CenterPoint Energy (NYSE:CNP) said Friday it plans to increase its 10-year capital plan to $43 billion through 2030, with a focus on additional investments in grid reliability and modernization.
CEO David Lesar told analysts on an earnings call that the company has added $2.3 billion to the capex plan and identified an additional $3 billion of potential opportunities that will be folded in “when we believe we can operationally execute it, efficiently fund it, and minimize the regulatory lag associated in recovering it.”
The Houston-based utility reported fourth-quarter earnings of $122 million ($0.19/share) and year-end earnings of $1.01 billion ($1.59/share), compared to $641 million ($1.01/share) and $1.39 billion ($2.28/share) for the same periods in the previous year.
“We continue to execute well; 2022 was truly an exciting and productive year,” Lesar said during the call. “We are confident that this strong momentum will continue into the new year.”
He noted it was the 11th straight quarter CenterPoint has exceeded or met its own expectations for earnings guidance. Lesar has been CEO for the last 10 of those quarters.
The infrastructure investment will be needed. Texas has added nearly 1.1 million jobs since the COVID-19 recession, Lesar said. Houston, CenterPoint’s primary electric service region, has added 179,000 jobs and increased its population by almost 300,000 to nearly 7 million, he said.
“This is now like adding a city the size of Irvine, Calif., to our footprint in just one year,” Lesar said. “We see this trend continuing as the Texas miracle keeps humming along.
“This growth is just one of the reasons we believe we are uniquely positioned as a company.”
The company’s share price closed at $29.22 Friday, a gain of 16 cents on the day.
Entergy Takes Hit from Grand Gulf
Entergy (NYSE:ETR) on Thursday reported earnings of $106 million ($0.51/share) for the quarter and $1.1 billion ($5.37/share) for the year. That compared to $259 million ($1.28/share) for 2021’s fourth quarter and $1.12 billion ($5.54/share) for the year.
The results included a $551 million charge, $413 million after tax, for System Energy Resources Inc. (SERI), the Entergy subsidiary that owns the Grand Gulf Nuclear Station in Mississippi. FERC in December issued two orders involving the plant’s customer rate impacts. The orders addressed a series of uncertain tax positions that SERI took.
“We still believe that a global settlement with the remaining retail regulators on terms similar to the agreement with the MPSC would be in the best interest of all parties,” Entergy CEO Drew Marsh told financial analysts during the quarterly conference call. “It would resolve disruptive litigation uncertainty for SERI and our stakeholders, including our regulators, accelerate meaningful value to customers, avoid costly and unnecessary third-party litigation fees and allow all parties to move forward with fewer distractions.”
Entergy’s earnings exceeded Zacks Investment Research projections of $0.45/share. Entergy’s share price ended the week at $109.42, up $1.87 from Wednesday’s close.
FERC on Thursday dismissed a complaint from RENEW Northeast that had alleged that ISO-NE has “undue preference” for gas generators in its capacity accreditation and operating reserve rules (EL22-42).
The complaint from March of last year argued that ISO-NE doesn’t adequately take into account the uncertainty of natural gas supply in the region, particularly in winter, and that it therefore harms almost every other type of generation. (See Renewable Groups Challenge Gas ‘Preference’ in ISO-NE Rules.)
The complaint has been closely watched in New England, and FERC received many comments on both sides of the argument.
Ultimately, the commission found that RENEW failed to meet its burden under Section 206 of the Federal Power Act to show that the existing tariff is unjust and unreasonable.
Specifically, FERC wrote in its dismissal order that RENEW “failed to establish that gas-only resources are not similarly situated to generators with fuel on site.”
As for the complaint’s points on operating reserves, FERC noted that, contrary to what RENEW claimed, the ISO-NE tariff doesn’t require any resource to “have a known and measurable fuel supply and verifiable means of delivering upon real time dispatch.”
But in dismissing the complaint, FERC also called on ISO-NE to step up.
“We urge prompt action by ISO-NE on reforms, including capacity accreditation if deemed appropriate, to address these reliability concerns,” the commission wrote, adding that it is planning another forum on winter reliability issues in New England for June.
ISO-NE spokesperson Matt Kakley emphasized that the grid operator is continuing to work on updating its capacity accreditation rules through the stakeholder process.
“We’re pleased that FERC dismissed this complaint. To date, the region’s markets, including the capacity market, have achieved their primary reliability objective, but an overhaul of the capacity accreditation process is critically important as the region transitions to the future grid,” he said in a statement.
“To that end, ISO New England and stakeholders have been working on this issue for more than a year, with plans to file a proposal with FERC later this year. With this complaint formally dismissed, ISO New England and others can now engage with FERC commissioners and staff, benefiting from their views and expertise as the region navigates this important process.”
Clements’ Concurrence
Commissioner Allison Clements went a step further than the rest of the commission. In a forceful concurrence, she wrote that she believes the ISO-NE tariff is in fact unjust and unreasonable, even though the commission had to dismiss RENEW’s complaint because of what she called a “pleading error.” And she called on FERC to take action itself.
“In the face of clear evidence that ISO-NE’s rules fail to ensure the supply of resources when they are most needed, in my view the commission has a duty to take action to ensure grid reliability,” Clements wrote.
