYISO Study: Carbon Charge to Help NY Climate Goals.)
“It’s going to be really hard to meet the new goals in the CLCPA, even with a carbon price. It’s going to be really hard, so the state should be relying on every tool it can to get the job done,” Tierney said.
Implications of the CLCPA for entry of renewables and zero-carbon resources in New York | Analysis Group
NYISO stakeholders took a fine-tooth comb to the final version of the carbon pricing study at the ICAP/MIWG meeting, posing dozens of questions to Tierney.
“Is there a threshold size of the [decarbonization] solution that needs to come from carbon pricing, or is it linear, like you can have as little as 1% of it being accomplished through carbon pricing, or 99%?” asked Aaron Breidenbaugh, representing Consumer Power Advocates.
“I don’t think there’s an engineering or an economic answer to that because we’re going to be surprised, happily surprised, by a market solution,” Tierney said. “Introducing a carbon price will create a dynamic effect, which in turn will produce results later on, and the results will affect things that happen after that.”
Market Efficiencies
The report said the literature on organized wholesale markets indicates carbon pricing will produce a 1 to 3% efficiency improvement in the overall capital and operating costs of the wholesale electric system.
“Applying that range of market efficiency benefits to the above-market cost analysis, we estimate a benefit to New York consumers in the range of $280 [million] to $850 million, net present value, for a baseline scenario running from 2022 to 2036,” Tierney said. The baseline refers to the NYISO Gold Book forecast of baseline demand, she said.
“What is the 1 to 3% supposed to be capturing?” asked Howard Fromer, director of market policy for PSEG Power New York. “In a world that had the social cost of carbon reflected in LMPs, one would expect LMPs to trend higher to capture that cost in a marginal unit, to the extent that fossil is that marginal unit. I would expect that as that percolated through the electric system … you would see people doing things differently, being more active in efficiency opportunities as prices were higher. I assume some elasticities. … Is this 1 to 3% capturing that kind of benefit?”
Tierney provided an example: “If one did a long-term renewable energy credit procurement as the only approach to meeting the requirements of the CLCPA, then an owner of a fossil unit … might decide that the next dollars it might consider spending on operations and maintenance to keep that plant the most efficient one are not worth spending. The market would be telling that owner that it would be stupid to invest in such efficiency. This [1 to 3%] is meant to capture the other things going on.”
Mark Reeder, representing the Alliance for Clean Energy New York, said he assumed that carbon pricing would have negligible effects on energy efficiency, as residential retail prices would go down.
“There is no increase in energy conservation in homes from a program that results show the prices are in fact going down,” Reeder said. “Maybe you could have done an offset to your $280 million and go down another 15 [million dollars] and say it’s $265 million, but we keep forgetting the result … is customer prices go down. The customer impacts are quite near zero, but on net, the prices go down.”
Reeder questioned the premise of getting the 1 to 3% coming from the dispatch: “Most of the literature about going to deregulation was that it would increase efficiencies in terms of people’s investment decisions, in terms of their maintenance decisions. I would think the bulk of the 1 to 3% is in the investment decision to extend the life of your plant, to make your gas plant more efficient. None of those are dispatch efficiencies.”
Tierney disagreed. “There will be also dispatch efficiencies, along with the other types of efficiencies,” such as investments to make individual plants more efficient and others that reflect a shift of risk from consumers to owners of generation and transmission, she said. “So the dispatch efficiencies will be reflected in the new portfolio of resources [that] results from the new investment signals, including locationally in New York. Our 1 to 3% is meant to cover all of those types of things.”
Transmission Differentials
“We include in the value proposition that the carbon price would send signals for transmission as a result of a differential in LMPs, upstate and downstate,” Tierney said. “We also said that part of the value proposition here would be more direct signaling about the value of adding demand and supply resources in downstate New York, where most of the load occurs and where the prices would be higher.”
One of the benefits listed in the report has to do with transmission buildout, which NYISO has already documented as essential to New York meeting its aggressive goals, Fromer said.
