The D.C. Circuit Court of Appeals on Friday upheld a FERC ruling that found a 2016 merger had left three ITC Holdings subsidiaries no longer fully independent, disqualifying them from a full return on equity incentive for standalone transmission providers.
The decision found there was “substantial evidence to support FERC’s finding that the merger had reduced ITC’s independence, thereby rendering the existing adders unjust and unreasonable” (International Transmission Company, et al. v. FERC, 19-1190).
FERC had granted International Transmission Co. and Michigan Electric Transmission Co. 100-basis-point adders in 2003 and 2005, respectively, and granted ITC Midwest a 50-point adder in 2015. But in October 2018 the commission found the companies were no longer fully independent because their parent company, ITC Holdings, had merged with Canadian and Singaporean companies (EL18-140).
ITC Midwest has been upgrading transmission in Iowa. | ITC
The commission affirmed its ruling in July 2019, saying the reduction in the adders was appropriate because the merger had reduced but not eliminated the companies’ independence. (See FERC Rebuffs ITC Call to Restore Full ROE Adders.)
The transmission companies appealed to the D.C. Circuit. They argued FERC had “arbitrarily and capriciously departed from precedent establishing a particular methodology to assess transco independence.” And they contended FERC had “exceeded its statutory authority by reducing ITC’s transco adders without first finding the adders to be unjust and unreasonable,” according to the court.
Regarding the first argument, a three-judge panel found it “fails at the outset because FERC, consistent with its stated intent in Order No. 679, never established any definitive methodology, let alone the one ITC claims it did.”
“FERC has consistently applied a case-by-case approach to determining transco independence, considering ownership and business structure as part of that inquiry since it first granted a transco adder in 2003,” the court said.
The companies’ claim that FERC had exceeded its statutory authority under Section 206 of the Federal Power Act also failed, the court found.
The law requires “FERC to show that an existing rate is unlawful before ordering a new rate,” and ITC argued that FERC had violated that mandate by failing to find the existing adders to be unjust or unreasonable before reducing them by half,” the judges wrote. FERC’s analysis, however, “clearly tracked the two-step procedure mandated by Section 206,” they said.
Nobody outside our industry understands our industry. And we see ourselves through a glass, darkly.
So with the tragedy in Texas (more specifically ERCOT, which is 90% of Texas’ load), there are plenty of politicians and talking heads spinning what happened and who or what is to blame. They’re mostly wrong.
There are two things not to blame. And two things to blame. Please let me explain.
Thing No. 1 not to Blame: Wind Generation
Yes, there is a lot of wind in ERCOT: around 30,000 MW. And yes, wind is intermittent.
That’s why ERCOT assumes that only a small fraction of maximum wind generation will be available when needed. The amount of available wind that ERCOT assumed this winter is 7,070 MW.[1] And ERCOT ran a sensitivity for low-wind output that assumed 5,279 of that 7,070 MW would not be available, leaving 1,791 MW available.
Now let’s look at what actually happened. This chart, “ERCOT Load vs. Actual Wind Output,”[2] shows that actual wind generation (the right vertical axis, in megawatts) during the Feb. 11-18 period had only two brief dips below the low-wind sensitivity of 1,791 MW.
ERCOT load vs. actual wind output Feb. 11-18 | ERCOT
So wind generation is a bit player in this tragedy.
Thing No. 2 not to Blame: Load Forecast
In the fall ERCOT forecasted an extreme weather winter peak load of 67,208 MW.[3] Now let’s look at the same chart showing ERCOT load during Feb. 11-18 (this time the left axis). The peak load was 69,222 MW, at 8 p.m. on Feb. 14.[4] This is only 2,000 MW more than the forecasted extreme weather peak load, and this forecasted peak was exceeded for only five hours.
Now to complete the picture, we need to recognize that early in the morning of the next day, Feb. 15, ERCOT began shedding load. So we would need to add back load shed in order to simulate unrestricted load. The load shed began at 10,500 MW at 1:25 a.m., and grew to 16,500 MW later that day.[5] If you look at the chart and envision the addition of the load shed, you’ll see that the unrestricted load does not exceed the peak at 8 p.m. on Feb. 14 of 69,222 MW.[6]
So the load forecast is also a bit player in this tragedy.
Thing No. 1 to Blame: Thermal Generation Maintenance Outages
Now we’ll discuss the real culprits: thermal generation (gas, coal and nuclear) or, more accurately, the lack thereof.
Two things went wrong with thermal generation: maintenance (planned) outages and forced (unplanned) outages.
