The Transportation and Climate Initiative (TCI) on Monday released a draft model rule for a cap-and-invest program that Massachusetts, Connecticut, Rhode Island and the District of Columbia have agreed to launch for their regions.
Release of the draft kicks off a multiyear, multijurisdictional effort to define the framework for the TCI-Program (TCI-P) announced in December. TCI-P aims to cut transportation emissions by 26% from 2022 to 2032 in participating regions.
Initial emissions reporting under the plan is set to begin in 2022, with the first auctions and compliance requirements starting in 2023, Kate Johnson, chief of the Green Building and Climate Branch at the D.C. Department of Energy and Environment, said during a webinar Monday.
TCI released a corresponding update on proposed processes for public engagement to ensure the program focuses on equity. The draft model rule and the update on public engagement planning are available at TCI’s website, where stakeholders can find a portal to submit comments, preferably by April 1. TCI will publish a model rule after incorporating public input on the draft.
Once the official program launches, stakeholders will have an opportunity to engage in the TCI-P process through annual reporting that monitors program effectiveness, Johnson said.
The participating states also agreed to conduct comprehensive program reviews every few years.
Those reviews “will help ensure we’re achieving the goals we’ve set together, and that we’re making changes to stay on track and improve the program,” Johnson said.
How the Program Will Work
The draft model rule outlines how the cap-and-invest program will apply to the gasoline and diesel fuel supply chains within the program participants’ jurisdictions. Entities that hold a position at terminals that disperse transportation fuel for delivery will be required to purchase and hold emissions allowances and report emissions-related data to the jurisdiction in which they make deliveries, Megan O’Toole, an attorney with the Vermont Agency of Natural Resources, said during the webinar.
In addition, transportation fuel terminal operators will be required to report fuel shipment information to the jurisdiction in which they operate, she said.
Gasoline tankers like this one will be part of a transportation fuel supply chain that would be required to purchase emissions allowances under the Transportation Climate Initiative Program, as outlined in a draft model rule. | Shutterstock
Each supplier will use an emissions and allowance tracking system to report monthly the emissions associated with the fuels they disperse. Suppliers will purchase and then surrender allowances to cover the emissions that they have reported, O’Toole said.
An allowance represents the authorization to emit one metric ton of carbon dioxide pollution from transportation fuel. The allowances will be sold at joint, quarterly auctions by TCI-P participating jurisdictions. TCI originally projected allowance prices would begin at $6.60/metric ton.
“The number of allowances available for sale at auction each year is equivalent to the [program] cap, and the cap declines each year, meaning the number of allowances available for sale at auction will decline each year,” she said.
Participating jurisdictions will set and publish a reserve price prior to each auction and then publish the final clearing price and total allowances sold at auction, according to the draft rule.
Use of Auction Proceeds
Participating TCI-P jurisdictions will use the allowance auction proceeds to invest in clean transportation.
“It’s up to each individual participating jurisdiction … to determine independently how to invest those program proceeds in consultation with their citizens … and policymakers,” Garrett Eucalitto, deputy commissioner of the Connecticut Department of Transportation, said.
Examples of investments, according to Eucalitto, include:
improving public transportation for unserved or underserved areas;
investing in zero-emissions buses, cars and trucks;
expanding electric vehicle charging infrastructure;
developing interstate EV charging corridors;
repairing existing roads and bridges; and
providing alternatives for active transportation, such as protected bike lanes and accessible sidewalks and crosswalks.
TCI-P participants committed to establishing equity advisory bodies to help shape their investments, Johnson said, adding that participating jurisdictions will designate those advisory bodies “soon.”
Total U.S. energy storage deployments in 2020 could surpass all those in 2015-2019 combined, Dan Finn-Foley, head of energy storage for Wood Mackenzie, said Thursday.
One of the biggest drivers of recent growth in the energy storage industry is the role of utilities’ integrated resource plans in regulated markets.
Regulated utilities will present a “massive opportunity” for storage because of the way they are valuing the resource, Finn-Foley said during a webinar, “State of the U.S. Energy Storage Industry,” presented by the Energy Storage Technology Advancement Partnership.
Utilities are transitioning their IRPs to meet state clean energy policies, with renewables and storage starting to fill in for traditional baseload and peaking capacity resources, such as natural gas.
Finn-Foley said that, for example, Arizona Public Service increased the amount of energy storage capacity in its IRP by 960% from 2017 to 2020.
The storage industry will see exponential growth in the next five years, he said, with the final installed capacity for 2020 likely to pass 1 GW for the first time. Another spike will likely follow in 2021.
A Big Ask
The extended power outages in Texas last month present an important case for how much energy storage needs to grow if it is expected to help build resilient power grids. (See ERCOT, MISO, SPP Slough Load in Wintry Blast.)
Finn-Foley said, for example, that a grid that has lost 30 GW of resources for multiple days would need energy storage with a 90-hour duration and 30 GW of capacity to make up for the loss.
