PHILADELPHIA — Has weather become so extreme that utilities should end the universal service model and stop serving at-risk locations?
It’s something that should be considered, Margaret Peloso, a partner in Vinson & Elkins’ Environmental & Natural Resources practice, told the Edison Electric Institute 2019 meeting last week.
Peloso cited the National Oceanic and Atmospheric Administration’s National Climatic Data Center, which found that between 1980 and 2018, the U.S. averaged 6.2 extreme weather events per year that resulted in $1 billion or more in damages (inflation adjusted to 2019). In 2014-18, the count of $1 billion events doubled to 12.6 per year, and in 2018 alone, there were 14 such events, including hurricanes, severe winter storms, floods and wildfires.
“We are seeing an increase in these really big, really high-dollar-value events,” Peloso said. “When you start to look at our structures for disaster relief and how we socialize disaster costs, we’re going to run out of money. And it raises the question: Who should pay for it?”
Peloso said the problem is a combination of climate change producing more severe events and more people living in high-hazard areas because of poor land use policies stemming from “misaligned” incentives. Local governments, which control zoning, benefit from an increased tax base and thus tend to be permissive and reluctant to risk litigation by denying landowners the right to build on their properties. And when there are losses from flooding or wildfires, much of the cost is externalized to the state and federal government.
In addition, research has shown that people underestimate risk and underinvest in insurance and risk mitigation, Peloso said.
“If you’re really looking at managing the risks for your company, as the CEO, I think it’s time to reconsider the universal service model and ask: Are there some areas that are just too exposed to natural hazards and risk to really be served?
“There’s actually a small utility in California … that couldn’t get general liability coverage this year because of wildfires,” Peloso said. The utility identified about 600 customers in high-risk areas. “They gave them all generators. And they said, ‘We’re going to shut your power off’” at times. (See related story, Fire Season Starts in Calif. with Power Shutoffs.)
“Let’s try to move away from this paradigm … of putting things exactly back where they [were],” she said. “Maybe that’s not where we really want people to live.”
Combining Efforts
The consequences of the current policies are stark. After a wildfire is extinguished, “we’re left with a landscape that’s going to take, in many cases, several decades to recover,” said Barnie Gyant, deputy regional forester for the U.S. Forest Service. “In some of the cases where we’ve had really large fires … it will be 100 years before we have a forest again.”
Gyant said government agencies need to work more closely with utilities and the owners of forest lands to coordinate preventive measures. In California, he noted, his department manages more than 60% of forested landscape and 20% of the landmass, giving it overlapping responsibilities with state and federal fish and wildlife agencies and utilities.
He cited the 2017 memorandum of understanding the Forest Service signed to improve coordination with Sierra Pacific Industries, which manages nearly 1.9 million acres of timberland in California and Washington. Other industrial landowners have signed the MOU since.
“Most everyone has five- or 10-year plans, but those plans are done in a vacuum. They’re not connected,” Gyant said. “When you look at the amount of money and resources those different entities have, I think we can make a difference with the fires in California. … We’re not saying we’re going to stop fires. But I do think we can be strategic in where we place our treatments to reduce the size of those fires, help protect communities and help protect infrastructure.”
Peloso agreed, saying policymakers should resist “throwing dollars at things like management per mile as opposed to trying to be smart about where the highest risks are.” Spending should be based on “where you get the most meaningful risk reduction instead of doing things [that] we think will generally reduce threats,” she said.
Resistance to Vegetation Maintenance
Former Florida Public Service Commissioner Ronald Brisé, now a government affairs consultant for Gunster, said utilities and regulators often meet resistance from local government over vegetation management efforts.
“Some cities will tell you … I’m going to sue you if you cut my trees,” he said.
Some areas that suffered outages following Hurricanes Irma and Wilms “are the same cities [where] their citizens are reacting because of vegetation management.”
IDACORP CEO Darrel Anderson, who moderated the discussion, complained of having to deal with separate sets of rules for his company’s operations in Idaho and Oregon.
In Idaho, the company can use a soil sterilant to prevent vegetation growth around its poles, a technique he said is proven to reduce the impacts of fire on electric lines. “In Oregon, we can’t do that unless we do a separate environmental study on each pole,” he said.
California’s annual wildfire season kicked off last week with high winds, a heat wave and precautionary power shutoffs by Pacific Gas and Electric to thousands of customers.
A wind-driven blaze called the Sand Fire burned 2,500 acres of hilly terrain 60 miles west of Sacramento, and another fire scorched 1,800 acres of dry grasslands in rural Central California. Neither fire caused serious injuries or property damage, but they underscored the threat of wildfires as vegetation begins to dry out after an especially wet winter.
In response to the hot, windy conditions, PG&E turned off power for a day or two for about 1,700 customers in Napa, Solano and Yolo counties near the Sand Fire and for nearly 21,000 in the Sierra Nevada foothills of Yuba and Butte counties. Last year’s Camp Fire, the deadliest and most destructive in state history, ravaged a large part of Butte and leveled the town of Paradise.
Members of the California National Guard search debris after the deadly Camp Fire, which led PG&E to institute emergency power shutdowns days later. | California National Guard
PG&E first deployed its controversial Public Safety Power Shutoff program last October, nearly a month before the Camp Fire started Nov. 8 — though it did not use the measure in Butte just before that fire ignited.