Texas RE-ERCOT Seasonal Risk Scenario | NERC
To understand what happened with the first thing, please look at the chart “Seasonal Risk Scenario,”[7] which was prepared by the NERC in November 2020 from data provided by ERCOT. This is a “waterfall” chart starting with gross winter resources on the left side, and then making adjustments to arrive at expected net resources relative to extreme winter peak demand on the right side. As you can see, ERCOT forecasted an expected operating reserve of 2.3 GW under extreme conditions.[8]
If you look at the second bar from the left, ERCOT forecasted 4.1 GW of “typical maintenance outages.” Here’s the problem: ERCOT approved 14 GW of maintenance outages for this period,[9] about 10 GW more than it had forecasted.
This appears to be grid operator error.
Thing No. 2 to Blame: Thermal Generation Forced Outages
Now to thermal generation forced outages. Please look at the same chart, this time the third and fourth bars from the left. The third bar shows “typical forced outages” for thermal generation of 4.5 GW, and the fourth bar shows “derates” (outages) for “extreme conditions” for thermal generation of another 4.5 GW. The total is 9 GW, which is the forced outages for thermal generation under extreme conditions.[10]
Actual thermal generation forced outages: about 18 GW.[11] So actual forced outages were 9 GW more than ERCOT’s extreme conditions scenario.
To recap, there were 10 GW of excess maintenance outages and 9 GW of excess forced outages, for a total of 19 GW in unanticipated thermal outages, in line with the necessary load shed of 16.5 GW.
The Why
As I said earlier, the excess maintenance outages appear to be grid operator error.
But what about the excess forced outages? Extreme winter conditions regularly occur around the U.S. and the world without catastrophic loss of electric generation.
ERCOT has a market design that assumes that as long as wholesale prices are unlimited, supply and demand will always “clear” — basically equalize. New resources will be built and upgraded in anticipation of occasionally getting very high prices. And existing resources would incur new capital costs in order to receive those very high prices occasionally.
The problem has always been that the needed high prices occur rarely — like every 10 years — when they max out at $9,000/MWh, 360 times a typical wholesale price of $25/MWh. Who would finance and build needed resources and their winterization on such a GameStop bet? And when such prices do occur, the political, regulatory and market fallout can be staggering.[12]
Because of these real-world limitations, grid operators like PJM have adopted a hybrid market structure: a capacity market to assure that adequate resources will be available when needed, and an energy market that matches supply and demand on a least-cost basis every hour.
A capacity market spreads the needed compensation to maintain, build and secure adequate supply resources over every day, month and year instead of requiring speculation over a burst of revenue that happens maybe once every 10 years. And it penalizes any resource that does not perform when needed. The cost to customers is spread over time instead of unpredictable price surges maybe every 10 years.
It’s a form of insurance: You don’t need it until you need it.
“Perhaps most important, the state [Texas] does not have a ‘capacity market’ to ensure that there was extra power available for surging demand. Such systems elsewhere act as a sort of insurance policy so the lights will not go out, but it also means customers pay higher bills.”
Let me close by wishing the best to the good people of Texas, and the hope that we all learn the right lessons from this tragedy.
[8] Wood Mackenzie points out that ERCOT does not combine extreme conditions of high thermal outages and low wind when comparing to extreme winter peak load.
[9]https://www.woodmac.com/news/editorial/Breaking-down-the-texas-winter-blackouts/full-report/. Wood Mackenzie also reports that in the week before the storm hit, ERCOT tried to recall some of this generation but was not successful in doing so. Although Wood Mackenzie described all 14 GW as “offline for maintenance,” it is possible that some of that were forced outages, in which case that portion should be added to excess forced outages discussed in the next section. ERCOT apparently does not have the literal power to reject planned outage requests submitted more than 45 days in advance, but it is difficult to believe that a generator would insist on its timing if ERCOT advised that system reliability would be denigrated.
[10] Wood Mackenzie points out that ERCOT does not combine extreme thermal outages and the low-wind sensitivity when comparing to extreme winter peak load and that, if ERCOT had done so, it would have shown a negative operating reserve of 4 GW.
[11] Wood Mackenzie reports that total thermal outages the morning of Feb. 15 went from the 14 GW of maintenance outages to 32 GW, the difference being 18 GW of forced outages. A chart stacking forced outages on top of maintenance outages is in an article by Enverus here, https://www.enverus.com/blog/trading-and-risk/ercot-power-grid-outage-what-went-wrong/.