Clements noted that everyone, including ISO-NE, agrees that the region faces gas delivery constraints that can threaten energy security, especially during extended extreme winter weather.
“Given this apparent agreement that ISO-NE’s rules are failing to assess the reliability of resources when they are most likely to be needed, in my view the Commission has a duty to fix the problem via action pursuant to section 206 of the Federal Power Act,” Clements wrote. “We cannot stand idly by as the region heads toward yet more winters for which it is not adequately prepared.”
And she also suggested that she is wary of what ISO-NE might put forward in its formal capacity accreditation process.
“In my time at the commission, thus far it has accepted almost every significant capacity accreditation proposal put forward by an RTO or regional framework,” she wrote. “My view has been that some of these proposals met the requirements of the Federal Power Act, while others did not.
“As these decisions mount … they contribute to a slow but steady erosion of the commission’s bedrock legal standard that rate proposals must be just and reasonable and not unduly discriminatory,” Clements wrote.
FERC last week accepted a set of revisions to PJM’s tariff that the RTO proposed through its Quadrennial Review of the parameters underlying its Reliability Pricing Model (RPM) auctions (ER22-2984).
The Feb. 14 order accepted all the changes sought by PJM, sanctioning a market design with a steeper variable resource requirement (VRR) curve intended to procure a smaller amount of capacity hewing closer to the reliability requirement. The new paradigm also switches the reference resource used to determine the cost of new entry (CONE) from a combustion turbine to a combined cycle generator.
“This Quadrennial Review proposal was developed with an unprecedented level of stakeholder input and appropriately reflected stakeholder priorities,” PJM spokesperson Jeff Shields said in response to the order. “The new VRR curve is an improvement on the prior VRR curve, as it achieves a better balance between reliability and cost by procuring resources based on the reliability standard, thus meeting reliability requirements at a reasonable cost while incentivizing investment in new generation resources.”
Steeper VRR Curve
Pointing to market simulations conducted by the Brattle Group, PJM said the existing VRR curve over-procures capacity and results in an average loss-of-load expectation (LOLE) of one in 17 years, which it states is “significantly greater” than the target of one in 10. The new market design was simulated by Brattle to produce a LOLE of one in 14.
The new shape shifts the foot of the curve, the lowest point, about 2.2% to the left of the reliability requirement to “help prevent costly impacts of overestimations of net CONE, which would result in more reliability than expected,” PJM said in its filings.
PJM also changed the calculation for setting the capacity price cap, the highest point of the curve, to be set at the greater of the gross CONE or 1.75 times net CONE. The shift away from the current cap set at 1.5 times net CONE is intended to address the possibility that market conditions could change in the gap between the Base Residual Auction’s (BRA) and the delivery year and result in an underestimation of net CONE and therefore an under-procurement of capacity.
The PJM Power Providers (P3) protested the changes, saying that the steeper curve, combined with the other changes the RTO proposed, would result in increased volatility and compound the price impacts of each market design change. (See PJM Defends Quadrennial Review Parameters from Generator Protests.)
The Independent Market Monitor noted in its comments that the proposal moves closer to its recommendation of rotating the curve halfway toward a vertical demand curve, which would have created a much steeper curve. The Monitor’s analysis found that the recommendation would have reduced the 2023/24 BRA’s revenues by $406 million, or 18.5%. (See IMM Offers Mixed Review of PJM Quadrennial Review Docket.)
Forward-looking EAS Offset Calculation
The market design changes also include switching from using historical data to calculate energy and ancillary services (EAS) revenues to a forward-looking approach to calculating the EAS offset.
The change was supported by several environmental and public interest groups in a joint filing stating that a forward-looking EAS offset would be more responsive to an evolving resource mix, fuel prices and future market conditions.
The Monitor also supported the change, stating that the proposed approach reflects how investors evaluate the market and avoids overstated capacity market prices stemming from an EAS offset being based on historically low prices in the PJM markets as current and forward-looking energy prices have increased significantly.
In its protests, P3 said the use of futures prices would increase market uncertainty and volatility. By using proprietary data and models in its calculations, P3 also said that the proposal lacked transparency and limited market participants’ ability to estimate how future EAS revenues would be determined.
In accepting the forward-looking approach, the commission wrote that it relies on the same data developers use to assess project viability and that prices from liquor futures markets produce prices reflecting future conditions.
“We find that PJM’s proposed use of futures prices to calculate the EAS offset is just and reasonable because the record indicates that futures prices better reflect PJM market participants’ expectations of future market conditions as compared to historical electricity prices,” the commission said. “Indeed, P3 provides no evidence that market participants themselves use historical prices to predict future prices. PJM, on the other hand, supports its claim that market participants use futures prices.”
The commission also said that this was in line with an “almost identical” that it approved in 2020 (EL19-58).
PJM had previously sought to shift to using futures data as part of a 2019 filing revising its reserve markets and received FERC approval the following year, but the commission reversed itself in 2022. In overturning the previous order, the commission said its reversal of the reserve penalty factor and operating reserve demand curve (ORDC) “undermined the fundamental basis” for its determination that the historic offset was unjust and unreasonable. (See FERC Reverses Itself on PJM Reserve Market Changes.)