Power shutoffs are now part of the utilities’ annual wildfire mitigation plans approved by the California Public Utilities Commission. (See California Regulators OK Utility Wildfire Plans.)
A Portland, Ore.-based utility announced Thursday it was adopting a similar measure, suggesting that intentional shutoffs may spread beyond California. The Pacific Northwest has seen its share of devastating wildfires in recent years.
“This measure would only be taken as a last resort to help ensure customer and community safety,” Pacific Power said in a statement. The utility, a subsidiary of PacifiCorp, serves about 764,000 customers in Oregon, Washington and an area of Northern California near the Oregon border.
The National Interagency Fire Center (NIFC) in Boise, Idaho, predicts an active wildfire season in California, the Great Basin and the Pacific Northwest this year because of a “robust grass crop” from winter rains.
“As we go forward into June, those grasses that we see across the landscape are going to dry and cure out … and we’ll see an increase in fire activity especially across California,” said Bryan Henry, assistant program manager of predictive services at the NIFC.
Temperatures soared above 100 degrees Fahrenheit in inland areas during last week’s heat wave. CAISO issued its first “flex alert” of 2019 by calling for residents to voluntarily conserve electricity during peak demand in the late afternoon and evening, when air conditioning use spikes and solar arrays power down.
“Because of widespread heat, the ISO anticipates energy demand reaching a peak of 42,800 MW this evening,” CAISO said in a June 11 news release. “Also, two units with a total generation of 1,260 MW are offline due to mechanical failures. The Flex Alert is being called in response to the high electricity demand and the reduced generation.”
California, which last year mandated greater dependence on renewable energy sources going forward, offset the spike in demand largely with natural gas peaker plants, according to CAISO.
Four of New York’s major utilities will collectively see their revenues reduced by more than $7 million for failing to meet certain reliability and customer service requirements last year, state regulators revealed last week.
The New York Public Service Commission on Thursday reviewed reports on utility performance in electric reliability, gas and electric safety and customer service in 2018 (Cases 19-E-0169, 19-E-0246 and 19-M-0307). “While most utilities are doing a good job providing safe and reliable service, four utilities have fallen short of our expectations in certain areas, and we will continue to act aggressively to ensure utilities improve performance,” PSC Chair John B. Rhodes said. “Additionally, as a result of this analysis, it is clear that utilities must be ready to address more frequent and powerful storms.”
The PSC held its regular monthly session in New York City on June 13.
The utilities being dinged for their performance include New York State Electric & Gas, Central Hudson Gas & Electric, Orange and Rockland Utilities, and National Grid’s Long Island gas operation.
Major storms last year accounted for more than 80% of the total customer-hours of electric service interruptions and 36% of the overall number of customers affected. New York experienced 36 separate major storm events in 2018, with the five largest occurring between March 2 and May 20, said Mary Ferrer, of the Department of Public Service’s Office of Electric, Gas and Water.
Last year ranks third in customer-hours of interruption in the last 20 years, behind Hurricane Irene and Tropical Storm Lee in 2011 and Hurricane Sandy in 2012.
Last year saw more customer-hours of interruption when including major storms than calendar year 2017; however, excluding major storms, the statewide interruption frequency and duration performance for 2018 declined compared to the previous year and the statewide five-year average, primarily because of fewer outages from equipment failures and tree contacts, Ferrer said.
‘Right Kind of Oversight’
The commission relies on two primary metrics to measure electric performance: the System Average Interruption Frequency Index (SAIFI), and the Customer Average Interruption Duration Index (CAIDI). By compiling the interruption data provided by the individual utilities, the average frequency and duration of interruptions can be reviewed to assess the overall reliability of electric service statewide.
Benjamin Dunton
NYSEG had its worst performance last year since 2007 with an average duration of 2.17 hours, above the target of 2.08 hours. Central Hudson’s frequency performance of 1.50 did not meet the target of 1.38.
The duration and frequency target failures mean NYSEG shareholders will see a negative revenue adjustment of $3.5 million and Central Hudson shareholders will see a negative revenue adjustment of $2 million, the commission said.
All the utilities complied with safety standards in 2018. Manual stray voltage testing performed on approximately 1 million utility facilities statewide identified 396 stray voltage situations, more than in 2017, though incidences of the more severe category over 4.5 V declined. Most such incidents on utility-owned facilities stem from street lighting, DPS staff member Benjamin Dunton said.
Diane Burman
In response to a question by Commissioner Diane Burman about why the more serious stray voltage readings were down from the previous year, Dunton said, “More awareness on the part of people doing construction work and digging.”
DPS staff member Sonny Moze delivered the report on customer service quality, which found that most utilities met or exceeded the standards for customer service for 2018, with the exception of O&R, which failed to meet its target for calls answered by a representative within 30 seconds.
“This is the right kind of oversight,” Rhodes said of the customer service report. “I appreciate that O&R is responding to the evidence and will appreciate it even more when their performance improves to the standard that we expect.”
O&R’s shareholders will be required to pay $450,000 for the performance shortcoming.
Sonny Moze
“I do think it’s important that we have more meat on the bone when it comes to the 30 seconds for calls answered,” Burman said. “The utilities point out why it’s taking longer to answer the call, so we might need to work on that.” O&R, for example, cited higher-than-normal call volumes.
Barring ESCOs?