Eversource Energy and Vermont Electric Power Co. (VELCO) each presented replacement and refurbishment projects to the ISO-NE Planning Advisory Committee on Wednesday, with Eversource detailing its preferred solution to replace the only self-contained fluid-filled cable on its Connecticut transmission system.
Eversource’s Paul Melzen said the utility plans to remove 400 feet of the existing cable system and install 520 feet of solid dielectric cable in the duct bank at Branford 11J, a 115/23-kV substation located along the Connecticut shoreline. The project also calls for replacing two existing bus support structures and the relocation of an NRG Energy-owned 23-kV circuit from a combustion turbine housed in the substation to accommodate the route of the 115-kV duct bank.
The work’s estimated cost is $8.8 million, with a projected in-service date in the fourth quarter.
The fluid-filled cable was initially manufactured in 1981, and its creators are no longer in business. The cable has logged 26 work orders since 2005, including fluid leaks that increased maintenance burdens and reliability concerns. The continued decrease in oil pressure or oil level will eventually result in a trip of the cable. There was a service interruption in March 2017 that required complex restoration methods, according to Melzen. The cable is also located near a waterway, an environmental risk.
Eversource Energy wants to replace a self-contained, fluid-filled cable system with a solid dielectric cable system at a substation in Branford, Conn. | Eversource Energy
Melzen mentioned two potential alternatives to Eversource’s preferred solution. One is replacing the existing fluid-filled cable system with a new one, which would create the need for dielectric fluid accumulators, fluid-level pressure alarms, and additional maintenance and operational requirements. It would additionally pose an environmental threat with the release of dielectric fluid. There would also be limited equipment suppliers. The second is replacing the current cable system with an overhead bus, but there is a lack of real estate in and around the substation to accommodate it.
Hantz Presume of VELCO outlined three transmission line refurbishment projects at an estimated cost of $31.6 million, with the work completed between 2022 and 2024.
The most significant portion of the work will be along the 26.4-mile line from Essex to Middlesex, where 116 out of 305 wood H-frame structures with rotten pole tops and cross arms will be replaced with mostly steel H-frames to reduce VELCO’s current wood pole inventory. The line location is primarily mountainous, with difficult access and a challenging sloped right of way. The estimated cost is $15.2 million for the project, which is expected to be completed in 2024.
The other two projects are similar refurbishments along lines between Essex and Sandbar (11.2 miles) and West Rutland to Blissville (11.6 miles) that are expected to cost a combined $16.4 million and replace a total of 123 wooden frames with steel by 2022. Both lines have seen rotten crossarms and pole tops, and moderate to severe woodpecker damage.
Additional Items
ISO-NE Director of Transmission Planning Brett Oberlin gave a forward-looking presentation on dynamic reactive power devices. The RTO would like to use synchronous condensers as the preferred device to address system concerns identified in needs assessments, except under specific system limitations. Oberlin asked for stakeholder feedback by March 4.
Steven Judd, principal engineer in system planning for ISO-NE, provided stakeholders a summary of DNV GL’s stochastic time series analysis of variable energy resources (VERs). The RTO initially hired DNV GL in 2019 to use its weather modeling software and develop a historical dataset of all existing wind plants and future offshore wind plants from 2012 to 2018. It now contains hourly time series data for VERs, load and weather data in New England for 20 years (2000-2019). DNV GL also developed the Stochastic Engine, which can resample wind speed, irradiance, price and load into parallel and plausible scenarios. The weather-to-generation models simulate each weather scenario’s expected power production, creating thousands of 20-year simulations of hourly weather and power outputs.
SPP’s state regulators recently agreed on revisions to a package of recommendations that would improve operations along the RTO’s seam with MISO.
Texas Public Utility Commission Chair DeAnn Walker facilitated the Regional State Committee’s modifications to the document, which prioritizes resolving rate pancaking and adds a category for smaller interregional projects. (See RSC Keeps MISO Liaison Committee Alive.)
The RSC, meeting on Feb. 12 shortly before severe winter weather overwhelmed many of its members’ states, agreed that rate pancaking and smaller interregional projects should remain their two top priorities.
The MISO-SPP seam | Organization of MISO States
The regulators also agreed that the RSC-Organization of MISO States Seams Liaison Committee (SLC) should create a working group focused on inventorying the different types of rate pancaking along the MISO-SPP seam and sided with the SLC’s recommendation that a survey be conducted of transmission owners and other stakeholders to measure interest in studying the issue.