Change to Combined Cycle Reference Resource
Shifting away from its longtime usage of combustion turbines as the reference resource, PJM proposed to use a combustion cycle generator as the resource type that is most likely to be constructed to meet a capacity shortfall in the future. The RTO noted that the last combustion turbine built in its footprint was in 2018, and the Monitor wrote that no “significant level” of capacity has been installed since 1999.
P3’s protest stated concerns that using a combined cycle would come with a higher and more variable EAS offset. It said that higher profits in those markets could lead to a lower net CONE, lower relative capacity prices and ultimately less capacity clearing even if a higher supply is needed.
“Based on the record as a whole, we find P3’s concerns to be overstated,” FERC said. “As Brattle explains, perverse incentives will not be substantially different for combined cycle plants than for combustion turbines because both combined cycle plants and combustion turbines are usually operating as load approaches peak load, which is when energy prices are more sensitive to supply conditions.”
Amortization Period
The commission also overruled a protest from J-Power USA stating that the amortization period used in the calculation of gross CONE doesn’t take into account legislation that would shorten the lifespan of a generator, namely Illinois’ Climate and Equitable Jobs Act (CEJA).
The company pushed for a shorter amortization in the ComEd locational deliverability area (LDA) to reflect the requirement that generators be carbon free by 2045, which the protest said would result in the early retirement of gas generators, including the combined cycle unit reference resource.
The commission noted that PJM stated it would be inappropriate to change the period for the ComEd transmission zone without changing the parameters for the rest of the CONE area and that CEJA contains a carveout to allow generators to continue operating outside the emissions requirement if deemed necessary for reliability.
Danly and Christie Reluctantly Concur
Commissioner James Danly wrote that while he is in agreement that the Quadrennial Review filing meets the requirements of Federal Powers Act Section 205, he believes that the protests to its provisions show that the commission should consider a broader examination of PJM’s capacity market.
“The time is ripening for the commission to investigate whether the PJM rate construct (including the capacity market) is just and reasonable and not confiscatory,” he wrote. But in this section 205 proceeding, I agree — reluctantly — that PJM has made the required showing that these piecemeal proposals are just and reasonable.”
Commissioner Mark Christie also said that the larger functioning of the capacity market was the “elephant in the room” as the commission examined the Quadrennial Review.
“Moreover, we cannot ignore the events of last Dec. 24 and 25: Winter Storm Elliott,” Christie said. “One of the common criticisms over the years has been that the PJM capacity market procures too much capacity, yet during at least two recent extreme weather events — the polar vortex of 2014 and Winter Storm Elliot last December — PJM reportedly came very close to ordering rotating outages. … My point in this concurrence is not to analyze, favor or criticize earlier changes to the capacity market construct or propose new changes; my point is a larger one: that these events raise important broad questions about this capacity construct’s efficacy.”
Consolidated Edison (NYSE:ED) released its 2022 earnings report late Thursday night, showing that it earned $1.66 billion in net income ($4.68/share), about $300 million, or 23%, more than in 2021.
The increase was slightly more than that of 2021, which saw earnings increase by about 22%. (See Con Edison 2021 Earnings Jump 22%.)
Earnings for the fourth quarter, however, were down about 15% from the same period in 2021: $190 million ($0.53/share), compared to $355 million ($1/share).
ConEd corporate structure | ConEd
CEO Timothy Cawley said in a statement that “the great work of our employees and our customers’ desire for a clean energy future enabled us to make tremendous progress in 2022 in energy efficiency, new [electric vehicle] charger installations and customer solar projects.”
The New York-based utility, which services parts of New Jersey via Orange & Rockland Utilities, sold its Clean Energy Businesses (CEB) portfolio of 3,300 MW in renewable energy projects to RWE Renewables America in 2022. The deal is valued at $6.8 billion and anticipated to close near the end of the first quarter. (See Con Edison to Sell Clean Energy Businesses for $6.8B.)
ConEd return performance | ConEd
According to its earnings report, Con Ed spent months considering “strategic alternatives” for the CEB but concluded that the transaction would allow it to “focus on our core utility businesses and the investments needed to lead New York’s ambitious clean energy transition,” Cawley said in a statement in October.
Con Ed intends using funds from the CEB sale to repay $1.25 billion of parent company debt in 2023, repurchase up to $1 billion of its common shares, forego common equity issuances in 2023 and 2024, and issue up to $900 million of common equity in 2025.
The company also issued $366 billion as part of the COVID-19 arrears assistance program, which the New York Public Service Commission created to help reduce the arrears balances of residential and small commercial customers struggling after the pandemic. Phase 2 of the program started in January, and Con Ed approximates that $392 million credit is eligible for the program.
Con Ed also announced on Wednesday that its customers installed a record 9,600 solar projects last year, which have the capacity to produce 89 MW.
The company expects 2023 adjusted earnings per share to be between $4.75 to $4.95 because of the anticipated CEB sale. It forecasts an average annual increase in peak demand over the next five years for electricity and gas to be approximately 0.6% and 1%, respectively.
Con Ed also plans to issue approximately $2.6 billion in long-term debt, including for maturing securities, during 2024 and 2025.
Oregon is eligible to rake in hundreds of millions of dollars in funding for building electrification, energy efficiency and grid resilience through federal grant and tax credit programs established over the past two years.