“That amount of energy storage is staggering,” he said. “It’s three or four orders of magnitude more than is on the grid today.”
Reaching that level of capacity in the U.S., he added, will require an equally staggering expansion in manufacturing capacity.
Huge advancements in long-duration energy storage will also be necessary.
“If storage wants to firm out these long-term outages or just smooth out spikes in demand and supply, then we’re going to have to start having the conversation of how we build out manufacturing and economic capability for long-duration systems,” Finn-Foley said.
Stable growth of energy storage in the U.S. will only be possible with the development of mature domestic manufacturing and regionalized supply chains, Imre Gyuk, director of energy storage research at the Department of Energy’s Office of Electricity, said during the webinar.
He also said that, as states reach their mandates for high penetration of renewables, long-duration storage will become essential.
“We have to go from six to eight hours, which we can handle with lithium-ion [batteries], to 10 hours, to diurnal, to several days and possibly weeks and even months,” Gyuk said. “In order to do that, we will need new technologies and new approaches, where we don’t just do energy storage per se, but we fold in other approaches, such as demand management.”
Public Service Enterprise Group CEO Ralph Izzo used the company’s earnings call Friday to lobby for increased subsidies for its New Jersey nuclear plants and predicted the sale of its non-nuclear generation by the end of the year.
PSEG has requested a three-year extension to New Jersey’s controversial zero-emissions certificate (ZEC) program, which paid the company $300 million last year to continue operating the Salem and Hope Creek nuclear plants. The subsidy works out to $10/MWh, which Izzo said is not enough to make the plants competitive with natural gas and zero-marginal-cost renewables.
PSEG’s Salem and Hope Creek nuclear generating stations produce nearly half of New Jersey’s electricity and more than 90% of the state’s carbon-free power. | PSEG Nuclear
Izzo said the company is pleased that the staff of the state Board of Public Utilities recently concluded that Salem and Hope Creek will remain eligible for ZEC payments when the current subsidy order expires in 2022. But he said the payments are too low considering falling PJM forward power prices. He added that the three-year ZEC cycle is too short to give the company confidence to make major capital improvements or consider relicensing the plants when their current licenses expire between 2036 and 2046.
The company would retire the plants if the ZEC payments were reduced below $10/MWh, he said.
“The nuclear plants need more than $10, and what we’ve said is we’ll look at longer-term solutions for that and hopefully coming out of the federal government with a carbon price,” Izzo said during the earnings call with analysts. “And the only reason why we would accept $10 now is that that’s all [the state] can do. So that’s not a negotiation.”
Hope Creek Nuclear Generating Station is one of two PSEG nuclear plants receiving ZEC payments from New Jersey. | NRC
The BPU’s ZEC decision is expected April 27, Izzo said.
Generation Sale, ESG Report
Izzo said PSEG has received “initial indications of interest” from potential buyers for its 467 MW of solar generation and its 6,750-MW fossil generation fleet in New Jersey, Connecticut, New York and Maryland, which it put up for sale last July. Izzo declined to name potential buyers but said “we are on track to announce an outcome in the second half of 2021.”
The company is selling the generation assets as part of its planned transformation to a “primarily regulated electric and gas utility,” Izzo said.
Responding to an analyst’s question, Izzo said the widespread generation outages that accompanied subfreezing temperatures in ERCOT will have no impact on the company’s operations. “Our near-death experience in January of 2014 with our own polar vortex really has winterized these assets in a way that I’m sure Texas will now follow suit with,” he said.
PSEG plans $14 billion to $16 billion in capital spending for 2021-2025. | PSEG
In January, PSEG released its first environmental, social and governance (ESG) performance report, which included an expanded disclosure of employee demographics along with new goals for fleet electrification and waste reduction. The company’s carbon-reduction plan calls for an 80% decrease in emissions below 2005 levels by 2046, with the goal of achieving net-zero by 2050.
By 2030, the utility said, it will convert all passenger vehicles, 62% of medium-duty vehicles and 90% of heavy-duty vehicles to battery electric vehicles, plug-in hybrids or “anti-idle job site work systems.”
It also pledged to reduce the total weight of waste that is landfilled and incinerated to 4.78% of the total waste generated by Public Service Electric and Gas by 2023.
The report also mentions the BPU’s approval in January of $205 million in spending by PSE&G on EV infrastructure. (See NJ BPU OKs $205M EV Spending by PSE&G.) And it noted that the company will retire its last coal-fired unit, the 383-MW Bridgeport Harbor 3 generating station, in June.
Looking ahead, Izzo said PSE&G is forecasting capital spending of $14 billion to $16 billion through 2025, with 50% going toward carbon-reduction investments, including energy storage, energy efficiency, methane emission reduction and advanced metering infrastructure.
Offshore Wind
However, Izzo noted the capital spending forecast does not include any potential investments in offshore wind. PSEG agreed in December to take a 25% stake in Ørsted North America’s 1,100-MW Ocean Wind project, which won the BPU’s first offshore wind solicitation. Construction on the project, 15 miles off the Atlantic City coast, is expected to begin next year, with commercial operation expected in 2024.