“Creating that inventory is important,” Kansas Corporation Commissioner Andrew French said. “It’s important to get feedback from the TOs and other stakeholders. It’s not just TOs experiencing those issues.”
The SLC has said the working group should comprise RSC and OMS members and an equal number of other stakeholders chosen by the two regulatory groups.
Walker, the RSC’s lead on the SLC, was to send the revised document to OMS Executive Director Marcus Hawkins.
National Grid is participating in research to determine how to convert existing gas networks to support hydrogen that could be used for home heating, Kristin Munsch, the utility’s director for regulatory and consumer strategy, said Wednesday.
Hydrogen is a versatile source of energy that presents the opportunity to use existing infrastructure to meet climate goals, Munsch said during a virtual panel event hosted by the Northeast Energy and Commerce Association.
Space and water heating is the second largest source of emissions in Massachusetts, according to data from the Massachusetts Clean Energy Center, and most New England buildings are currently heated by fossil fuels.
Large wind projects, such as those in the U.K. and Europe, are producing an oversupply of energy that can be used for hydrogen production, independent energy market researcher Brad Bradshaw said during the panel discussion. The stranded electrons can be monetized by powering water electrolysis to produce hydrogen, which can then be put in pipelines for things like steel manufacturing or blending with natural gas.
“It seems to meet a lot of challenges” related to Massachusetts’ climate goals, Munsch said.
Because hydrogen is not a new industry, it already has an extensive supply chain, Bradshaw said. Handling the storage and transportation of hydrogen is “done in a well-experienced industry and a safe, economical manner.”
National Grid is exploring supply chain options for hydrogen that could include using facilities like the one in this rendering to make hydrogen from excess wind power. | Shutterstock
Research is now focused on how to “pipe the hydrogen within homes safely and test [hydrogen] with different appliances,” he said.
“Several boilers are already manufactured around the world that take in 100% hydrogen to produce heat for homes, so it’s not really challenging,” Bradshaw said. “It’s just new.”
Excess solar and wind from grids in New York and Maine can be converted to hydrogen and transported cost effectively in high-capacity compressed tube trailers to places like Boston to help decarbonize the gas system, he said.
In the U.K., where the utility is headquartered, National Grid is researching different “flood rates” of hydrogen to a network of more than 100 residential buildings and commercial office spaces, Munsch said. The utility is learning from colleagues in the U.K. about what kind of pipes to use to transport hydrogen.
“The question now is how does it behave differently in our distribution systems,” Munsch said, as New England has “a lot of old pipes.”
National Grid has also partnered with the New York State Energy Research and Development Authority and Stony Brook University’s Institute for Gas Innovation and Technology to assess the impact of introducing hydrogen to infrastructure in New England.
In New York, National Grid has a proposal pending for a multiuse hydrogen production and utilization facility in collaboration with Standard Hydrogen Corp. The renewable natural gas produced will be injected into National Grid’s gas distribution system. The facility would also incorporate carbon capture, utilization and sequestration.
Research into hydrogen as a source of thermal energy is a “question of keeping all of our options open” for the anticipated increase in electrification of sectors such as heating and transportation, Munsch said.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. The MRC will be asked to endorse proposed revisions to Manual 40: Training and Certification Requirements resulting from a periodic review. The Operating Committee endorsed the revisions Feb. 11. (See “Manual 40 Changes Endorsed,” PJM Operating Committee Briefs: Feb. 11, 2021.)
Endorsements/Approvals (9:10-11:00)
1. Black Start Unit Testing, CRF, Involuntary Termination, MTSL and Substitution (9:10-10)
A. Members will be asked to endorse a proposal addressing black start unit involuntary termination, substitution rules, capital recovery factor (CRF) and minimum tank suction level (MTSL). Greg Poulos, executive director of the Consumer Advocates of the PJM States, introduced the proposal on behalf of the Delaware Division of the Public Advocate at the January MRC meeting after proposals from PJM and Dominion Energy failed to receive endorsement. (See PJM MRC/MC Briefs: Jan. 27, 2021.)
B. Susan Bruce of the PJM Industrial Customer Coalition and Sharon Midgley of Exelon will also ask stakeholders to endorse an alternative PJM proposal on the same issue on first read. The proposal received 43% stakeholder support at the OC in December.
2. Storage as a Transmission Asset (SATA) (10-10:40)
The MRC will be asked to endorse PJM’s proposal for addressing how storage should be considered in the Regional Transmission Expansion Plan, along associated tariff and Operating Agreement revisions. Stakeholders endorsed the proposal at the Planning Committee in December. (See PJM PC OKs RTEP Rules for SATA.)