The PSC also announced steps that could prohibit five energy service companies (ESCOs) from further marketing and enrolling new customers in New York. Only one of the five companies, Atlantic Power & Gas, currently has any customers.
“I think it’s important to identify that we are looking at potential violations of the Uniform Business Practices [adopted for ESCOs], and really relating to filings that haven’t come, and there are no customers there,” Burman said. “Two of them have voluntarily discontinued practicing in the state because they failed to report to us. The other two are orders to show cause, but again there are no customers involved.”
John B. Rhodes
The commission has the authority to regulate ESCOs’ access to utility distribution systems, including the power to require them to meet price caps set at utility prices.
The PSC directed that Atlantic explain why the commission should not ban it from operating in New York or take other remedial action (Case 16-M-0618).
In March 2017, the commission ordered Atlantic to cease marketing to and enrolling customers. On March 4, DPS staff identified apparent violations of the order.
Atlantic does business in the service territories of Central Hudson, Consolidated Edison, and National Grid’s KeySpan Gas East and Brooklyn Union Gas. It has 30 days to counter the DPS findings.
Gregg C. Sayre
Further, the commission also directed that Clear Choice Energy, Amerigreen Energy, Bluesource Energy and Got Gas? — none of which has customers — explain why they should not be barred from operating in New York for failing to file their annual compliance filings.
Sayre Farewell
Rhodes read a resolution of appreciation for Commissioner Gregg C. Sayre, likely attending his last session as commissioner, as the New York State Senate is soon to vote on Gov. Andrew M. Cuomo’s nomination of Tracey Edwards, a Long Island Democrat, to a seat on the PSC. State law sets a maximum of five members of the commission, of which only three can be members of the same political party.
The PSC currently has four members: three Democrats and one Republican.
The Texas Public Utility Commission last week approved a certificate of convenience and necessity for a 345-kV transmission project that cuts through an active petroleum field in West Texas’ Permian Basin (Docket 48785).
During their open meeting Thursday, the commissioners agreed to tweak a previously proposed order by an administrative law judge.
The Texas PUC’s June 13 open meeting
The CCN allows Oncor and AEP Texas to build 345-kV double-circuit transmission lines, ranging in length from 44 to 59 miles, and at a cost of $98 million to $126 million. The line is part of the $336 million Far West Texas transmission project, approved by ERCOT in 2017. (See ERCOT Board Approves West Texas Transmission Project.)
During the meeting, PUC Chair DeAnn Walker and Commissioner Arthur D’Andrea discussed Walker’s addition of language allowing Oncor and AEP to make a “minor deviation” from the route if they receive landowners’ permission and they do not cause an “unreasonable” increase in cost.
Walker said she normally omits the language from orders. However, it gives the developers flexibility in dealing with drilling wells that take only months to begin producing.
“I think when Oncor gets out there, there’s going to be something they have to address,” Walker said. “If Oncor gets out there and finds something they can’t do, or they feel they don’t fall within the language, I’m fine with them filing a request for an expedited decision. I don’t think we should go to a full CCN to get them an answer.”
D’Andrea agreed with granting exceptions to transmission facilities in areas with petroleum development and suggested a rulemaking to address the process.
Commissioner Arthur D’Andrea
AEP Texas Securitization OK’d
The commission approved a request from AEP to securitize $369.2 million in system restoration costs as a result of Hurricane Harvey in 2017 (Docket 49308).
In an ex parte communication to Walker, financial planner Saber Partners argued that AEP’s proposed servicing fee of 10 basis points was inconsistent with the state’s Public Utility Regulatory Act that mandates a “lowest transition charge.” Staff examined 72 recent similar transactions and determined AEP’s request was consistent with those ranges and with the PURA.
PUC Fines Oncor, Intervenes at FERC
In other actions, the PUC:
Approved a settlement agreement against Oncor for inaccurate telemetry. The utility agreed to pay an administrative penalty of $75,000 (Docket 49454).
Voted to join regulators from Indiana, Mississippi and Missouri in intervening in LS Power’s complaint with FERC against MISO’s economic planning process (EL19-79). The company charges that the RTO’s planning process fails to provide a clear path for regionally beneficial economic enhancements that do not currently qualify as market efficiency projects, resulting in unnecessary congestion costs.
SPP collected another $1.65 million in market-to-market (M2M) payments from MISO in April, pushing the total to $62.5 million since the two RTOs began the process in March 2015.
| SPP
SPP staff told the Seams Steering Committee on June 11 that 33 temporary flowgates were binding for 585 hours, resulting in more than $934,000 in M2M bills. It was the 25th month in the last 31 in which M2M distributions have flowed in SPP’s direction.
Eight permanent flowgates were binding for 142 hours, accounting for more than $720,000.
Generators worried that Pacific Gas and Electric will try to reject billions of dollars in power purchase agreements during its bankruptcy proceeding said they will appeal a federal judge’s recent order telling FERC it has no authority over the agreements.
NextEra Energy, Calpine and Consolidated Edison Development filed notices of appeal with the U.S. Bankruptcy Court in San Francisco on Thursday. They want FERC to have concurrent jurisdiction with the court over the PPAs.
Judge Dennis Montali | Commercial Law League of America
The generators’ filing came the day after Judge Dennis Montali certified the matter for direct appeal to the 9th U.S. Circuit Court of Appeals, saying it “is very much a matter of public importance,” involving what is likely the largest utility bankruptcy in U.S. history, and ought to be decided quickly.