But so far, the state has received just $200,000 from the feds, despite Congress having passed the $1.2-trillion Infrastructure Investment and Jobs Act (IIJA) a year-and-a-half ago.
On Wednesday, Oregon Department of Energy (ODOE) Director Janine Benner appeared to counsel patience for the utilities, companies and other organizations looking to tap that funding stream.
“It takes time to get the money through the federal process, and it will take time to get the money through the state process, so I think a lot of folks are working as hard and fast as they can,” Benner said Wednesday during an agency webinar on the status of the state’s funding under the IIJA and the Inflation Reduction Act (IRA), which was passed last August. (See Senate Passes Inflation Reduction Act.)
The $200,000 already received was IIJA funding awarded under the U.S. Department of Energy’s State Energy Program (SEP) and is targeted at improvements to Oregon’s energy security plan. ODOE in December applied for the remaining balance of the $5.6 million in SEP formula funding available to the state under the IIJA, money to be used “to provide technical assistance to consumers and communities as well as to facilitate research, analysis and programs on energy efficiency, renewable energy, sustainable transportation, and resilient energy systems,” according to Jennifer Senner, ODOE’s federal grants officer.
Senner said Oregon is also preparing applications for:
$50 million in IIJA formula funding for grid resilience, which the state must match at 15%. Utility recipients that sell more than 4,000,000 MWh annually will then be required to match their state grants at 100%, while those selling less than that amount must match at one-third.
$1.3 million from the IIJA’s Energy Efficiency Revolving Loan Fund Capitalization Grant Program, which provides grants and loans to conduct commercial and residential energy audits and perform EE upgrades and retrofits of buildings.
$1.9 million from the IIJA’s Energy Efficiency and Conservation Block Grant Program for projects that reduce home carbon emissions and improve energy efficiency.
Oregon will also be eligible for a total of $113 million in IRA formula funding under the HOMES program, which incentivizes contractors and installers for improving the energy performance of houses, and the High-Efficiency Electric Home Rebate (HEEHR) program, which offers cash to low- and moderate-income households that switch to electric heating and appliances (such as heat pumps), upgrade electric panels and wiring to accommodate new equipment, and improve their home’s energy efficiency.
“While there’s a lot we still don’t know about these funds, we anticipate we will be submitting an application for them either in the summer or the fall, and that the funds will be available in either late 2023 or early 2024 to support these residential upgrades related to homes,” Senner said.
ODOE is also exploring IRA programs related to workforce training, including the training of contractors who would assist in implementing the residential energy efficiency upgrades under the HOMES and HEEHR programs. Senner said it is still not clear whether those grants would be competitive or offered under formula funding for all states.
Senner noted that ODOE is participating with the Washington Department of Commerce and others in the Pacific Northwest Hydrogen Association (PNHA), which was created to win a portion of the $8 billion in funding the Biden administration is targeting for the development of regional hydrogen hubs across the country. The DOE has encouraged the PNHA to submit a full application for a matching grant after reviewing the association’s concept paper. (See DOE: 33 of 79 Preliminary Hydrogen Hub Applications Chosen.)
‘A Huge Opportunity’
Senner said Oregon is also seeking to tap money from the U.S. EPA’s Greenhouse Gas Reduction Fund, which was established to prompt private capital to finance GHG-reduction projects, and the Climate Pollution Reduction Grants program, which is targeted at states, territories, tribes, air pollution control agencies and local governments to implement emissions-reduction plans. She said Oregon might be able to get an early jump on this funding because it already has advanced GHG plans in place.
ODOE “will consider equity at every step” in the process of spreading the federal funds, including considering the “geographic diversity” of recipients, Benner said, referring to the state’s sharp urban-rural divide, partly a product of income disparities between wealthier metro areas and lower-income rural towns.
“We will try to coordinate with tribal governments, and we’ll work to communicate clearly, inclusively and efficiently to ensure stakeholders and the public are informed and supported and that they’re able to participate in federal funding opportunities,” she said. She added that the agency will take guidance from the Biden administration’s Justice40 initiative, which aims to distribute at least 40% of the funds to disadvantaged communities.
Senner said ODOE is still “waiting on quite a bit of guidance” from federal agencies on the various programs, particularly those related to the IRA.
“It’s a bit overwhelming with the amount of funding federal funding coming our way, but it’s a huge opportunity for the state to make significant progress on our clean energy and climate change goals,” Benner said.
The New York Public Service Commission on Thursday approved 62 transmission upgrades with a combined capacity of 3.5 GW and an estimated cost of $4.4 billion.
The projects in three upstate regions are needed to loosen existing constraints in preparation for the state’s transition from fossil fuel-generated electricity to substantially larger amounts of clean renewable energy, according to the commission.
The price tag is only an estimate, and the final cost could range anywhere from $3.3 billion to $6.6 billion, which is a standard range of uncertainty for such projects, said Elizabeth Grisaru, deputy director of the Department of Public Service’s Office of Electric, Gas & Water.
The resulting monthly increase in customers’ bills could range from 3% to 16%, though success with the projects would prevent curtailment risk charges being passed from generators to utilities to ratepayers, she said.