PSEG has an option to increase its stake in Ocean Wind by an additional 25%. Izzo said the company is taking a cautious approach and would not seek to increase its stake beyond 50%. “The commercial risk is completely mitigated by the [power purchase agreement with New Jersey]. And the operational risk is mitigated by making sure you partner with a world-class partner. And we think we have that in Ørsted,” he said.
He was bullish on the company’s chances to build the onshore transmission needed to connect New Jersey’s OSW to PJM’s grid.
“There is likely to be a transmission solicitation that will be managed by PJM on behalf of New Jersey that we feel very confident that we could do something of that sort without necessarily needing partners, although we will be welcomed to partnerships in that regard too,” he said. (See NJ Asks PJM to Seek Bids for OSW Tx.)
Q4 Results
PSEG reported declining profit and revenue in its most recent quarter, blaming mild weather for depressing electricity demand.
Net income was $431 million ($0.85/share) in the fourth quarter of 2020, compared with $437 million ($0.86/share) a year earlier. Revenue fell to $2.4 billion, below the $2.73 billion predicted by analysts.
On an adjusted basis, profit was 65 cents/share, in line with Wall Street’s expectations. Most of the difference was attributed to a 31-cent/share gain from PSEG Power’s nuclear decommissioning trust fund.
OGE Energy and CenterPoint Energy executives last week added color to their agreement disposing of their master limited partnership in Enable Midstream Partners, a gas-gathering business being acquired by Energy Transfer.
Both companies said Energy Transfer’s $7.2 billion all-equity acquisition of Enable will allow them to focus on transitioning to a fully regulated utility business model and lessen their exposure to the gas market’s volatility.
CenterPoint CEO David Lesar reminded financial analysts during an earnings call Thursday of his earlier comments to them that the Houston-based company is “absolutely focused on reducing and eventually eliminating our midstream exposure through a disciplined financial approach.”
“And now have a transaction that we expect to achieve … exchanging our interests into a more liquid security, which will facilitate an accelerated exit, increased autonomy … giving us flexibility to make decisions about our exit strategy, and, of course, that reduces risk to distributions while we wind down our position,” Lesar said. “This transaction will have zero impact on our broader strategic goals.”
As CenterPoint’s earnings call concluded, OGE’s began.
“Let me be clear: We will exit our midstream investment, and we will do so in a responsible way that does not create overhang to the Energy Transfer units,” CEO Sean Trauschke told many of the same analysts. “We will do what we’re focused on … making sure that we continue to take costs out of our business to minimize that impact to customers at the same time.”
Trauschke said the company plans to reinvest the reinvest the transaction’s proceeds back into its utility business, Oklahoma Gas & Electric.
“We are not constrained or limited in any way in terms of the opportunities we see in our growing service territory,” he said.
CenterPoint Energy crews restoring power in Texas following February’s winter storm | CenterPoint Energy
OGE holds a 25.5% limited partner interest and a 50% general partner interest in Enable. CenterPoint owns 53.7% of the common units representing Enable’s LP interests. It will own approximately 3% of Energy Transfer’s outstanding LP units after the merger’s consummation, which is expected later this year.
CenterPoint will also pay OGE $30 million when the transaction closes.
Lesar also addressed the company’s restoration efforts following the Feb. 15 power outages that almost knocked out the ERCOT grid. He said once power was restored to CenterPoint’s system, the utility was able to bring power back to 98% of its 2.6 million electric customers in about 12 hours.
“This was a systemwide failure across the state, as has been well written,” he said. “There’ll be something that comes out of [the state legislature] from this, but people have done a good job of understanding our role in this.”
The company spent an additional $1.25 billion buying natural gas during the outage, Lesar said. CenterPoint will work with regulators to recover the costs.
CenterPoint reported fourth-quarter earnings of $15 million ($0.27/diluted share), up from 2019’s closing quarter of $128 million ($0.25/diluted share). Year-end earnings resulted in a $949 million loss (-$1.79/diluted share), compared to a $674 million ($1.33/diluted share) profit the year before.
On a guidance basis that excluded income and debt from the Enable preferred units and other impairments, earnings were $173 million ($0.29/share) for the quarter and $793 million ($1.40/share).
The company’s share price finished the week at $19.44, a 6.4% drop from Wednesday’s close of $20.78.
OG&E Files $1B Cost Recovery
OGE also reported a loss for 2020, saying year-end earnings were $173.7 million in the red (-$0.87/diluted share), compared to 2019’s earnings of $433.6 million ($2.16/diluted share). For the quarter, earnings were $54.8 million ($0.27/diluted share), compared to $35.4 million ($0.18/diluted share) a year ago.
The company said OG&E was among several utilities that began recovery proceedings at the Oklahoma Corporation Commission over restoration costs following February’s severe winter storm. OG&E is seeking to recover $1 billion for natural gas and purchased power costs, more than 2019’s total fuel costs.