3. Competitive Exemption OA Revisions for SATA Resources (10:40-11)
Contingent on approval of the SATA proposal, Sharon Segner of LS Power will introduce a friendly amendment with OA revisions specifying, among other things, that SATA resources are ineligible for qualifying as immediate-need reliability projects.
Members Committee
Consent Agenda (1:20-1:25)
B. Stakeholders will be asked to endorse proposed Tariff Attachment K and OA Schedule 1 revisions addressing market rules for real-time values. The package was endorsed with a sector-weighted vote of 4.9 (98%) at the January MRC meeting. (See “Real-time Values Market Rules,” PJM MRC/MC Briefs: Jan. 27, 2021.)
D. Members will be asked to endorse proposed tariff and OA revisions related to stability limits in markets and operations. The package was endorsed with a sector-weighted vote of 4.05 (81%) at the January MRC meeting. (See “Stability Limits Endorsed,” PJM MRC/MC Briefs: Jan. 27, 2021.)
Endorsements/ Approvals (1:25-2:25)
1. MC Resolutions (1:25-2:25)
Midgley and Jim Davis of Dominion Energy will ask stakeholders to endorse a proposal, along with associated OA revisions, developing rules to address sufficient member approval of a resolution at the MC. Poulos will review an alternative proposal.
MISO said its members collectively saved about $3.5 billion in 2020 for choosing RTO membership over going it alone on the grid.
The grid operator’s 2020 value proposition study showed that it provided between $3.1 billion and $3.9 billion in regional benefits. The annual value proposition study compares utility benefits of RTO membership versus flying solo.
MISO chalked the savings up to improved reliability, more efficient use of the region’s existing assets and reduced need for new assets.
Despite the pandemic, the cost reductions didn’t change much from a year earlier, when MISO said it saved members between $3.2 billion and $4 billion. For the past four years, the grid operator has claimed annual cost savings between $3 billion and $4 billion. (See MISO Estimates up to $4B in 2019 Benefits.)
Spokesperson Brandon Morris said the pandemic didn’t affect value proposition results because MISO was able to consistently maintain normal reliability and operations functions.
“Our member utilities’ shared commitment to serving the footprint reliably — combined with relatively stable year-over-year load levels as compared to 2019 — resulted in a 2020 value proposition which was largely shielded from the devastating impacts of COVID-19,” Morris told RTO Insider.
“The value proposition has been relatively stable for the past few years at about $3.5 billion,” Strategy and Business Development Adviser Brad Decker told stakeholders at a teleconference Feb. 19 to discuss the savings.
MISO has documented more than $30 billion in benefits to its members since 2009. “This benefit has grown as MISO has grown,” Decker said.
Broken down, MISO estimated it has saved members between $384 million and $447 million because of its ability to offer improved reliability and perform compliance tasks on behalf of its members.
The RTO said members also avoided spending another $517 million to $572 million because it dispatches existing assets efficiently and offers energy regulation and spinning reserves.
“Before MISO, the region operated as a decentralized, bilateral market,” Decker said. “Now, the day-ahead and real-time market processes are used to minimize total production costs.”
But MISO said its most attractive benefit is its members’ diminished need to build new generating assets, worth between $2.47 million to $3.22 million in savings.
The grid operator said its footprint diversity accounted for about $1.9 billion to $2.4 billion of that reduced need for assets. Decker said the RTO’s geographic expanse means load can rely on other generation assets because weather and demand fluctuate by region.
“If you shared a car with your neighbors, you have fewer cars in garages, and that’s exactly what’s happening under footprint diversity,” Decker said.
Other drivers of the reduced generation need were MISO’s efforts to better incorporate wind into the resource mix, which it valued at a $450-$517 million savings to members, and its demand response programs, which it valued at $116-$211 million.
“MISO’s regional planning enables more economic placement of wind resources, reducing the overall capacity needed to meet required wind energy output,” Decker said.
A plan to build small community solar projects and reduce electric bills for some low-income residents in Nevada is facing pushback from consumer advocates, who object to passing program costs to nonparticipating ratepayers.
The proposed Expanded Solar Access Program is the result of Assembly Bill 465, passed by the Nevada legislature in 2019. The Public Utilities Commission of Nevada has been conducting a rulemaking since mid-2019 to spell out details of the program, which would be run by the state’s monopoly electric provider, NV Energy.