“There is simply no way we’re going to make a dramatic dent in carbon reduction unless more transmission is built in the state,” Fromer said. “To what extent does the 1 to 3% benefit capture the difference of a likelihood of transmission buildout in a world where you’re moving $30 power to a $35 market, versus $30 power to a $55 market? How do you get the public to accept spending a billion dollars for a line that’s saving hardly any money?
“What is the logic that you get more transmission built from upstate to downstate unless you’re reflecting the carbon benefit of that transmission in the price — and is any of that in the 1 to 3%?”
Tierney said she didn’t think so. “Based on the literature review, that has not been called out as a specific issue. I think that is a powerful advantage of the NYISO’s carbon-pricing proposal, putting a price signal on transmission.”
Fromer said that raised the issue of whether the state would get more carbon reductions by just relying on REC contracts.
“One of the concerns with the [CLCPA] is … you might not get carbon reduction from some of the renewable additions upstate because the load being reduced would have been using renewables anyway, and you don’t have the lines to move the surplus power downstate,” Fromer said. “Even though you’re spending a lot of money, you’re displacing other pre-existing carbon-free energy.”
“I agree. … When we did our buildout scenarios and estimated the above-market costs that one might expect as a result of the CLCPA, which was the lump of money from which we said that you could expect to get 1 to 3% in efficiency savings, we included no transmission investment in that,” Tierney said. “We did include one scenario [that] assumed that all of the offshore wind dumped into New York City, so that higher cost is reflected in part in there.
“In order to actually get the carbon reductions, there has to be a demand forecast that reflects electrification of buildings and vehicles, including in downstate New York, where most of the state’s demand is located, and that has to include getting the power to where people live,” she said.
ISO-NE will add five buses to the bulk power system list and remove seven others for various reasons, the Planning Advisory Committee learned on Thursday.
Dan Schwarting, lead engineer for transmission planning, presented the BPS list updates to the PAC and said reasons for the additions include planned transmission upgrades, changes to protection schemes, and a reduction in inertia in Nova Scotia and New Brunswick.
Two of the additional buses were previously identified as BPS in the proposed plan application (PPA) for the Southeast Massachusetts/Rhode Island (SEMA/RI) transmission upgrades, and all five were identified in the 2019 BPS assessment report.
Reasons for the seven bus removals include generation retirements, dynamic model changes and other system changes since 2016, Schwarting said.
Four buses were previously identified as new BPS in the PPA study but will not be added to the BPS list. All seven buses were identified in the 2019 BPS assessment report.
The Northeast Power Coordinating Council requires the identification of buses that are part of the BPS, with some NPCC criteria applying only to BPS buses or BPS elements, including Directory 1: Design and Operation of the BPS and Directory 4: System Protection Criteria.
BPS classifications are determined through a performance-based test, as described in NPCC Document A-10.
RSP Transmission Projects and Asset Conditions
New England saw cost increases of nearly $200 million on 11 transmission projects between June and October 2019, according to Brent Oberlin, the RTO’s director of transmission planning, who presented on Regional System Plan transmission projects and asset conditions.
Eight of the projects were in the Greater Boston area and had a combined cost increase of $157 million, which Eversource Energy attributed to “actual construction bids coming in higher than estimated costs, lengthy and extensive permitting, and restrictive permitting conditions,” Oberlin said.
Investment of New England transmission reliability projects by status through 2023 | ISO-NE
The other three projects all were in the Seacoast New Hampshire Solution, in the Madbury-Portsmouth area, and experienced a combined cost increase of $40 million, which Eversource also attributed to actual construction bids coming in higher than estimated costs, lengthy and extensive permitting, and restrictive permitting conditions.
“This can’t keep happening; the estimates have to get more accurate,” said Dorothy Capra, director of regulatory services at the New England States Committee on Electricity. “You don’t want to keep upsetting state regulators.”
Eversource representatives at the meeting said they would be prepared to answer questions on the cost overruns in more detail at the PAC meeting in November.
There were no new projects since the June 2019 update, but three upgrades on the project list have been placed in-service, including two in Greater Boston and one in Greater Hartford and Central Connecticut, Oberlin said.