Snow buried Oklahoma several times this winter. | OG&E
Trauschke said OGE has secured $1 billion of additional bank financing or liquidity to cover the costs.
“We certainly understand the pressure that this event will have on our customers, and we will work with our commissions to help mitigate the impact to our customers’ bills,” he said.
OGE’s stock price fell 5.5% following the earnings release, closing the week at $29.27.
NYISO on Thursday discussed potential steps to better align New York State Reliability Council (NYSRC) studies for setting the statewide installed reserve margin (IRM) with the ISO’s studies for establishing locational minimum installed capacity requirements (LCRs) for the zones associated with the Hudson River Valley, New York City and Long Island.
The IRM and LCR studies have historically used many of the same starting assumptions, with several exceptions, such as the former’s use of the preliminary forecast of the following year’s peak demand, while the LCR study uses the final peak load forecast, said Joshua Boles, NYISO senior manager for market operations. Boles presented proposals to determine market requirements to the Installed Capacity Working Group (ICAPWG).
Stakeholders discussed related proposals, such as expanding the number of peak load hours identified for use in allocating the obligations of load-serving entities in the Installed Capacity (ICAP) Market and updating procedures to better align the LCR process with the IRM process.
New York Control Area reserve margins for the years 2006 through 2020 | NYSRC
NYISO and its stakeholders recently adopted an economic optimization method for establishing LCRs, which resulted in the ISO, per its tariff, adding several assumptions to the LCR study process that are not present in the IRM study process.
New York Control Area load zones | NYSRC
NYISO’s tariff also requires it to incorporate transmission security limits (TSLs) into the IRM study. Stakeholder proposals include using the IRM study peak load forecast in the LCR study process. The NYSRC has prioritized evaluating the appropriateness of incorporating TSLs into the IRM study.
The NYSRC will discuss this evaluation in May. “We are reviewing if tariff changes are necessary and expect to have an answer for stakeholders by mid-March or April,” Boles said in response to a stakeholder who urged moving fast enough to have any possible revisions in effect for 2022.
NYISO establishes ICAP market requirements for the spot market auction construct each year to help the grid operator and the NYSRC satisfy the one-day-in-10 years loss of load expectation standard. These requirements determine the minimum quantity of ICAP that loads must purchase.
Peak Hour Forecasts
On expanding the number of peak load hours for use in allocating LSE obligations in the ICAP market, Ethan D. Avallone, NYISO capacity market design technical specialist, asked whether transmission owners could fold that additional information into their process.
The current process of setting the minimum unforced capacity (UCAP) requirements for LSEs is based on the single peak load hour identified by the ISO, which is ultimately used by the TOs to assign capacity obligations to the LSEs serving load by transmission district.
“Aside from that, when the ISO does provide a single peak load hour today, some things are already added back in, but should the TOs and NYISO add back other things into the load forecast?” Avallone said.
NYISO each September identifies the New York Control Area (NYCA) peak load date and hour for the current capability year. For example, in September 2021, the ISO will provide this information for the 2021 capability year.
The peak hour load received from the TOs includes demand reductions during that hour from all special case resources (SCRs), which are demand response resources participating in the capacity market, but the TOs choose whether their own load reduction programs that do not overlap with SCRs should be added back into the load.
Results from 2020 final LCRs vs 2021 final LCRs | NYISO
Municipal generating units that participate in the capacity market are also added back into the load, but there currently is no adjustment to add back generation from resources not participating in the wholesale markets, such as production from rooftop solar.
Ryan Carlson, NYISO senior resource adequacy analyst, reviewed possible updates to LCR procedures to better align that process with the IRM process, such as in the handling of updates to load forecasts after the October IRM Study lockdown date, and whether updates should be made only if changes are also made to the data and assumptions used to calculate the IRM.
Stakeholders want NYISO to perform additional review of year-over-year changes and include drivers of those changes as part of the informational LCR results presented to stakeholders in the fourth quarter of each year.
In presenting a comparison of the IRM final base case with the final LCRs, Carlson said, “These results were definitely discussed here very broadly, which spurred the potential idea of changing the LCR process around to reduce what some saw as volatile results.”
The ISO plans to return to the ICAPWG with updates in April.
MISO is still collecting data and reviewing the actions it took during a massive cold spell that gripped most of the U.S. in mid-February.
Frigid temperatures Feb. 14-16 across most of the RTO’s footprint created paper-thin — and then nonexistent — reserve margins, particularly in MISO South. In all, MISO temporarily interrupted load Feb. 16-17 in parts of Southeast Texas, South and Central Louisiana, and South-Central Illinois. The rotating outage orders ended Feb. 17 at 1 a.m. EST.
“There’s just so much to still unpack from last week. … There’s going to be so much information coming out in the next few weeks,” MISO Senior Director of Operations Planning J.T. Smith said during a Reliability Subcommittee teleconference Feb. 25.
Smith said while operations and actions taken were similar to previous cold weather events in MISO South, the biggest dissimilarity was how far-reaching the arctic blast was.