AB465 specifies that the cost of the discount for low-income customers must be spread across all of the utility’s ratepayers.
But the bill does not contain a similar provision for other costs of the program, according to the Bureau of Consumer Protection (BCP), which is part of the Nevada Attorney General’s Office. Yet PUCN’s proposed regulation states that “all costs related to the Expanded Solar Access Program are public policy costs that must be charged to all customer classes of an electric utility.”
“The only subsidy allowed under Assembly Bill 465 to be charged to nonparticipating customers is that of the low-income discount,” Senior Deputy Attorney General Michael Saunders said in a Feb. 16 letter to PUCN. “The Expanded Solar Access Program was intended to be a stand-alone program with its costs covered by participating customers.”
The letter reiterated concerns that BCP expressed in written comments last year. And PUCN’s regulatory operations staff, which is separate from the agency’s decision-making side, have also expressed concerns about spreading program costs other than the low-income discount to all ratepayers.
“This outcome does not seem just and reasonable since remaining ratepayers will receive no direct benefit from this program,” Assistant Staff Counsel Shelly Cassity said in a May 29 letter to the commission.
NV Energy did not respond to requests for comment on the Expanded Solar Access Program. A spokesperson for the attorney general’s office said BCP could not comment on issues related to rulemaking.
PUCN held a workshop and a hearing last week on its draft regulation for the program. The commission now plans to release a revised draft, to be followed by another written comment period and hearing.
As outlined in AB465, which was sponsored by Assemblywoman Daniele Monroe-Moreno (D) of North Las Vegas, the Expanded Solar Access Program would include three to 10 community-based solar projects in areas with a concentration of low-income residents. NV Energy would own and operate the solar facilities, which would be connected to the company’s distribution system.
NV Energy would also include at least one utility-scale solar resource in the program. The utility-scale facility is necessary to make the program affordable to residents, NV Energy officials said during hearings on the bill.
Program participants would fall into three categories:
nonprofits and disadvantaged businesses, including those owned by minorities or low-income residents,
residents whose income falls below 80% of the area median, and
residential customers who show that they cannot install their own solar projects because of rental agreements or site constraints.
The program would establish its own electric rates. Low-income residents in the program would be guaranteed a reduced rate. Other participants would have “stability and predictability” in their electric rates, although reduced rates are not guaranteed.
In another provision, the Nevada Department of Employment, Training and Rehabilitation would work with employers and the International Brotherhood of Electrical Workers to create solar job opportunities and a training program.
Break from Tradition
Monroe-Moreno has noted that AB465 is not a traditional community solar program.
In general, community solar programs allow participants to buy or lease part of an off-site solar photovoltaic system. The programs are also known as shared solar or solar gardens. As of June, community solar projects were found in 39 states and Washington, D.C., according to the National Renewable Energy Laboratory within the U.S. Department of Energy.
Nevada came close to enacting a community solar bill during the 2017 legislative session.
Senate Bill 392, by Sen. Mo Denis (D) of Las Vegas, would have allowed community solar gardens run by subscriber organizations, with individual subscribers receiving a credit on their electric bill for their share of electricity generated by the solar garden.
The legislature passed SB392, but then-Gov. Brian Sandoval vetoed it, saying he was concerned that community solar gardens would operate as small utilities, only without the same level of regulation.
Sandoval was also concerned about the bill’s timing. Nevada residents were preparing to vote in November 2018 on the Energy Choice Initiative, which would have moved the state from an electric monopoly to a competitive market. The initiative failed.
AB465 garnered support from organizations including the Sierra Club Toiyabe Chapter, Western Resource Advocates, IBEW and the Nevada State AFL-CIO. Supporters pointed to the bill’s environmental and workforce benefits.
Nevada Conservation League representative Kyle Davis said during a Senate committee hearing that although the bill wouldn’t create a traditional community solar program, it would be “a step forward, especially for low-income ratepayers.”
But some groups opposed AB465.
The Solar Energies Industry Association, a national trade group, objected to the fact that the bill would allow solar projects approved as long ago as 2018 to be included in the program. SEIA said it would prefer that the program add new solar projects.
The Coalition for Community Solar Access shared SEIA’s concern. The group also said it wasn’t clear how much program participants would save on their electric bills.
Those issues and others “make this bill … an unnecessary and deeply flawed experiment for the state, especially with tried-and-true best practices to be leveraged from over a dozen other states,” CCSA Executive Director Jeff Cramer said in a May 2019 letter to the Senate Committee on Growth and Infrastructure.