Cumulative investment of New England transmission reliability projects and asset condition through 2027 | ISO-NE
Eversource 1355 115-kV Line Rebuild
Eversource’s John Case presented the utility’s plans for an estimated $7.45 million line rebuild in Connecticut (+50% to -25%), with an estimated in-service date of May 2020.
Eversource proposes to rebuild the 115-kV 1355 transmission line from the Colony substation to Schwab Junction in Wallingford, Conn., replacing 14 aged and degraded structures with new steel structures.
A conductor dating back to 1927 | Eversource Energy
The original 1927 steel lattice towers on the line have bent members, corrosion and tower legs located in standing water. The conductor and shield wire in this section are original to the line, thus 92 years old, and no longer standard Eversource transmission conductors, Case said.
The utility will reconfigure the circuit arrangement and right of way to reduce the structures and conductors required, eliminating seven structures and approximately three-quarters circuit-miles of conductor. The aged and degraded copperweld conductor and shield wires will be replaced with new standard conductors and optical ground wire.
Wood structures in this section date from 1966 and suffer from various degrees of woodpecker damage, rot, cracks and deteriorated steel mechanical connections.
Tx Owner Local System Plans
The PAC meeting was followed by a meeting of the Transmission Owner Planning Advisory Committee, a transmission owner-led forum. The TOs each provided brief introductions of their local system plans or those of their subsidiaries, including upcoming transmission projects within their areas.
The New England Power Pool Reliability Committee (RC) on Wednesday reversed its September rejection of ISO-NE’s proposed installed capacity requirement (ICR) calculations for Forward Capacity Auction 14 (2023/24) and three annual reconfiguration auctions (ARAs) to be conducted in 2020.
A restored End User sector quorum and a break in the ranks of universal opposition from the Generation sector proved the tipping point. Needing a 60% majority to recommend the ICR values to the Participants Committee, the RC voted by roll call and passed the motion with 63.49% in favor. The RC approved net ICRs of 32,205 MW for 2020/21 ARA 3, 32,230 MW of 2021/22 ARA 2 and 32,465 MW for 2022/23 ARA 1.
The Generation sector voted 4.2% in favor and 12.59% opposed, with one abstention. The Transmission and Publicly Owned Entity sectors remained unanimous in favor, Alternative Resources remained approximately split, and the End User sector was recorded unanimously in favor with one abstention.
Capacity commitment period 2020/21 ARA 3 systemwide capacity demand curve | ISO-NE
The committee also approved a 940-MW value for the Hydro-Québec interconnection capability credit (HQICC) for FCA 14’s ARA 3, with the value rising to 958 MW for ARA 2 and 969 MW for ARA 1.
Peter Wong, ISO-NE manager of resource studies and assessments, and Senior Engineer Manasa Kotha presented the ICR values and tie benefits.
Pending PC approval on Nov. 1, the RTO plans to file the ICR-related values with FERC by Nov. 5.
$46 Million PTF Cost Allocation
The RC voted to recommend that ISO-NE approve pool-supported pool transmission facility (PTF) costs of $46.39 million for the Baird 115-kV line rebuild project in Connecticut, per the revised cost allocation submitted by Avangrid/United Illuminating.
The committee found the costs consistent with the criteria set forth in Section 12C of ISO-NE’s Tariff for receiving regional support and inclusion in pool-supported PTF rates, and that none of the costs associated with the upgrade are considered localized costs.
The project involves rebuilds of the 88006A and 89006B lines between Baird substation, Barnum substation and the Devon Tie switching yard tying into the Housatonic River Crossing project, for a total distance of approximately 2.4 miles, and includes installing new galvanized steel transmission poles supporting new aluminum conductor steel-supported cable and optical ground wire.
Based on a show of hands, the motion passed with none opposed and no abstentions.
Other Action
The RC on Wednesday also approved a number of projects, including recommending that ISO-NE approve implementation of the Scitico substation circuit breaker and transformer addition project by Eversource Energy in Connecticut, as well as the 15-MW Davenport Solar Generation project by NextEra Energy Resources in Vermont.