“This was a more widespread cold weather event,” Smith said. “This time our neighbors weren’t as spared.”
He said the frigid air brought rain and snowstorms in addition to a band of ice storms that traveled through southern portions of the footprint.
“It wasn’t just cold weather, it was also severe weather,” he said.
The National Oceanic and Atmospheric Administration said nearly three-quarters of the contiguous U.S. was blanketed in snow Feb. 16.
After MISO declared the grid stable on the afternoon of Feb. 17, the South region briefly slipped back into an emergency event.
Smith said the RTO knew a week in advance that a polar vortex was imminent and began reaching out to members for their generation availability. Complicating matters, he said, was the Presidents’ Day gas trading holiday on Monday. He said MISO urged members to secure all fuel needs during gas clearing on Friday.
“We tried to be as thoughtful as possible on the front end of it, but once we got into real-time … we saw the extreme cold on the generation and transmission become much more stressful,” he said.
Smith said MISO issued multiple emergency declarations as it became clear the system couldn’t support the demand and overcome forced outages and fuel scarcity. He said energy was initially able to flow east to west to SPP, but those flows ground to a halt as the situation deteriorated.
“To make sure we didn’t lose more, we had to shed some load in a couple different instances,” Smith said.
He said the grid operator shed roughly 700 MW on the evening of Feb. 16, but he did not have numbers for the other events.
“There were a lot of things moving at the same time. It truly was an unprecedented environment that happened last week. There will be a lot of conversation,” he promised stakeholders. He said staff would offer more details and a timeline of the event at upcoming stakeholder meetings.
‘Mixed Bag’
It usually takes the grid operator a few months to collect data and publicly present a detailed review of congestion, import capability, generation outages and emergency response performance.
Smith said MISO navigated several transmission constraints and multiple emergencies in separate parts of the footprint because of a combination of unavailable fuel supply, generation trips, system operating limits and transmission congestion.
“It was a mixed bag all across all regions. It wasn’t just one area; there were outages all over the footprint,” he said.
In all, Smith said roughly 60 GW of capacity was unavailable at different times across the event.
Entergy storm restoration in Louisiana | Entergy
MISO had predicted “minimal risk” throughout February in its annual winter preparedness workshop in the fall. It originally said January held the lion’s share of wintertime risk and that by February, generator maintenance outages could ramp up. (See MISO: Winter Could Get Tricky Despite Forecast.)
“We were in February. We’re usually past the risk by the end of January. We had some units that were getting ready to get on outages that our membership worked to move. In fact, one of our members had to move a planned outage twice because the cold lasted so long,” Smith said.
January operations were mild compared to February’s wild conditions. MISO’s January load averaged 76.2 GW with a “mild” 91.3 GW peak, the lowest January peak in four years, Smith said.
“Overall, it was a fairly benign month,” he said.
Guinea Pigs
Until now, MISO had recently been hosting short, uneventful meetings of its Reliability Subcommittee.
“Something tells me our next meetings won’t be so abbreviated. … I think we’re going to be rolling up our sleeves for the next several meetings,” RSC Chair Ray McCausland said during a MISO Advisory Committee teleconference Feb. 17.
McCausland said MISO may schedule joint meetings of its Market, Resource Adequacy and Reliability subcommittees, like it did in the wake of Hurricane Laura.
A week ago, MISO executives defended its last-resort emergency actions.
“MISO operators are highly trained to respond to multiple large-scale disruptions that can occur during tight operating conditions,” said Executive Director of System Operations Renuka Chatterjee. “We prioritized these challenges and made quick decisions to protect the integrity of the bulk electric system.”
Prior to last week’s deep freeze, MISO was pursuing a redesign of its resource adequacy construct, which includes more attention on wintertime reliability risks, seasonal capacity auctions and a pivot to an “available capacity” accreditation proposal, where accreditation values are rooted in generators’ past performance.
The Advisory Committee will hold a discussion on the potential new resource adequacy design during MISO’s quarterly Board Week in March, which will undoubtedly feature talk on the winter emergencies.
Clean Grid Alliance Executive Director Beth Soholt asked if MISO’s resource adequacy rethink will sufficiently address challenges unearthed in the deep freeze, which she said included performance issues across all resource types — frozen coal piles, unavailable pipelines and iced turbines.
“I think every resource type has had problems, in particular across Texas,” Soholt said during an Advisory Committee teleconference Feb. 17. “Are we adequately factoring this in?”
Resource Adequacy Subcommittee chair Chris Plante said MISO’s available capacity accreditation proposal should take an unbiased measure of resource availability.
Madison Gas and Electric’s Megan Wisersky said no other capacity market uses an available capacity accreditation and the concept remains unproven.
“We’re sort of guinea pigs in this. This is untested. I’m not saying it’s good or bad; we’re just guinea pigs,” she said.