“Also of great importance, though not directly related to the rejection issue, are billions of dollars in claims arising from the tragic wildfires that occurred principally in 2017 and 2018 in Northern California for which [PG&E bears] substantial liability,” Montali wrote in a memorandum for the appeals court.
The fires include the fatal wine country fires of October 2017 in Napa and Sonoma counties and the Camp Fire, the deadliest in state history, which killed at least 85 people in November 2018 and destroyed the town of Paradise.
“In some cases [PG&E’s] liability is a result of [its] direct actions and in others because of … strict liability under California’s inverse condemnation laws,” the judge said. “These wildfires are the principal publicly stated reasons why the debtors filed for bankruptcy.” (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
Power Play
On June 7, Montali had issued another memorandum saying “FERC must be stopped” from undermining the bankruptcy court’s oversight of contracts PG&E might seek to reject during Chapter 11 reorganization.
Montali said FERC has no authority over the $42 billion in PPAs signed by the utility or its parent company PG&E Corp., despite the commission’s assertion that it shares jurisdiction in the matter with the court. (See ‘FERC must be Stopped,’ PG&E Bankruptcy Judge Says.)
The FERC decisions “discussed here were not the actions of a power regulator carrying out its statutory duties to police rates, terms and conditions of power contracts, and enforcing the filed-rate doctrine,” Montali wrote. “To be blunt, they were unauthorized acts of the power regulator executing a power play (to use a hockey term) to curtail the role of the court acting within its authorized and exclusive role in these bankruptcy cases. Those decisions cannot be applied or honored here.”
Montali emphasized that FERC does not have concurrent jurisdiction — “or any jurisdiction” — over the authorization of any rejections of PPAs. “Debtors do not need approval from [FERC] to reject any of their power purchase contracts,” he said.
Exelon’s Antelope Valley Solar Ranch in the desert near Los Angeles is one of the largest solar photovoltaic projects in the world and one of the renewable generation facilities potentially affected by PG&E’s bankruptcy. | U.S. Department of Energy
In response to petitions by NextEra and Exelon, FERC declared in January that it shares authority over PG&E’s wholesale PPAs with the bankruptcy court. (See FERC Claims Authority Over PG&E Contracts in Bankruptcy.) In May, it rejected a rehearing request by PG&E, saying the wholesale PPAs “implicate the public’s interest in the orderly production of plentiful supplies of electricity at just and reasonable rates” and so fall under FERC jurisdiction. (See FERC Denies PG&E Rehearing Over Contracts Dispute.)
PG&E asked Montali to tell FERC not to meddle in its bankruptcy proceedings, which he did, and requested an injunction against FERC, which he said was unwarranted.
“There is no need to enjoin anyone or any action now,” he wrote in June.
Montali has said all along that he thinks the 9th Circuit needs to decide the competing viewpoints of federal authorities and that he wanted to expedite that process.
“The central issue of whether a bankruptcy court alone may grant or deny a motion to reject a PPA as an executory contract, or whether FERC has a say in the question by virtue of its claimed ‘exclusive jurisdiction’ [over wholesale PPAs], has not been addressed by any reported 9th Circuit decision or by the United States Supreme Court,” Montali wrote.
The case involves up to 400 contracts for power, the rejection of which “will give rise to substantial damage claims because rejection constitutes a breach under current bankruptcy law,” the judge said. “How those damage claims will be treated under any Chapter 11 reorganization plan will inevitably be interrelated with how the wildfire-related claims will be treated.
“If FERC has a say in the rejection decision because its authority is upheld as ‘concurrent’ with this court’s, an extremely complicated situation will be rendered all the more complicated and time-consuming, possibly delaying further the ultimate resolution, settlement and payment of those wildfire and contractual claims,” Montali said.
FERC last week directed SPP to make Tariff changes to allow fast-start resources to set clearing prices, saying its current rules are not just and reasonable (EL18-35).
The order wraps up investigations of several RTOs the commission began in December 2017 under Federal Power Act Section 206 and directs SPP to eliminate inflexible operating limits and other rules that the commission said are preventing prices from reflecting the marginal cost of serving load. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
OG&E’s Mustang Energy Center features gas-fired quick-start units. | OG&E
FERC found SPP’s quick-start pricing practices to be unjust and unreasonable because they do not allow prices to reflect the marginal cost of serving load. It directed the RTO to make six Tariff changes that the commission said would result in acceptable rates:
Modify the real-time energy market clearing process to execute the cost-minimizing dispatch solution followed by a pricing run; remove a screening run; and remove the option for enhanced energy offers that incorporate amortized commitment costs in the incremental cost curves.
Modify the pricing logic so that commitment costs of quick-start resources (including all such resources even if they have not registered as quick-start resources) are reflected in prices, in both the day-ahead and real-time markets.
Include in the definition of quick-start resources a requirement that those resources have a minimum run time of one hour or less.
Allow for relaxation of all quick-start resources’ economic minimum operating limits by up to 100%, such that the resources are considered dispatchable from zero to their economic maximum operating limit in setting prices.
Apply quick-start pricing treatment to both registered and unregistered quick-start resources.
Include the quick-start pricing practices in the Tariff.