The committee also recommended that ISO-NE approve implementation of Eversource’s Andrew Square-to-Dewar Street Station 115-kV cable installation project in Boston; New England Power’s 40-plus-MW Iron Mine Hill Road solar generation and transmission project in Rhode Island; and the latter’s King Solar 1 and 2 generation project.
It also approved revisions to Operating Procedure 16J to modify the timing for initiating the annual certification of transmission equipment dynamics data; and revisions to Operating Procedure 2A, to modify the table of itemized equipment maintenance of communications, computers, metering and building services.
Attorneys in the Pacific Gas and Electric bankruptcy case sparred Wednesday over the merits of their competing reorganization proposals, taking potshots at each other’s plans but not scoring any obvious points with the judge overseeing the proceeding.
The hearing was the first since U.S. Bankruptcy Court Judge Dennis Montali ended the utility’s exclusive right to submit a restructuring plan. The decision allowed the company’s unsecured bondholders to submit their own proposal, which has won the support of a group representing wildfire victims, the court-appointed Tort Claimants Committee (TCC). (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)
The hearing also coincided with PG&E’s announcement that it would cut power to customers in 17 Northern California counties in the second series of public safety power shutoffs (PSPS) orchestrated this month to prevent wildfires. The blackouts commenced Wednesday morning and continued into Thursday.
The bondholders’ attorney, Michael Stamer, came out swinging early in the hearing. He disparaged the feasibility of PG&E’s reorganization plan and urged Montali to schedule a confirmation vote for the bondholder proposal as soon as possible — a move that would effectively prioritize the plan over the utility’s.
“We think the most efficient way to get to the end zone — which is confirmation [of a plan and] satisfaction of AB 1054 — is to allow our plan to go first,” Stamer said, referring to the new California law that allows PG&E to draw on a $21 billion fund to cover wildfire damages if it wraps up its reorganization by June 30, 2020. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
Stamer said the bondholder plan would also accelerate a separate state court proceeding convened by Judge James Donato to settle wildfire victims’ claims against PG&E over the October 2017 Tubbs Fire, which killed 22 people and leveled a section of Santa Rosa. (See PG&E Bankruptcy Split into Three Parts.) He contended the plan would “remove the burden” from Donato to estimate damages because bondholders have already negotiated a settlement with the TCC to cover claims of up to $13.5 billion for that fire. The PG&E plan caps the claim amount at $6.9 billion.
Montali was skeptical of Stamer’s argument.
“There’s a whole group of lawyers on the other side who think the burden is not gone — it’s still there. It’s called evaluation,” Montali said, questioning whether the bondholder’s plan might “overpay” tort claimants at the expense of other parties.
Montali added that the bondholder plan might be “DOA” if Donato “puts a larger number” on the claim.
“Our plan is DOA if he puts a very small number on them,” Stamer retorted. Nevertheless, the parties supporting either plan would have to “scramble” if the settlement lands between $6.9 billion and $13.5 billion, he said.
“They’ll scramble to come up, and we’ll scramble to come down,” he said.
Stamer said the “biggest difference” between the two plans is that PG&E’s financing is contingent on the $6.9 billion top-end estimate for potential Tubbs Fire claims.
“Unequivocally, they have to get Judge Donato to say that there is less than $6.9 billion of tort claims, or their financing disappears,” he said.
Montali pointed out that PG&E has said it will come up with additional financing if needed.
“We actually refer to that as the ‘stroke of the pen’ argument,” Stamer replied. “The debtors are of the view that if they get a different view from Judge Donato, with the stroke of a pen, what we will do is we will raise more money.
“So, here’s one of the fundamental problems — the world doesn’t work that way. No. 2 is the bulk of their money coming from equity holders. Setting aside the $30 billion of bridge loans, it has to come from equity holders.”
“You might say that doesn’t happen in the real world, and I might agree with you. That’s why you schedule a hearing — to prove the feasibility,” Montali said.