NYISO is looking forward to a more supportive political environment at the federal level after a challenging yet fruitful 2020 spent adapting to the pandemic and enhancing market rules to better align with New York’s clean energy transition, CEO Rich Dewey said last week.
“We’re much more likely to have a federal energy policy more closely aligned with the energy policy of New York” with the new Biden administration and leadership changes at FERC, Dewey told the ISO’s Management Committee on Wednesday in an informal “State of the Grid” address. “Some of the political conflict that we’ve been figuring out how to navigate our way through could ebb away and really provide an opportunity for us to come up with a set of rules that recognizes that consistency between the federal and the state policy.”
During his first open meeting as chair on Feb. 18, FERC Chairman Richard Glick ended several proceedings related to capacity markets, while also promising to take a new look at some issues. (See “Next Chapter on RTO Capacity Markets,” Glick Hits ‘Refresh’ at 1st FERC Open Meeting.)
Dewey referred to the “tension and stress” the ISO experienced last year, “specifically around buyer-side mitigation (BSM).”
“You’ve seen some of the policy statements coming from the FERC, and it signals some changes that we’re going to need to address, and you’re starting to see developments in the way of technical conferences on capacity market changes … particularly relating to the minimum offer price rule [MOPR] and BSM,” Dewey said. “You’ve seen some of the statements coming from the chair that the MOPR is unsustainable and that we need to look for solutions that more effectively accommodate the entry of the public policy resources and do so in a way that we can maintain just and reasonable rates.”
NYISO is working to update its BSM processes in order to compensate for the growing disconnect between the original design, intended to cover a few new resources in any given class year, and the up to 50 such resources to be evaluated currently. (See NYISO Explores Improving BSM Processes.)
State officials continue to fine-tune the various clean energy programs, and the New York Power Authority and Public Service Commission have been supportive of the ISO’s public policy transmission process. “We’re very encouraged by the prominence New York state is placing on that,” Dewey said.
New York’s Climate Leadership and Community Protection Act goals are coming into sharper focus, Dewey said. “When we think of getting to 70% renewable electricity by 2030 and 100% carbon free by 2040, reaching those goals will take everything we’ve got.”
The recent supply problems in Texas serve as a reminder to keep reliability as the “paramount concern,” he said.
Survey Says NYISO Satisfies Customers
The annual performance assessment and customer satisfaction survey conducted by the Siena College Research Institute (SCRI) shows NYISO last year continued to score the highest mark and improved slightly on its 2019 results.
The ISO’s 2020 final scores for satisfaction of 91.5 and performance assessment of 77.6 are the highest ever recorded since the introduction of a new polling system in 2016, with a year-end combined score of 86. As in last year’s survey, 60% of the combined score is satisfaction and 40% the performance assessment.
NYISO Survey: Siena College’s annual customer satisfaction and performance survey shows the grid operator improving its overall scores for the past five years. | NYISO
“The customer inquiry satisfaction score was the highest ever, at 98.6, and I think most of us would be happy if a child came home from school with that number on the report card,” SCRI Director Don Levy said.
“I look at the survey responses every quarter, and if anyone gives a particularly negative feedback we try to address it right away and change the situation if possible,” Dewey said. “I get a lot more value out of the deep dive into specific situations because it reveals how someone is thinking.”
Operating out of a pair of dueling hearing facilities for two days last week, Texas lawmakers took their first shots at the electric industry as they began to try and grasp the complexities of a system that failed during mid-February’s “unprecedented weather event.”
Some legislators, blessed with a better understanding than others of the grid’s innerworkings, tried hard to understand what went wrong when ERCOT began dumping up to 20 GW of load Feb. 15, pushing much of its grid into blackout conditions as it tried to avoid a total collapse. They dug into the events that led to the load shed and the market’s pricing intricacies.
Others simply gave voice to their constituents’ frustrations, questioning the energy-only market’s wholesale price-indexed rate plans that have led to five-figure bills and why ERCOT’s Board of Directors included out-of-state directors.
“Who’s at fault? I don’t want to hear about systems; I want to know who’s at fault,” Rep. Todd Hunter (R) demanded of Curt Morgan and Mauricio Gutierrez, the respective CEOs of Vistra and NRG Energy, before the House State Affairs and Energy Resources committees on Thursday.
Vistra’s Curt Morgan (left) and NRG’s Maurico Gutierrez address a joint session of the Texas House’s State Affairs and Energy Resources committees. | Texas House of Representatives
“I want the public to know who screwed up,” he continued. “That’s what people want to know. I want names and details. Tell me some specifics!”
“I don’t think you can put one thing at fault,” Gutierrez started to explain. Pressed again by Hunter, he then relented by listing ERCOT, the power generators, the transmission and distribution providers, and the Public Utility Commission before being cut off.
On the Senate side, lawmakers grilled ERCOT CEO Bill Magness for five uninterrupted hours that same day. PUC Chair DeAnn Walker followed him in the hot seat before the Senate’s Finance Committee and Business and Commerce Committee, staying there for two and a half hours.