FERC said the changes will result in SPP “having a pricing mechanism that is similar to the pricing mechanisms in other RTOs/ISOs.” It noted that the RTO said it would be required to develop new pricing systems and software to gain compliance with the order, but it expected additional information to be entered into the record when “details on mitigation contained in the Tariff revisions are filed on compliance.”
Jenbacher 2 reciprocating engine | GE Power Generation
FERC found SPP’s approach to pricing quick-start resources to be “inconsistent with minimizing production costs.” It directed the RTO to submit a compliance filing by Dec. 31.
PHILDELPHIA — U.S. Rep. Paul Tonko (D-N.Y.) knows the kind of dramatic action needed to address climate change won’t happen with Donald Trump in the White House and Republicans in control of the Senate.
But he also doesn’t want to make the mistake that Republicans made when they nearly repealed the Affordable Care Act without having an alternative to replace it, he told the Edison Electric Institute’s 2019 conference June 10.
“I hope that [is] instructive to all of us sitting in this session of Congress: to develop a plan of attack while there isn’t the means to get it done so that when the political climate … is ripe, we’re ready to go. We have no time to waste.”
For now, he says, he chooses to avoid “rhetorical” debates over the Green New Deal and try to make progress on “what lies in the realm of possibility” under the current balance of power.
What’s that?
Tonko, chair of the House Energy and Commerce Committee’s Subcommittee on Environment and Climate Change, says he sees bicameral, bipartisan support for clean energy research; investments in EV charging infrastructure and grid modernization; workforce development; energy efficiency; and investment tax credits for energy storage.
“I don’t want to get trapped in the rhetoric of Green New Deal, no Green New Deal. l embrace many of the principles of the Green New Deal. But let’s move forward and develop science-based, evidence-based … policies that take us forward.”
Tonko wasn’t the only speaker who saw reason for optimism on climate policy, even at a time when CO2 levels have reached the highest level in 400,000 years.
Rich Powell, executive director of ClearPath, which supports nuclear power and “small government, free market” policies to nurture clean energy innovation, said he’s seen a change in Washington recently.
“If you watch the rhetoric in D.C. for the past six months, something pretty surprising has happened,” he said, recounting his experience testifying as a Republican witness at two House hearings on climate change.
“There was generally consensus that climate change is real; that global industrial activity from … human sources is a significant contributor to that, and that the federal government ought to take significant, ambitious action beyond what it’s doing now to tackle that challenge. I think there was consensus on that issue. So now I think we’re at a space where we can begin to move from a vigorous discussion of whether there is a problem meriting federal action to a vigorous discussion about the right solutions to that problem.”
“If you really just look at the environmental provisions … [the Green New Deal is] not actually that crazy,” said Aliya Haq, director of the Natural Resources Defense Council’s Climate and Clean Energy Program. “It’s extremely ambitious. But there’s no prescription. No policy about how we get there. It’s a blank slate for how we achieve these goals.”
Sarah Ladislaw, a senior fellow in the Energy and National Security Program at the Center for Strategic and International Studies, said the economic justice goals of the GND are also important.
“As we observe technological resource base changes that are taking place in the U.S., there’s actually a fair degree of commonality at the state and local level about what direction we should take,” she said. “It should broadly be lower carbon. It should definitely create jobs and economic opportunity. And it should make communities feel like they have a competitive part in this future.
“The problem, though, is that energy alone can’t sustain economic vitality at the local level. … So, one of the most attractive things about the Green New Deal is … the part of it that’s about trying to secure economic security and a greater degree of equality. … That’s the bigger political moment that we’re living in, and energy [policy] has this tendency to get carried along with those types of political sentiments.”
Bringing Clean Energy to the Developing World
Powell acknowledged setbacks, citing the loss of carbon-free nuclear generation and the expansion of coal-fired generation in the developing world.
“Right now, for a lot of the developing world, the right thing for pure [economic] development is coal. There are hundreds of new coal-fired power plants being built around the world. China has 250 more in its domestic pipeline in addition to the terawatt of … coal — average age 11 years — that are already [operating]. … They’re building at least another 100 GW around the world for their Belt and Road initiative.
“Too often in the past these facts — and they are brutal facts, they’re intimidating facts — have been used to shield against climate action. They’ve been used to saying, ‘Well, it doesn’t matter what we do here in the United States because all the other countries are going to make their own decisions.’ And I refuse to accept that. … Actually, we can do quite a bit about climate change.”
The solution, he said, is innovation that makes clean alternative generation as cheap as coal. “And that can be done, because we’ve done it here in the United States.”
Role for Innovation
Powell called for “technology-inclusive tax credits that cover all innovative, clean or very low-emission energy technologies and that permanently changes the incentive set for utilities … whenever they’re going to be building anything new.”
“I agree with Chairman Tonko that this is clearly a bicameral, bipartisan place where we can make a lot of progress on this issue,” he continued. “And I say that because we made a lot of progress on this issue in the last Congress,” citing passage of the 45Q Carbon Sequestration Tax Credit, the 45J Nuclear Production Tax Credit and other legislation on nuclear and storage innovation.
“So, we think there’s a broad, robust agenda where we can get started … on climate change immediately and use the United States as a test bed for global clean energy technology that can help decarbonize the rest of the world.”
Dominion Energy CEO Thomas Farrell, who moderated the EEI discussion, said it will be impossible to meet climate goals without nuclear power, citing research that electrification of transportation and other sectors could increase electric demand by 50%.