The large price tag — and the fact that it is only one of many costs to be borne by ratepayers through the clean energy transition — gave some commissioners pause, but the majority voted for it.
The 62 upgrades are planned by Central Hudson Gas & Electric, National Grid, New York State Electric & Gas and Rochester Gas and Electric. The projects are focused in three areas of concern: the Hudson Valley and Mohawk Valley, extending south and west from Albany; the North Country, from the western Adirondacks to Lake Ontario and the Canadian border; and the Southern Tier, along the Pennsylvania border.
The utilities said there is 689 MW of existing solar and wind generation in these areas and 3,529 MW in some stage of development.
The work will be completed through the coming decade. Costs will be allocated across ratepayers statewide, as the benefits of decarbonization will extend to all New Yorkers.
Grisaru told commissioners that the projects were a result of the state’s Climate Leadership and Community Protection Act (CLCPA), the landmark 2019 law that codified decarbonization goals including 70% renewable energy by 2030. The concurrent transition to electric vehicles and all-electric buildings will create added power demand statewide.
Passage of the Accelerated Renewable Energy Growth and Community Benefit Act led the PSC in May 2020 to start a proceeding to plan the transmission infrastructure needed to accommodate these changes.
The three upstate regions were identified as problem zones in September 2021, and the utilities were directed to submit plans for upgrades.
Grisaru said the 62 projects are a snapshot estimate by the utilities, circa late 2021, of their future needs, but more generation projects have gone into development since then, and further transmission upgrades may be needed. Based on this, the package of 62 upgrades is a very conservative response to present and potential future needs, she said, with little risk of over-construction.
“I’m happy to see this project before us today,” PSC Chairman Rory Christian said. “We understand that to successfully decarbonize, we need to have a robust transmission system, and I’m encouraged that these investments will not only help us achieve that goal but help secure New York’s role as a leader in clean energy going forward.”
NYISO has highlighted the need for grid upgrades, and it did so again after Thursday’s vote.
“As stated in the NYISO’s 2021-2040 System & Resource Outlook, significant investments in generation and transmission projects are needed now to maintain the reliability and resiliency of our grid moving forward,” ISO spokesperson Kevin Lanahan said via email. “We’ll continue to work closely with elected officials, regulators and stakeholders to keep the grid working for all New Yorkers.”
The order was approved 5-2, with Commissioners Diane Burman and John Howard opposed. Both agreed with transmission expansion, but not with the mechanism by which the cost is being reviewed and allocated. They thanked Grisaru and her staff, however, for noting the uncertain cost of the upgrades.
Commissioner John Maggiore wished the state’s progressive income tax could cover some of the cost, rather than all of it falling on ratepayers.
Commissioner James Alesi recalled the great delays and cost overruns with the Second Avenue Subway project in Manhattan and said he worried about the unknown future costs of CLCPA rollout, which is currently being estimated at $275 billion — about $14,000 per person, or $37,000 per household statewide.
The PSC has divided transmission upgrades that have been proposed to accommodate expanded renewable energy in the wake of CLCPA into two categories: Phase 1, which also incorporates safety and reliability considerations, and Phase 2, which solely to supports new resources. Thursday’s order was the first Phase 2 approval by the PSC.
Pacific Gas and Electric pleaded not guilty Wednesday to 11 charges stemming from the September 2020 Zogg Fire, including four counts of involuntary manslaughter and three felony charges of recklessly starting the wildfire.
The California Department of Forestry and Fire Protection (Cal Fire) determined that a pine tree falling onto a PG&E power line ignited the 56,000-acre blaze in forested areas of Shasta and Tehama counties. It killed four people who could not escape the flames, including a mother and her 8-year-old daughter, and destroyed more than 200 structures.
PG&E said in a statement Thursday that it intends to fight the charges filed by the Shasta County District Attorney’s Office. The judge set a tentative trial date of June 6, but PG&E could settle the case rather than go before a jury.
“As we have stated previously, we accept Cal Fire’s determination that a tree falling into our powerline caused the 2020 Zogg Fire,” the utility said. “However, we believe PG&E did not commit any crimes, and that the conduct of our coworkers and contractors reflects good-faith judgment by qualified individuals. We have informed the court that we intend to defend ourselves against the remaining charges.”
On Feb. 1 a judge dismissed 20 of the 31 charges filed by the prosecutor’s office but said there was sufficient evidence to try PG&E for seven felonies and four misdemeanors. (See PG&E Can be Tried Again for Manslaughter.)
Under California law, involuntary manslaughter, a felony, is a category of homicide in which the defendant is alleged to have committed a lawful act “which might produce death, in an unlawful manner, or without due caution and circumspection.”
The district attorney’s office said in its September 2021 criminal complaint that PG&E had failed in its “legal duty to safely operate electrical transmission and distribution lines in a manner that minimizes the risk of catastrophic wildfires” by failing to clear the damaged and dangerously leaning pine tree.
When the charges were filed, PG&E CEO Patti Poppe said “two trained arborists walked this line and, independent of one another, determined the tree in question could stay.”
“We trimmed or removed over 5,000 trees on this very circuit alone,” Poppe said.
The Zogg Fire was the second time that the state’s largest utility has been charged with manslaughter.