FirstEnergy officials updated investors Thursday on the ongoing investigation into the fallout from House Bill 6 during its fourth quarter earnings call while also disclosing billionaire investor Carl Icahn is looking to acquire a stake in the company.
Officials said it disclosed in its most recent filing with the Securities and Exchange Commission that it received a letter Feb. 16 from Florida-based Icahn Capital informing them that Icahn is making a filing with the Federal Trade Commission of its intention to acquire voting securities of FirstEnergy in “an amount exceeding $184 million but less than $920 million,” depending on market conditions. The company’s market capitalization is almost 18.5 billion.
FirstEnergy said it does not know whether Icahn or his associates have already acquired FirstEnergy stock, and it did not know his intentions regarding the company. The letter was the only contact so far with Icahn, officials said.
Icahn earned a reputation in the 1980s as a “corporate raider,” known for his hostile takeover and asset stripping of airline TWA. Icahn briefly served as an economic adviser in the Trump administration in 2017.
FirstEnergy’s share price jumped 7.2% to $34.25 by the end of trading on Thursday on the news involving Icahn, climbing as high as $35.36 per share after noon. Nearly 19 million shares traded hands, about three times as many on a typical day in the last year. The share price closed Friday at $34.03 on a trading volume of 5.3 million shares.
FirstEnergy President Steven Strah | FirstEnergy
“We thought it was noteworthy, and that’s why we’re just being open and transparent about it,” acting CEO and FirstEnergy President Steven Strah said. “We just don’t know enough at this point.”
An electric utilities industry analyst at KeyBanc in Cleveland said in a note to clients that Icahn was likely attracted because FirstEnergy is undervalued.
“We believe that there are multiple avenues for [FirstEnergy] to close its valuation gap where an activist could have an impact – up to and including a sale of the company,” said KeyBanc analyst Sophie Karp, who added that Icahn’s interest could result in a sale of the utility or of non-core assets.
HB 6 Investigation
Thursday’s earnings call was the first held since five FirstEnergy officials were fired in the wake of the fallout surrounding the alleged $61 million bribery scheme that resulted in the passage of HB 6 to rescue struggling nuclear plants in Ohio at a cost to the public of more than $1 billion. The scandal also claimed Ohio Public Utilities Commission Chair Sam Randazzo, who resigned after the FBI raided his home. Randazzo has not been charged in the Justice Department investigation of the scheme. (See PUCO Chair Randazzo Resigns.)
Neither FirstEnergy nor its former executives have been charged.
But on Friday, the Justice Department’s Southern District of Ohio announced that Generation Now, a nonprofit social welfare agency at the center of the purported racketeering scheme created to conceal more than $60 million in corporate money to former Ohio House Speaker Larry Householder, pleaded guilty to one count of racketeering conspiracy.
Householder and his longtime political strategist Jeffrey Longstreth signed the guilty plea on behalf of Generation Now. Longstreth pleaded guilty in October to an identical individual charge and faces up to 20 years in prison. Householder has pleaded not guilty and is awaiting trial. Stripped of his title as speaker, Householder continues to serve as a state representative. Strah, who took over for former CEO Charles Jones after he was fired in late October, said FirstEnergy is “deeply committed” to creating a culture in the company where its leaders “encourage open and transparent communications with all of our stakeholders.” (See FirstEnergy Fires Jones over Bribe Probe.)
“We are dedicated to re-emphasizing that every employee at every level has the responsibility to consistently act in accordance with our core values and behaviors and to speak up if they see inappropriate behavior anywhere in the organization,” Strah said. “At the same time, we’re taking decisive actions to rebuild our reputation and brand and focus on the future.”
Strah said FirstEnergy is continuing to cooperate with the Department of Justice and SEC as the investigation into the alleged bribery scheme continues.
Christopher Pappas, FirstEnergy executive director and independent board member, said the company’s internal investigation has not resulted in any new material to disclose. Pappas said investigators have found certain transactions, including vendor services, that were either improperly classified, misallocated to utility or transmission companies or lacked proper supporting documentation.
The transactions, Pappas said, resulted in amounts collected from customers that were “immaterial” to FirstEnergy and will work with regulatory agencies “to address these amounts.” The exact amounts were not disclosed.
“Our internal investigation continues to be thorough and robust and includes assistance from external law firms who are supported by several other consultants,” Pappas said.
FirstEnergy announced it has stopped making political contributions and will no longer make contributions to political nonprofit 501 (c) (4) organizations.