The judge firmly rebuffed the notion that he could shelve PG&E’s plan in favor of the bondholders.
“I have to do what the [bankruptcy] code says … and I don’t think it says I can dump a debtor’s plan because another plan is confirmable,” Montali said.
No Altruists
PG&E attorney Stephen Karotkin complained that Montali’s decision to terminate PG&E’s exclusivity “has not worked to promote a consensus” in settling on a reorganization plan.
“As we told you, the [Ad Hoc Committee of Unsecure Bondholders] and the TCC have become polarized entirely and now want to move forward with their own plan. That’s not the way it should work,” Karotkin said.
“At the exclusivity hearing, your honor, the TCC made very clear to you that they would only engage in mediation if you agreed to terminate exclusivity,” he said. “Having done that, we say to your honor, now is the time to promptly appoint a mediator. That is the way to move these cases forward, and let’s see if the TCC will live up to its word and its commitment to this court to mediate.”
Karotkin contested the bondholders’ contention that financing for the PG&E plan would fall apart if the Tubbs Fire claims exceed $6.9 billion, saying there is “ample capacity in both the debt and equity markets to fund the plan and meet the requirements of AB 1054. The debtor’s plan does not vaporize.”
He said Stamer was promoting the misconception that PG&E’s financing must come from the existing equity holders. “It doesn’t. There’s no requirement that it comes from the existing equity holders,” he said.
“The ad hoc bondholders are not a group of altruistic investors willing to put up money on favorable terms in an effort to save the state of California,” Karotkin said. “Any number of financial institutions have advised the debtors that there is adequate capital necessary … and on substantially better terms than the terms that are being provided by the ad hoc bondholders.”
Montali assured Karotkin that PG&E’s plan was still a contender.
“I may have disappointed you because I ended exclusivity, but I didn’t say your plan was out of the running,” Montali said.
“Neither one is perfect yet, and neither one is confirmable yet. But both are potentially confirmable,” he said.
Montali declined to rule on scheduling the confirmation of either restructuring plan. Hearings in the proceeding are slated to continue at least into early next year.
Shutoffs Resume
By Thursday morning, PG&E’s latest round of shutoffs covered nearly 183,000 customers — or about 540,000 people — in the Sierra Foothills and North Bay regions, where a “Diablo” wind event was bringing peak gusts of 65 miles per hour in conditions of extremely low humidity.
“Once the high winds subside, PG&E will inspect the de-energized lines to ensure they were not damaged during the wind event, and then restore power,” the utility said in a statement. “PG&E will safely restore power in stages as quickly as possible, with the goal of restoring the vast majority of customers within 48 hours after the weather has passed.”
PG&E tweeted that customers currently impacted would be restored in advance of any further PSPS initiated this weekend. The company said it forecasts indicated “elevated” risk of additional blackouts on Sunday and Monday.
PG&E’s incited a backlash from California regulators and Gov. Gavin Newsom over its decision to shut power to more than 2 million residents earlier this month. The company has defended its decision and last week signaled it will continue the PSPS policy for years until it hardens its system against wildfire danger. (See PG&E Says Blackouts Will Continue.)
CARMEL, Ind. — MISO is rearranging its Integrated Roadmap schedule to update the list of market improvements annually instead of the existing nearly two-year timeline.
The RTO said it will cut the Integrated Roadmap from 20 months to 13 months to put it in sync with the MISO’s annual budget process and the Independent Market Monitor’s yearly State of the Market Report. The Monitor’s recommendations are regularly folded into the ongoing list of market improvements.
MISO is suggesting a one-time shift of the Integrated Roadmap to cut seven months out of the process from recommendation to numbered roadmap item. After the change, stakeholder prioritization of recommendations will take place in March instead of July.
At an Informational Forum on Tuesday, market strategy team member Christov Churchward said the move to the new timeline will be implemented by the end of the year, nudging the new issue submission for the 2020 roadmap to Dec. 23 instead of the usual cutoff in the beginning of May. MISO and stakeholders’ issue prioritization is slated to begin Jan. 22 and wrap in the first half of April.