PG&E pleaded guilty in June 2020 to 84 counts of involuntary manslaughter and one count of arson in the Camp Fire, which destroyed much of the town of Paradise on the morning of Nov. 8, 2018. A 100-year-old C hook on a PG&E transmission tower broke, allowing a line to drop and spark dry vegetation below.
The Camp Fire and a spate of Northern California wine country fires in October 2017 forced the utility into bankruptcy and led to a multibillion-dollar settlement with fire victims.
WASHINGTON — FERC on Thursday approved two new NERC reliability standards in response to the February 2021 winter storm that nearly led to the collapse of the Texas Interconnection (RD23-1).
According to FERC staff, EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) implement about half of the standards-related recommendations from the commission’s joint inquiry with NERC into the Texas grid operator’s poor performance during Winter Storm Uri.
The standards require generator owners to implement several measures to prevent their units from freezing during extreme cold-weather events. These include constructing retrofits at existing units based on the “extreme cold weather temperature” where they are located, defined as the lowest 0.2 percentile of the hourly temperatures measured in December, January and February since Jan. 1, 2000.
Owners will be required to submit corrective action plans if the temperature is at or above the unit’s designated extreme and one of the following occurs:
a forced derate of more than 10% of the total capacity of the unit, and exceeding 20 MW, for longer than four hours in duration;
a start-up failure where the unit fails to synchronize within a specified start-up time; or
a forced outage.
Generator owners and operators will also need to conduct annual staff training on cold weather preparedness and develop procedures to improve the coordination of load-reduction measures during an emergency.
“These new standards will help to prepare our nation’s grid and our grid operators so they can provide power to consumers in the face of extreme weather,” acting FERC Chairman Willie Phillips said in a statement. “I am pleased that NERC and its regional entities acted swiftly to propose these reliability standards so that my fellow commissioners and I could move decisively and vote today to ensure the reliability and resilience of the bulk power system.”
Despite unanimous approval at FERC’s open meeting Thursday, the commission acknowledged that more work needs to be done. Project 2021-07 is only Phase 1 of a three-phase process at NERC in response to the storm, and staff noted that more proposed standards will be brought before the commission by the end of the year to address the second half of the relevant recommendations.
Standard’s Shortcomings
FERC also found EOP-12-1 to be lacking, and it directed NERC to revise it to “to clarify certain language, enhance certain standard requirements, include criteria on permissible constraints and identify the appropriate entity that would receive the generator owners’ constraint declarations under the standard,” staff said in presenting the order.
“EOP-012-1, in its current form, includes undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods,” FERC said in its order.
Among the elements FERC required be included in the next version of the standard are a deadline for the completion of corrective action plans and a shorter grace period for generators to implement those plans and freeze-protection measures. The approved standard gives generators five years to upgrade their facilities, for example.
“Although we are giving NERC the discretion to determine what the effective date should be shortened to, we also emphasize that industry has been aware of and alerted to the need to prepare their generating units for cold weather since at least 2011,” FERC said. After the January 2018 South Central cold snap, a joint FERC-NERC report found “that one-third of the generator owners and operators surveyed ‘still had no winterization provisions after multiple recommendations on winter preparedness for generating units.’”
“NERC should consider the amount of time that industry has already had to implement freeze-protection measures when determining the appropriate implementation period,” the commission ordered.
Commissioner Allison Clements criticized EOP-012-1’s deficiencies at length during the meeting. “This is one of the more important votes we are taking during my time at the commission,” she said before recalling the deaths and economic damage Texans experienced during the 2021 storm as a result of prolonged power outages.
“There are a number of good measures in what we accept today, to be sure,” Clements said. “But the critical generator weatherization requirements as they were proposed, to be frank, are not up to the task.”
EOP-012-01 requires that existing generators be able to operate for at least one hour continuously at their designated extreme low temperature. “Yeah, one hour,” Clements said sardonically. “Needless to say that doesn’t bring total comfort that we will ensure we get through the next multiday event like Winter Storm Uri.”
She also said the amount of time allowed for implementation “does not reflect the urgency we feel.”
The commission gave NERC a year to submit the revised standard.
Although ERCOT’s markets are not subject to FERC regulations, generators in the Texas Interconnection are subject to NERC’s reliability standards. But Commissioner Mark Christie said market design was the bigger issue.
“These [standards] may have a positive impact … for generators, but … one of the problems that prompted [what happened during] Uri was the market design” in ERCOT, he said. “And I think the same issue applies in many other RTOs. It’s a much bigger issue about how these markets are structured and how they deliver the reliability that we need.”
Participants Praise ‘New Cadence’ for In-person Meetings
TUCSON, Ariz. — Following this week’s meetings of NERC’s Board of Trustees and Member Representatives Committee (MRC), board Chair Ken DeFontes congratulated the bodies on “a very productive week,” aided by a “new cadence” for the events intended to give participants more chances to interact outside of formal gatherings.
“I really got a strong vibe last night from everyone … how much they enjoyed getting together and having that kind of approach,” DeFontes said in opening Thursday’s board meeting.