“To do that with zero-carbon [energy] — unless you can figure out a magic switch, carbon capture or something — you will need more and more and more renewables, which use enormous amounts of land,” he said. “Those of us who are actually doing this for a living are already getting very significant pushback from local jurisdictions saying, ‘I’m not going to change the zoning. … We have enough solar in our town; we don’t want any more solar.’”
NRDC’s Haq offered a cautionary note, citing research that even climate change “alarmists” are resistant to higher taxes on gasoline.
More sobering news came June 11 from Deloitte’s annual resources survey, which reported that while most businesses have increased their initiatives on sustainability, the action by residential consumers has lost momentum.
“Consumer complacency may be settling in as costs outweigh climate as a motivator in adopting new technologies and cleaner energy sources,” said Marlene Motyka, Deloitte’s U.S. and global renewable energy leader. “On the other hand, most businesses don’t perceive a choice between climate and cost. They see green energy choices as a win-win: Doing the ‘right thing’ is good for the environment and the bottom line.”
CARMEL, Ind. — MISO is toying with the idea of foreshortening its 2020 Transmission Expansion Plan (MTEP) process in order to maximize time spent on the 2021 cycle of transmission projects.
The RTO last week said it wants stakeholder approval to stop work on the four 15-year future scenarios used in the 2020 MTEP (requiring it to instead rely on an older version of futures) and to forego the usual planning studies in favor of smaller, specialized studies to identify projects.
MISO Planning Manager Tony Hunziker said the idea is to finish MTEP 20 work early to provide more time to completely retool the future scenarios in time for the 2021 cycle.
“Throughout this process, there’s been this building momentum and increased interest in starting MTEP 2021 futures as early as possible,” Hunziker told stakeholders at a Planning Advisory Committee meeting Wednesday.
Stakeholders asked if the 2020 plan would still contain an Appendix A, the annual list of transmission projects recommended to the Board of Directors for review and approval.
“There would certainly be an Appendix A and the usual reliability projects. This would more impact economic projects,” Hunziker said.
If MISO stops work on MTEP 20, it won’t have the usual Market Congestion Planning Study for the cycle.
“In its place, we could do a couple targeted economic studies,” Hunziker suggested. “We haven’t completely thought through everything yet. We wanted to put this out there and judge stakeholders’ interest.”
He assured stakeholders that MISO wouldn’t skip economic transmission planning for the year; it would just come in a different form.
“We’re still very committed to the economic planning process,” Hunziker said.
He said moving forward with MTEP 20 futures development would “tie staff up until mid- to late summer.”
“If we continue down the path of completing MTEP 2020 futures, it’s going to slide down the time that we can start on the 2021 futures,” Hunziker said.
Stopping work on MTEP 20 would pull staff’s focus entirely to developing MTEP 21 futures, he said. Staff have previously promised stakeholders an extensive rework of the four futures that guide the annual transmission planning process in time for 2021.
MISO had been using the same set of futures with only minor edits for the last three years to evaluate transmission projects. The RTO developed the futures in collaboration with stakeholders with long-term use in mind. (See MISO: Minimal Change to 2019 Tx Planning Futures.)
In April, MISO said it would boost renewable generation estimates in each of the four 15-year future scenarios, bumping minimum penetration levels from 15 to 35% of the generation mix to 20 to 40%. (See Renewables Outlook to Get Boost in MTEP 20 Futures.) However, MISO’s pivot puts that proposal in doubt, with Hunziker saying it could either keep or discard the larger renewable assumptions.
In halting further efforts on MTEP 20, MISO would likely begin 2021 futures discussions in July and schedule four special workshops in fall to gauge stakeholder expectations around a new set of futures.
“Either way we go, we’ll start the MTEP 2021 futures discussion early,” Hunziker said, adding that MISO would begin discussions on MTEP 21 with or without a MTEP 20 work stoppage by September. MISO usually begins futures development in January of each year for the upcoming year’s transmission planning cycle.
A Hijacking?
Some stakeholders pointed out the move would give MISO 27 months to develop futures, risking that enough time could pass for the freshly developed futures to themselves become stale. But Hunziker said the first few months would be spent on how to improve the process and settle on what new data should inform the scenarios.
Clean Grid Alliance’s Natalie McIntire asked how the move would affect MISO’s annual interregional transmission planning efforts with SPP and PJM. She said that because MISO no longer builds a joint model with its neighboring RTOs, it should keep up with grid modeling.
MISO staff said they weren’t yet sure how the new course of action would interact with next year’s interregional planning.
“I’m really surprised and concerned by this,” McIntire said. “It’s concerning that a small number of stakeholders can hijack the process,” suggesting that only a few influential members were in favor of truncating MTEP 20.
However, Xcel Energy’s Drew Siebenaler thanked MISO for proposing a “pared-down” MTEP 20. He said the move would give the RTO the time necessary to evaluate several new state and company renewable targets, new resource retirements and recent zero-carbon commitments for use in its futures.
“Who says we’re going to have that kind of clarity in five months?” consultant Roberto Paliza challenged. “I just don’t see that we’ll have a new set of futures that are radically different.”
“We’re just about done with the MTEP 20 discussion here,” McIntire said. “The whole idea that we would get rid of a big part of MTEP 20 … I don’t think that extra two months [for MTEP 21 futures] is going to be that significant.”