“This will continue to make the Integrated Roadmap even more integrated,” Churchward said.
MISO plans to hold a workshop Nov. 7 to discuss which improvements it will undertake with stakeholders from 2020 through 2025. (See Stakeholders Confused over MISO Roadmap.)
Prices, Peak Stay Low in Hot September
MISO’s average load in September nearly matched load at the same time last year, though peak loads stayed significantly below September 2018.
The RTO reported a 79.5-GW average load throughout the month, in line with the 79.4-GW average load in 2018. It hit an almost 107-GW peak on Sept. 11, well below the 115-GW peak on Sept. 4, 2018.
MISO said parts of its South and Central regions were 6 to 7 degrees Fahrenheit above the National Oceanic and Atmospheric Administration’s 30-year September historical average.
“We had a warm enough September this year — even warmer than last year,” Executive Director of Market Operations Shawn McFarlane said.
MISO systemwide prices September 2018 to September 2019 | MISO
The RTO called a hot weather alert in MISO South for Sept. 5-9, when average high temperatures stayed above 95 degrees. Despite this, MISO was able to keep “good supply availability,” McFarlane said.
In mid-September, RTO executives predicted MISO’s forecasted 112-GW fall peak wouldn’t come to pass with the worst of September heat behind the footprint. (See MISO Unruffled by Fall Supply-demand Outlook.)
Despite warm weather loads, prices stayed low, with MISO averaging a $24.61/MWh real-time LMP — a 27% decrease compared to September 2018 when real-time prices averaged $33.82/MWh. McFarlane said the low prices were a product of strong natural gas supply and low fuel prices.
A federal judge ruled Wednesday that only the Ohio Supreme Court can determine whether state law thwarted a citizen advocacy group’s ballot petition against nuclear plant subsidies.
Judge Edmund A. Sargus Jr., of the U.S. District Court for the Southern District of Ohio, denied Ohioans Against Corporate Bailouts’ motion for a preliminary injunction after the group claimed 38 days of its 90-day allowance to collect signatures were wasted in a “blackout period” during which it sought the attorney general’s approval of the petition’s language before circulation could begin.
The group has alleged a well-funded opposition harassed and bribed its petitioners, further complicating its effort to gather 265,774 signatures by Oct. 21. (See Ohio Nuke Petition Misses Signature Deadline.)
“This 90-day period they claim is burdened arises from the Ohio, not the federal, Constitution,” Sargus wrote. “Whether the Ohio Constitution guarantees a full 90-day period for petition circulation, and whether the statute’s requirements ‘burden the 90-day period,’ is a question beyond the jurisdiction of this court. Instead, these questions should be resolved by the Ohio Supreme Court.”
Perry Nuclear Power Plant, located about 40 miles northwest of Cleveland
Ohioans Against Corporate Bailouts has led a campaign against Ohio’s House Bill 6 — a $150 million nuclear subsidy program funded with ratepayer surcharges — having begun organizing petition efforts the same day Gov. Mike DeWine signed the legislation in July. The group fell nearly 45,000 signatures short of the count necessary for the referendum’s inclusion on the 2020 ballot, according to documents filed Wednesday.
“We look forward to making our case to the Ohio Supreme Court that the petitioning ‘blackout’ period is an unfair infringement on our constitutional right to referendum,” Gene Pierce, the group’s spokesperson, said in a statement. “Ohioans deserve the opportunity to vote on House Bill 6, and the despicable campaign by supporters of the bill to prevent that should not be rewarded.”
William Rogers, president of Advanced Micro Targeting, the Nevada-based company that managed the referendum effort, said in court documents that he had never encountered a “more hostile environment” in any other state throughout his 30-year career. He said Ohio’s draconian preregistration requirement, coupled with the opposition’s abuse of public records to target petition circulators for harassment and bribery, undercut the group’s efforts. (See Federal Court Waives Ohio Preregistration Law.)