“I also hear positive feedback from people about the time that we’ve allowed for breaks and an opportunity to have more informal conversations. I think we’re becoming more hungry for that just because we haven’t been able to be together as much as we would have liked,” he continued, referring to the moratorium on in-person gatherings caused by the COVID-19 pandemic that the board and MRC ended their August meetings with in Vancouver.
The Tucson meeting was one of only two full gatherings planned for members and trustees this year, as announced when the board met in New Orleans in November. (See “Board Makes Meeting Changes Official,” NERC Board of Trustees/MRC Briefs: Nov. 15-16, 2022.) While the August 16-17 meetings — to be held in Ottawa, Ontario — will feature full attendance by trustees, members and stakeholders as usual, only trustees and members will attend the May 10-11 gathering in D.C. in person, while others will attend virtually.
The final meeting of the year will be held entirely online; currently the plan is for this meeting to be trustees only, though DeFontes has previously said a virtual MRC meeting is possible if action is needed from members.
New Standards Sent to FERC
Trustees voted Thursday to adopt two new reliability standards, concluding the work of Project 2021-04 (Modifications to PRC-002 – Phase II) and Project 2021-05 (Modifications to PRC-023).
Project 2021-04 produced the standard PRC-002-4 (Disturbance monitoring and reporting requirements), which clarifies notification requirements for fault recorder data in order to help analyze bulk electric system disturbances. The result of Project 2021-05 is PRC-023-6 (Transmission relay loadability), which aims to “eliminate confusion surrounding out-of-step blocking settings.” Both standards will now be submitted to FERC for final approval.
Following the approval of the new standards, Howard Gugel, NERC vice president of standards development, updated the board on the progress of the organization’s work on addressing extreme cold weather.
Earlier on Thursday FERC had agreed to adopt the new standards EOP-011-3 (Emergency operations) and EOP-012-1 (Extreme cold weather preparedness and operations) following their approval by the board in October. Gugel noted that these two standards represent the first phase of the cold weather standards project that the board ordered in November 2021. The standard development team is currently working on the second phase and plans to have new standards available for public comment by March, after the team revises them one more time to address the commission’s newest order.
Board Agrees to Shortened Data Request Timeline
In addition to the standards actions, the board voted to authorize a shortened timeline for NERC to gather information related to FERC’s order last month directing NERC to develop standards requiring utilities to implement internal network security monitoring on certain bulk electric system cyber systems. (See FERC Proposes New Cybersecurity Standard.)
The commission’s order mandated that NERC’s new standards apply to all high-impact BES cyber systems, and to medium-impact cyber systems with external routable connectivity. In addition, the order directed NERC to study the potential impact of applying the requirements to all other cyber systems. FERC ordered this study to be submitted by Jan. 18, 2024.
Performing such a study would require NERC to issue a Section 1600 data request to responsible entities, but this request must be submitted to FERC for a 21-day review period, and then undergo a public comment period that normally lasts 45 days, which NERC staff feared would leave them unable to meet FERC’s deadline.
Staff requested that the board allow this comment period to be shortened to 21 days, and to request FERC shorten its review period to as little as five days, promising to “conduct outreach and coordination with FERC staff during the data request drafting stage.” The board approved the request without objection.
Thilly Honored in Retirement
Kristine Schmidt joined Thursday’s meeting as NERC’s newest trustee, having been confirmed by the MRC at its meeting the day before along with existing trustees Suzanne Keenan and Jim Piro. Each will serve for three years, with their terms expiring in February 2026.
Schmidt has 40 years’ experience in the electricity industry, including at Pacific Gas and Electric, where she was a board member in 2019-20. She has also served on the Western Energy Imbalance Market Governing Body, where she was the inaugural chair in 2016. Her career has also included stints at Xcel Energy and ITC Holdings, as well as a commissioner adviser at FERC. She will serve on the board’s Enterprise-wide Risk Committee, Finance and Audit Committee, and Nominating Committee.
Schmidt will take the seat recently vacated by former Chair Roy Thilly, who was ineligible for renomination having served on the board for 12 consecutive years. This restriction did not apply to Keenan and Piro, who have served for five and three years respectively.
Introducing a resolution to honor Thilly for his years on the board, DeFontes jokingly called Thilly — who preceded him as chair, serving from 2017 to 2021 — his “consigliere” for helping him get up to speed in his new role.
“When I stepped up to be chair, I was feeling a little uncomfortable [about] following Roy. But to his credit, he helped me a great deal with the transition, … and he did it with grace and dignity and humility,” DeFontes said.
WASHINGTON ― Legislation to streamline the permitting of clean energy projects, including new transmission lines, may require bipartisan collaboration and tradeoffs, according to Sen. Martin Heinrich (D-N.Mex.).
While Republicans and some Democrats, such as Sen. Joe Manchin (D-W.Va.), are focused on permitting new natural gas pipelines, there is an “upside” to the situation, Heinrich said in a brief interview Wednesday at the American Clean Power Association’s Energy Storage Policy Forum.
“If we can do permitting reform and do it well, so much of the capital is actually going to flow to clean electrons. So that sets us up for the potential for a bipartisan solution to all this,” he told RTO Insider.
The senator pointed to cost allocation as one of the “tough issues” to be worked through to prevent states and their residents from “paying for something they’re not benefiting from. But you have to have ways of sharing costs across multiple jurisdictions, multiple businesses and making sure that costs and benefits get shared proportionately.”