The company on Thursday also named John Somerhalder, a former executive with CenterPoint Energy in Texas, as vice chairman of FirstEnergy. Somerhalder will also serve as executive director and a member of FirstEnergy’s executive leadership team in a transitional capacity and is tasked with improving the company’s governance and rebuilding relationships with regulators.
Clean Energy Investment
FirstEnergy reaffirmed its commitment to modernizing its grid and becoming carbon neutral by 2050. Last year, the company invested $3 billion in its distribution and transmission system and grid modernization. FirstEnergy continues to operate about 3,100 MW of coal-fired power plants in West Virginia, according to its most recent 10K filing. The company has committed to owning 50 MW of solar generation in West Virginia by 2030 and has pledged to look for other ways to reduce coal burning in the state. “We believe robust long-term organic growth opportunities are well aligned with the focus on electrification and the critical role the grid plays in supporting the transition to a carbon neutral economy,” Strah said.
The company recently announced a $19.6 million project to construct a new transmission substation in Trumbull County, Ohio, to support the energy demands of the electric vehicle industry expanding in the region. The new transmission infrastructure will provide electric service to Ultium Cells — a 3 million-square-foot EV battery-cell manufacturing plant backed by General Motors and South Korea’s LG Chem.
FirstEnergy has started construction on a new transmission substation in Trumbull County, Ohio, to support the expanding electric vehicle industry in the region. | FirstEnergy
In its strategic plan announced last month, FirstEnergy pledged to achieve carbon neutrality by 2050. It said all new light-duty and aerial trucks will be electric or hybrid vehicles beginning this year and 30% of the fleet will be electrified by 2030.
“This ambitious goal reflects our transformation to a regulated electric utility and our responsibility to help create a sustainable energy future,” Strah said.
Earnings
The company reported earnings of $1.1 billion ($1.99/share), on revenue of $10.8 billion for fiscal year 2020 and $242 million ($0.45/share) on revenue of $2.5 billion for its fourth quarter.
The year-end results were an improvement over 2019, when the company earned $908 million ($1.70/share) on revenue of $11 billion.
FirstEnergy CFO Jon Taylor said he expects a profit of $1.3 billion to $1.4 billion for the current 2021 fiscal year.
Consolidated Edison on Thursday reported net income of $1.1 billion ($3.29/share) for 2020, down about 18% from the previous year because of lower commercial and industrial demand during the COVID-19 pandemic and costs associated with Tropical Storm Isaias last August.
The company’s net income for the fourth quarter was $43 million ($0.13/share), compared with $295 million ($0.89/share) for the same period in 2019.
“I want to thank our essential frontline employees for their dedication and sacrifice throughout the pandemic. Their exceptional work in providing safe and reliable energy to New Yorkers has made a critical difference throughout this most difficult year,” CEO Timothy P. Cawley said in a statement.
Con Edison deployed a 1-MW generator to support the field hospital at the Brooklyn Cruise Terminal in Red Hook. | Con Ed
Last March, Con Ed began suspending utility service disconnections, certain collection notices, final bill collection agency activity, new late payment charges and certain other fees for all customers. The company estimates foregone revenues at approximately $61 million and $3 million for Consolidated Edison Company of New York (CECONY) — its utility subsidiary serving New York City and Westchester County — and Orange and Rockland Utilities (O&R), respectively.
The company estimates the financial impact from COVID-19 for the full year to be $102 million. CECONY’s C&I demand was down 15% for the year, with revenue for the sector down 13%; O&R’s were down 9% and 8%, respectively.
The New York Public Service Commission in January approved further investigation into the Isaias preparation and response by Central Hudson Gas & Electric, CECONY, O&R and PSEG Long Island. PSEG is not under PSC jurisdiction, but the other three utilities “now face maximum potential penalties of up to $137.3 million, with Con Edison and O&R also facing potential license revocation depending upon a finding of repeat violations,” the commission said. (See “NYSEG Dinged for Isaias; Other IOU Cases Pending,” NY PSC OKs Utility Storage Deployment, Cost Recovery.)
New York Gov. Andrew Cuomo on Friday announced that he is advancing legislation to eliminate caps on penalties to ensure they align with actual damages caused by specific violations and to establish a clear process for revocation of a utility’s operating certificate upon recurring failures.
FirstEnergy officials updated investors Thursday on the ongoing investigation into the fallout from House Bill 6 during its fourth quarter earnings call while also disclosing billionaire investor Carl Icahn is looking to acquire a stake in the company.
Consolidated Edison on Thursday 