But Hunziker pushed back on that assertion, saying his staff don’t have time to properly facilitate both MTEP 20 futures and studies and early preparations on MTEP 21. He asked for more comments on the issue by June 28.
A tag team of ERCOT executives last week reviewed the grid operator’s summer preparations at the Board of Directors’ last meeting before the big heat. Judging by the few questions from the board, the presentation was well received.
Staff have said they expect to use emergency measures this summer to meet a record forecasted peak demand of 74.9 GW. ERCOT has available capacity of 78.9 GW and a reserve margin of 8.6%. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)
The June ERCOT Board of Directors meeting.
Dan Woodfin, senior director of system operations, told the board that ERCOT expects to “implement energy emergency alerts several times this summer.” He said the alerts would allow it to take advantage of the extra 2 to 3 GW of resources available “only in those limited situations.”
The grid operator does not expect any “wide-area reliability concerns,” Woodfin said. He said Far West Texas may see some congestion from oil and gas and solar development, and areas in the Texas Hill Country and the Rio Grande Valley could experience congestion as well.
The ERCOT system could get a boost if weather forecasts predicting cooler temperatures than the summer of 2018 — when the grid operator set a new peak demand of 73.5 GW — prove accurate. Senior Meteorologist Chris Coleman said it’s “unlikely” to be as hot as last summer, pointing to the ninth-wettest year on record for Texas.
“Wetness tends to suppress heat, to some extent,” Coleman said. He is projecting almost half as many 100-degree days in various Texas cities than last year (five to 14 in Austin, compared to 41 in 2018).
| ERCOT
Kenan Ögelman, ERCOT’s vice president of commercial operations, reminded the board of two Public Utility Commission-mandated changes to the operating reserve demand curve (ORDC), which provides a price adder when generation is scarce.
The grid operator will now blend 24 different ORDC curves, based on season and hour blocks, into one curve that aggregates all the data. This will raise adders above 2 GW of reserves during the summer months, but lower them in the winter, Ögelman said.
The PUC also directed ERCOT to shift the ORDC curve by 0.25 standard deviations, which Ögelman said will create a higher adder for any level of reserves above 2 GW.
IMM Market Report: Load Continues to Climb
The ERCOT Independent Market Monitor’s 2018 State of the Market report says the wholesale market performed “competitively” last year, but it also includes some future warning signs.
In briefing the report, which was filed at the PUC on June 5, IMM Director Beth Garza told the board that load is increasing in all four ERCOT load zones, led by a 15.4% increase in average real-time load from 2017 in the West zone, which includes the petroleum-rich Permian Basin. The average load in the North zone, home to Dallas and Fort Worth, increased 6.5% over 2017, and it was up 5.3% for the ERCOT system.
“There’s substantial load growth everywhere. There’s no other word to describe it,” Garza said.
IMM Director Beth Garza presents an overview of the 2018 State of the Market report.
She said the additional load amounts to a 2.2-GW increase each hour, noting, “That’s like two new combined cycle [generating units] to serve load every hour.”
Given the ever-increasing load, Garza said, “In 2022, the existing fleet is no longer sufficient to serve peak load.”
As it is, the IMM report said system shortages increased in 2018, with about 17 hours of prices above $1,000/MWh. The Monitor expects the trend to continue in 2019.
“What seem like very low reserves may just be the new normal,” the report says. “Given the overall size of the system and projected growth, a more robust reserve margin may no longer be required to cover load forecast errors and mitigate generator availability risks.”
The report also said with distributed generation playing an “increasingly important role in ERCOT, the risk associated with generator outages should decrease.”
Overall, ERCOT’s average prices climbed to $35.63/MWh, a 26% increase from 2017. Higher natural gas prices helped drive the increase, up 8% to $3.22/MMBtu.
The grid operator’s real-time market experienced a 30% increase in congestion costs, which totaled $1.26 billion. The IMM said a costly, localized constraint in Far West Texas was the primary culprit.
The report offers three recommendations to improve the reliability commitment process and resulting pricing:
Evaluate and improve the reliability deployment price adder, which the IMM says is producing results “inconsistent with its original intent.”
Explore options to consider commitment costs for RUC-committed units.
Eliminate the opt-out option for RUC-committed resources.
“Continuing to have the opt-out option is an incentive to withhold capacity,” Garza said. “In our decentralized market, where we count on people to make their own best decisions, the incentives in front of us lead to a situation where people are incented not to commit.”
Senate Bill 1938 gives incumbent utilities the first shot at building transmission projects in the state. The bill, which went into effect immediately after Gov. Greg Abbott signed it May 16, will require ERCOT to modify its transmission planning process to no longer designate transmission provider endpoints.
A second law already in effect — SB475, signed June 7 — creates a Texas Electric Grid Security Council composed of Magness, PUC Chair DeAnn Walker and a designee of Abbott. Magness said Walker will chair the council, which will begin meeting later this year.
SB936, signed June 10 and effective Sept. 1, requires ERCOT and the PUC to contract with an entity to serve as the commission’s cybersecurity monitor. It will be funded by the grid operator’s system administrative fee, Magness said.
Magness also celebrated a two-year delay in the grid operator’s sunset review, which also applies to the PUC and the Texas Office of Public Utility Counsel (OPUC). The review has been pushed back to 2024/25.