The two then sat together for more than five hours before the House committees. Their “day” finally ended at 12:26 a.m. Friday.
Magness explained the decision-making process that led to the lead shed, repeating some of the same information he shared with his board the day before. (See related story, ERCOT Provides ‘Explanations, not Excuses’.)
Asked by Sen. John Whitmire (D) whether he would have done anything differently, Magness said he wouldn’t.
“Obviously, what you did didn’t work. I think that’s fair to say,” Whitmire said.
Magness disagreed.
“Respectfully, I’d say it worked from keeping us into a blackout that we’d still be in today,” he said. “That’s why we did it. Now, it didn’t work for people’s lives, but it worked to preserve the integrity of the system.”
Sen. Brandon Creighton (R), representing a far northern Houston suburb where an 11-year-old boy died of hypothermia in an unheated mobile home, pressed Magness on why ERCOT wasn’t more upfront with its communication regarding the winter weather and possibility of tight supplies.
Magness said those communications began Feb. 8 with an operating condition notice and included his appearance at a Feb. 13 press conference with Gov. Greg Abbott. Staff issued a press release Feb. 14 urging customer conservation, a message amplified by its Twitter feed.
“We do know lives were lost. In my opinion, rather than the dollars being considered, that’s the ultimate loss,” Creighton said. “It did not resonate with us that we could have very cold conditions coming in. It did not resonate to us that the grid could be at risk from a supply standpoint. Foreseeable or not, that could be a situation that occurs. … It’s very much my opinion that you define those communication protocols immediately.”
Magness nodded in agreement.
Under further questioning, he said staff alerted the generators and transmission providers that cold weather was coming and that it would be a “significant event.”
“Internally, we knew we may need to run the processes that go into load shed and emergency operations,” Magness said. “We try to make those contacts through the PUC. We shared those notices with PUC and the senior staff, and we continued to share those notices.”
“We have to review what happened and ensure it doesn’t happen again,” Walker said later. “It wasn’t just the operational area, but the communication area. Could all of us have done better? Absolutely.”
A number of legislators remained unconvinced by what they had heard.
Sen. Charles Schwertner (R) said he remained unsettled about ERCOT’s preparations for a “once-in-a-generation” storm, managing the crisis and making decisions, and called for the grid operator’s reform “to ensure this doesn’t happen again.”
“I still have great concerns about the entirety of the agency,” he said. “The testimony has not been, on my part, overall encouraging.”
Hunter pointed to Abbott’s Feb. 16 statement, when the governor said, “ERCOT failed to do its job, and Texans were left shivering in their homes without power.”
“He basically indicated … ERCOT failed to do its job and made assurances the Texas infrastructure was prepared for the winter storm, and it wasn’t,” he said. “It’s hard to tell the general public to put a lot of faith in ERCOT. I haven’t heard anything positive, and I see everybody running away.”
Legislators Focus on PUC’s Walker
When the two days of hearings concluded, Walker found herself sitting alongside ERCOT in the ring of incoming fire from lawmakers.
In all, more than a dozen legislators, Democrats and Republicans alike, called for her resignation following the hearings, citing her unwillingness to exert the commission’s oversight responsibility of ERCOT.
PUC Chair DeAnn Walker (left) listens to Texas Sen. Sarah Eckhardt (D) question ERCOT CEO Bill Magness. | Texas Senate
Putting on his best Perry Mason, Rep. Rafael Anchía (D) led Walker through more than 30 minutes of testimony, during which she admitted the PUC had “total” control over ERCOT, that the commission could have leveraged its authority in requiring emergency operations plans and weatherization standards, and that she could have been more proactive in warning the public.
“When did you make the clarion call to the public that we had a major problem and people were likely to die?” Anchía asked.
“I don’t remember when. I know we were sending things out Thursday and Friday,” Walker responded.
Eventually, she admitted that “we all made errors. I think I made errors in doing my job.”
“Do you think the public deserves an apology from the PUC?” Anchía questioned.
“No further questions,” he said, cutting off any further responses.
Anchía later issued a statement calling for Walker’s immediate resignation for “failing to perform required oversight duties of ERCOT.”
“After two days of testimony, it is clear to me that there was a dereliction of duty and that the people of Texas deserve nothing less than for Commissioner Walker to resign immediately,” he wrote. “Her inability to even muster an apology to Texans who endured freezing temperatures without heat or power and resulted in loss of life is inexcusable.”
Rep. Abel Herrero (D), vice chair of the Energy Resources Committee, noted that Abbott had praised the resignations of several of ERCOT’s board members. (See ERCOT Chair, 4 Directors to Resign.) He asked Walker if the governor, who appoints the PUC’s commissioners, had asked for her resignation.
“He has not,” she said.
The PUC on Friday tweeted it had opened two new projects related to the winter storm: a rulemaking on weatherization standards (51840) and a review of electric service emergency operations (51841). However, that was too late for some legislators.
Anchía, Herrero and six other lawmakers sent a letter to Walker on Friday asking for her resignation, alleging she had failed in the PUC’s mission to “protect customers.”