Conversations about the issue among Democrats and Republicans in the House and Senate are “more sophisticated than they have been in the past,” he said.
A compromise on pipelines could have “the potential to make this a bipartisan solution,” said Heinrich, who sits on the Senate Energy and Natural Resources Committee, which Manchin chairs. “People have to realize that because of where the markets are heading, anything we do in this space is naturally going to benefit the clean energy transition.”
The need for the storage industry to move ahead with a strong bipartisan strategy was a key theme at the one-day event, with Jason Grumet, ACP’s new CEO, setting the tone in opening remarks that called on attendees to “find a way to balance the audacity of this transition with the humility of the limitations that all technologies have.”
Coming to ACP after 15 years as president of the Bipartisan Policy Center, Grumet said, “The challenge is that … we have to make a century-scale transition in 25 or 30 years. … There’s been a lot of advocacy, which is intended to be supportive, which has not been honest, which essentially said, ‘We can have 100% clean power by 2035 and leave oil and gas in the ground.’
“That’s not true. It undermines our credibility, makes us seem like hypocrites,” he said. “We just have to be really honest and pragmatic about the challenge. We’re going to have a multi-technology solution,” including natural gas.
“We have to recognize that storage, solar, wind, nuclear, clean gas are all going to be critical to actually decarbonizing the economy, and that’s also helpful because we need a lot of friends,” Grumet said. “We have a divided country, a divided Congress. You can’t get anything done unless you have broad-based appeal.”
Security, Affordability, Climate
ACP’s choice of Grumet to lead the organization, with his strong roots in bipartisan work, comes at a pivotal moment for the industry.
The U.S. energy storage market is “past the inflection point,” said Jason Burwen, ACP vice president for energy storage. The industry put about 9 GW of new storage online in 2022, and according to the U.S. Energy Information Administration, another 21 GW of new storage could be deployed on the grid by 2025.
Further, the Inflation Reduction Act provides a new tax credit for standalone storage, which opens the way for storage to be used as a grid resource. California has more than 4 GW of storage online, not all of it paired with solar, and could need up to 48 GW by 2045, according to the California Energy Commission.
Developers and power plant owners plan to significantly increase utility-scale battery storage capacity in the United States over the next three years, reaching 30 GW by the end of 2025. | EIA
“The remarkable growth in U.S. battery storage capacity is outpacing even the early growth of the country’s utility-scale solar capacity,” the EIA said in a December update. “U.S. solar capacity began expanding in 2010 and grew from less than 1.0 GW in 2010 to 13.7 GW in 2015. In comparison, we expect battery storage to increase from 1.5 GW in 2020 to 30.0 GW in 2025.”
Grumet sees energy storage as a central answer to the economic and political challenges of the moment. “Security, affordability and climate all have to be engaged at once,” he said. “The effort to focus on one of those three elements turns out to be pretty crappy energy policy that tends to lead you towards one side or the other of the political spectrum.”
While different mixes of generation can move the economy toward net-zero, energy storage is a hinge for all the of them, he said.
But bipartisanship can be a double-edged sword. “There’s a ton of bipartisan support for ‘don’t do anything near me’ … which is absolutely at odds with what we need to do,” Grumet said. “We have a society based on this premise of local control and community rights, and we have to honor that premise [but] you cannot transition that economy with community-based decisions.
“So we’ve got to figure out, again, as an industry, how do we make it clear that we have a shared national interest?” he said.
Starting From Nowhere
In an on-stage conversation with Grumet, Heinrich agreed that energy storage must be “socialized” as a “bread-and-butter” solution to a range of energy challenges.
“When I came to the Senate, and that was after four years in the House, there were a very small number of senators [who] were really focused on what are the nuts and bolts to really make the energy transition work,” he said. But as climate change has become an increasingly important issue, “the entire [Democratic] caucus is focused on solutions and looking for solutions.
“So if you come with credibility and say, ‘This policy or this technology is going to be absolutely critical,’ people start with an open mind,” he said.
Bipartisan solutions will also be needed to address clean energy supply chain issues and dependence on China for the processing of critical minerals, such as lithium, and manufacturing of key storage components.
“What we have to recognize is that industry doesn’t exist in a meaningful way in the continental U.S. today, and we need to change that,” Heinrich said. Tax credits for clean energy manufacturing in the Inflation Reduction Act have catalyzed new interest and activity in developing an industrial policy, he said, “but we’re really starting from practically nowhere.”
At the same time, “we don’t want to shut down for seven years,” while domestic supply chains are built out, he said. “You can’t wait until we make everything here to start creating solutions that we know we need today. … Why this is so complicated a problem is because we are really reorganizing the way we power our entire society.”
Grumet raised ongoing concerns on both sides of the aisle in Congress about China’s acquisition of U.S. technologies and intellectual property, which have resulted in “a reluctance to have any connection at all” with the country.
Both he and Heinrich see new opportunities for U.S.-Chinese joint ventures growing out of the snowballing investments in clean tech manufacturing in the U.S., triggered by the IRA.
While some European countries have labeled the law as “protectionist” and say it will draw investment away from the European Union, Heinrich said, it shows that “we’re serious about taking a new direction.”