Rogers said he knew in late September that the constant interference would prevent the group from meeting its deadline, so he began contracting with pay-per-signature firms to keep the campaign on track — to no avail. He claims the opposition poached 900 circulators between Sept. 3 and Oct. 21 by offering up $2,100/day to peddle a “fake petition.” AMT, by comparison, paid just $150/day.
Rogers told the court he estimated that it would take about 75 days to gather the necessary signatures and had initially expected circulators would collect around 4,100 per day.
Secretary of State Frank LaRose, the state’s chief election official and a defendant in the lawsuit, argued that the so-called blackout period is an “elections-mechanics rule that sets forth certain procedures for the referendum process” and doesn’t preclude advocates from promoting a petition in public discourse. He said that questions about whether the Ohio statute intends to give petitioners a full 90 days just for collecting signatures is worth exploring, but not in a federal court.
Sargus agreed, noting that the Ohio Supreme Court could give the group the remedy it seeks: a stay of HB 6 and additional time to circulate its petition.
“At the heart of plaintiffs’ claims is [the] proposition that the Ohio Constitution affords them 90 days to circulate a referendum petition, and that their First Amendment rights are violated by the statute because of the blackout period,” he said. “But Ohio courts have not held whether the 90-day period is guaranteed for circulating, or whether the required review by the attorney general violates the Ohio Constitution.”
Tom Becker, spokesperson for FirstEnergy Solutions, said Thursday the court’s decision “ensures that its citizens will have lower electric bills and cleaner air.” The company previously warned that it would resubmit deactivation notices for its Perry and Davis-Besse nuclear plants should the advocacy group succeed in its efforts. FES rescinded deactivation notices for both facilities in July after the state approved HB 6. (See Ohio Approves Nuke Subsidy.)
“We are pleased that our state will continue to benefit from diverse energy resources and that more than 4,000 jobs have been saved at our carbon-free, reliable nuclear power plants,” he said.
NEW ORLEANS — The outgoing president of the Organization of MISO States used his final address to the MISO community to once again press the RTO to develop a long-term transmission plan.
“We came together to encourage MISO to come together and study long-term transmission needs,” OMS President Daniel Hall said Thursday during a look-back at the organization’s 2019 accomplishments at its annual meeting. Hall attended the meeting via telephone, kept home by illness.
“There is nothing radical in these principles. … However, our goal was to jump-start the conversation on long-term needs in the footprint,” Hall said, referring to the set of transmission planning principles state regulators released in June. OMS has for months insisted that the RTO study creating a long-term transmission planning package similar to the 2011 multi-value project (MVP) portfolio. (See MISO Cracks Door on Long-term Tx Planning.)
In a review released earlier this month, MISO said the MVP package continues to show $16 billion to $57 billion in benefits, with a benefit-cost ratio ranging from 1.8:1 to 3.1:1.
“The current planning process is not sustainable. In fact, many stakeholders would say it’s broken,” Hall said. He urged MISO to put together a “thoughtful and comprehensive” long-term transmission plan study.
“Failure to do so will result in missed opportunities,” Hall said, referencing reliability benefits, reduced customer costs and accommodation of a growing renewables fleet.
MISO CEO John Bear said OMS’ long-range transmission planning principles are “a great call to action.”
OMS members also elected Minnesota Public Utilities Commissioner, and current vice president, Matt Schuerger as their 2020 president, a role he’ll take on two months early, as Hall plans to exit the Missouri Public Service Commission next month. North Dakota Public Service Commissioner Julie Fedorchak was elected vice president.
Transmission owners warned PJM last month that FERC inaction on the RTO’s capacity market revamp isn’t the only obstacle stalling future capacity auctions — state legislatures will likely need extra time to comply with the ruling too.
In a Sept. 4 letter addressed to the PJM Board of Managers, CEOs from PJM’s largest utilities urged the RTO to convene a meeting with stakeholders and produce a schedule that allows for time between FERC’s decision and the 2022/23 and 2023/24 Base Residual Auctions.