ERCOT CEO Bill Magness makes a point.
“While we always welcome sunset reviews, we’re happy for it to be in 2024 and 2025,” he cracked.
ERCOT’s positive year-end variance to budget has slipped slightly, from $34 million to $33.2 million, still boosted by a large gain in interest income ($18.7 million), Magness said.
Telemetry Data Blamed for Market Event
Ögelman told the board that a May 30 market event that briefly resulted in $9,000/MWh prices was the result of the security-constrained economic dispatch system receiving bad telemetry data.
“This happens,” Ögelman said. “Normally for very short durations, but it doesn’t hit the SCED. This hit the [market] run.”
The telemetry data indicated about 5,000 MW of resources wanted to move down during an interval, he said, and when the market didn’t respond quickly enough, the SCED engine used regulation up to get the ramp it thought it needed. Energy on the power balance penalty curve, used by ERCOT to price ancillary services such as regulation up, hit $9,000.01/MWh for about 2.5 minutes before operators, sensing something was wrong, reran SCED and corrected the data.
The blip resulted in settlement prices of as much as $1,500/MWh in some load zones for one 15-minute interval, Ögelman said.
Staff investigated the event but determined it didn’t warrant a price correction, according to ERCOT’s Protocols.
“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman said. Telemetry data are owned by the resources, not the grid operator.
He said staff would look into strengthening its telemetry data and follow up with stakeholders to evaluate alternatives.
TAC Vice Chair Coleman Leaves for CPS
Technical Advisory Committee Chair Bob Helton said the committee will “bring on” a new vice chair before the next board meeting, replacing longtime member Diana Coleman, who has left OPUC to take a position at CPS Energy, San Antonio’s municipal provider.
Coleman had served as the TAC’s vice chair since 2018, when Helton moved up from vice chair to chair to replace Adrianne Brandt when she also left for CPS.
Board Approves Budget, Change Requests
ERCOT’s system administrative fee will remain at 55.5 cents/MWh through 2021 as a result of the board’s unanimous approval of the 2020/21 biennial budget. The fee has remained level since 2016.
The board approved $268.3 million and $275.2 million for operating expenses, project spending and debt-service obligations for 2020 and 2021, respectively.
The board also approved seven Nodal Protocol revision requests (NPRRs), a change to the Nodal Operating Guide (NOGRR), two new Other Binding Documents (OBDRRs), two Planning Guide additions (PGRRs) and a system change request (SCR) on its consent agenda:
NPRR885: Adds new language to address the solicitation and operation of must-run alternatives, as directed by the PUC (Project 46369). The commission ruled that a resource entity must file a notification of suspension of operations at least 150 days prior to the date on which it intends to cease or suspend operations; within the 150-day notice period, ERCOT must determine whether the resource is needed for reliability.
NPRR896: Outlines the process to evaluate the cost-effectiveness of procuring reliability-must-run service or one or more must-run alternatives.
NPRR921: Replaces all instances of the “all-inclusive generation resource” and “all-inclusive resource” terms with “generation resource and settlement-only generator (SOG)” and “generation resource, settlement-only generator and load resource,” respectively. Eliminating the all-inclusive generation resource enables ERCOT to more narrowly tailor the requirement’s applicability to a reasonable scope.
NPRR923: Updates the weather-sensitivity process by allowing transmission and/or distribution service providers an additional 30 days to complete the investigation and execution of requests to revise electric service identifier (ESI ID) load profiles.
NPRR924: Moves the Independent Market Information System Registered Entity Application for Registration form into a section of the Nodal Protocols that houses similar forms.
NPRR926: Removes the 90-day period between subsynchronous resonance (SSR) study approval and initial synchronization, clarifies that the SSR mitigation plan is part of the SSR study and adds an ERCOT review process that gives the grid operator 30 days to review the SSR study. The change also gives ERCOT 45 days to implement any required SSR monitoring after the study’s approval.
NPRR929: Adds new criteria for determining whether a point-to-point (PTP) obligation with links to an option bid is eligible to be awarded based on the resource’s current operating plan (COP) status at the node where the bid sources. Bids will not be eligible for awards if they source at a resource with a COP status of “OUT” or “OFF” and the resource is not offered into the day-ahead market.
NOGRR185: Uses the terms created in NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the NOG.
OBDRR013: Changes the current single-value voltage categories of 345, 138 and 69 kV used to define generic transmission shadow price caps for N-1 constraint violations to accommodate Lubbock Power & Light’s transmission equipment, which does not fall into the three existing categories. The ranges are: greater than 200 kV ($4,500/MW), 100 to 200 kV ($3,500/MW) and less than 100 kV ($2,800/MW).
OBDRR015: Sets the value of lost load (VOLL) equal to the systemwide offer cap, which changes the high cap to the low cap should the peaker net margin exceed its threshold within an annual resource adequacy cycle.
PGRR069: Uses terms created by NPRR889 to replace “all-inclusive generation resource” and “all-inclusive resource” in the Planning Guide. The PGRR also clarifies the applicability of the generation interconnection or change request process to different generators, based on NPRR889.
PGRR070: Aligns the Planning Guide with NERC Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
SCR799: Enables ERCOT to provide transmission service providers its current month, 60-day and 90-day outage study cases in the system operations test environment on a monthly basis.