“Regardless of what FERC decides as to these new market rules, states will need time to react by redesigning their own clean energy programs and utility procurement programs,” said the CEOs of American Electric Power, Exelon, Public Service Enterprise Group, Dominion Energy and FirstEnergy. “This is no easy task.”
PJM submitted its proposal to create a resource-specific fixed resource requirement (FRR) in October 2018, four months after FERC ruled that its capacity market rules were not just and reasonable because they failed to address growing subsidies that the commission said are suppressing prices. (See FERC Orders PJM Capacity Market Revamp.)
The RTO made the FRR proposal as an alternative to expanding its minimum offer price rule (MOPR) to include all new and existing capacity receiving out-of-market payments, such as renewable energy credits and zero-emission credits for nuclear plants. The RTO’s MOPR currently covers only new gas-fired units.
The TOs cited comments filed with FERC from all sectors — including states, consumer advocates, load interests, suppliers, nongovernmental organizations and public power groups — that said regulatory and legislative changes will likely be required in the majority of PJM’s footprint to accommodate an FRR or expanded MOPR. Moving forward without these controls in place would further destabilize price signals and result in stranded costs, the TOs said.
“When the capacity auctions … are ultimately held, they will be most successful if they occur against a backdrop of stable and settled market rules, as well as state policies enacted in response to those rules,” the TOs’ letter concludes. “Indeed, it would be counterproductive to hold an auction when major portions of the auction framework remain in flux.”
On Sept. 27, a second cross-section of PJM members — including AEP Service Corp., Avangrid Renewables, the Illinois Citizens Utility Board, the Delaware Division of the Public Advocate, Dominion, EDP Renewables, Exelon, FirstEnergy Utilities, Natural Resources Defense Council, Nuclear Energy Institute, the D.C. Office of the People’s Counsel, PSEG and the Sierra Club — requested the RTO produce a capacity auction schedule that accommodates state and regulatory timelines, reiterating that any auction held next year would likely still be too early to factor in the impact of these policy changes.
“A rushed auction process would lead to skewed price signals that undermine economically rational behavior while reinforcing the high level of perceived (if not real) conflict that currently exists between PJM and the states,” the letter concluded.
PJM indefinitely suspended all deadlines for its upcoming BRAs pending FERC action before the end of year, when many deadlines for the 2023/24 auction would come due. (See FERC Halts PJM Capacity Auction.)
In a response to the TOs dated Sept. 12, PJM agreed to consult with stakeholders and reach out to state and regulatory commissions after a FERC order to consider next steps. Interim CEO Susan Riley noted that a “prolonged delay” undermines both investment decisions and capacity and reserve requirements.
Stakeholders, notably, say neither factor is of great concern — considering PJM’s healthy reserve margins and the fact that developers work on their own timelines — and don’t require the RTO to rush BRAs.
“At the same time, we agree that the auction must be both practical in its implementation and offer a meaningful opportunity for states to consider and pursue alternatives depending on the substance of the FERC order and their policy objectives,” Riley said. “This question of timing is well-briefed and clearly before FERC such that it may be addressed in its decision.”
PJM spokesperson Susan Buehler said Wednesday that Riley’s response applies to both stakeholder letters.
On Friday, the PJM Industrial Customer Coalition and the PJM Power Providers Group submitted a joint letter to the board pushing back against claims from other sectors that an extended delay is sustainable, saying that many resources’ lending arrangements are based on three-year forward capacity commitments and payments.
“While recipients of out-of-market payments or those resources seeking to exit the market through a FERC-sanctioned carve out may be able to better manage a capacity auction delay, those resources solely dependent on market revenues to determine their viability rely heavily on the three-year forward capacity construct to make decisions related to investments in existing units, construction of new units or retirement of uneconomic units,” the groups wrote. “The current delay of the 2019 auction is challenging many of these financial arrangements that are so critical to the overall vitality of PJM’s markets.”
American Electric Power’s third-quarter figures beat expectations with earnings of $734 million ($1.49/share), up from $578 million ($1.17/share) over the same period in 2018. Operating income was $722 million ($1.46/share), against Zacks’ consensus estimate of $1.33/share.