Saying that they had “lost all confidence that you can, or even care to, do your job,” the representatives wrote that, “at no time during your tenure as [PUC chair] have you taken accountability measures against ERCOT. There is little indication that you enforce, or are even aware of, some of the most critical functions of your agency.”
Rep. Jeff Leach (R) said Magness and Walker’s fellow commissioners, Abbott appointees Arthur D’Andrea and Shelly Botkin, should resign as well. He said it was “his strong belief” the long-term outages and the misery they caused could have been avoided.
Their resignations are “a necessary step so we and our constituents can be confident the right leadership is in place to ensure this never happens again in Texas,” Leach tweeted.
ERCOT Board Loses 2 More Directors
By the time Magness testified before the House committees, word had already leaked out that ERCOT had lost another director from its board. He acknowledged that an unnamed director had resigned (some quick online sleuthing revealed it was Brazos Electric Power CEO Clifton Karnei) and implied the decision had to do with financial issues at his cooperative.
ERCOT CEO Bill Magness addresses questions during a Texas Senate hearing. | Texas Senate
“I hear board members are jumping ship like rats on a sinking ship,” Herrero said to Magness.
“I think they saw a desire to have Texas residents involved and said, ‘We may not be the best people for the board,’” Magness replied.
“My problem as a lawmaker is we’ve had five non-Texans bail on this state,” Hunter said. “When the heat came on, they bailed. I don’t know if that’s a preview of coming attractions or what.”
The non-Texans serving on the board had drawn much of the politicians’ and public’s ire, but Karnei, a Texas university system graduate, had served on the board since at least 2001 and represented the cooperative segment. He joined the five out-of-staters who submitted their resignations Feb. 23. A sixth non-Texan withdrew his nomination for a board seat.
But the names keep disappearing from the board’s webpage. Karnei’s departure was followed on Saturday by that of Austin Energy General Manager Jackie Sargent, who represented the municipal segment. Sargent has been critical of ERCOT’s actions in anticipating and responding to the blackouts.
“The system we have, requiring a utility to force over 30% of our customers to be without power for such an extended period of time, is unacceptable,” she told the Senate committee hearing on Friday.
The departures leave the 16-person board with eight confirmed directors. The five independent director positions unaffiliated with ERCOT market participants and three of the eight market segment positions are vacant, though all but one of the segment alternates remain.
Magness, Walker and Lori Cobos, CEO of the Office of Public Utility Counsel, round out the board. Walker is the only non-voting member.
The grid operator’s bylaws under the state’s Public Utility Regulatory Act require 50% of the seated directors be present to reach quorum, with quorum being three when the number of seated directors is less than six and not less than three. Quorum is not possible with two seated directors. The board’s next scheduled meeting is April 13.
The board’s independent directors are nominated for three-year terms by the board following a search process, and then approved by ERCOT members and, finally, the PUC. The chair and vice chair positions are required to be filled by independent directors.
Segment directors are nominated for single-year terms by their segment representation.
Magness told the House committees the unaffiliated directors were added because “if you had an all-industry board, you need nonbiased, non-industry folks on the board to round it out.”
Asked whether there should be more consumer representation on the board, Magness said, “Y’all pretty much made us, so you can change us.”
Rep. Will Metcalf (R) indicated that very well may happen.
“I want the best CEO running my company. I want to make sure we’ve got the best leader. I don’t want board members from outside Texas,” he said. “Going forward, I want the best person running the show, and I want board members from Texas.”
Vistra’s Morgan: ‘Lack of Urgency’
Vistra’s Morgan said he was frustrated by what he saw as a “lack of urgency” from others as the winter storm approach.
Morgan told the House committees on Thursday that the company’s meteorologist saw the same incoming weather that ERCOT did but thought it would create more demand that the grid operator was seeing. He said Vistra was projecting nearly 75 GW of demand, while, at the same time, ERCOT was expecting to break its winter peak of 65.9 GW. (See ERCOT Bracing for Winter Storm, Record Demand.)
The meteorologist “said we didn’t have enough generation on the ground,” Morgan said. “We did what we normally do: We reached out to some of you here. We were very concerned. I was surprised about the lack of urgency I got from some of the officials in the agencies. The level of urgency was just not there.
“We do know [ERCOT] moved the demand forecast up. Even with perfect execution, I thought we were short, but nothing like what happened,” he said.
Pressed on his comments, Morgan said of ERCOT staff, “It’s wrong to say they didn’t do anything. They do what they normally do. I don’t think there was a broader communication to the public that we were running into a problem. There was not this broad communication that said, ‘Hey, we could be into rolling blackouts on Monday.’”
Magness said he didn’t have any conversations with Dallas-based Vistra about differences in demand forecasts, but he did say his staff had discussions with the company’s representatives.
“Everyone, especially in North Texas, kept getting concerned. They were right in the middle of the worst part of the storm,” he said. “We understand those concerns. We felt the same way. We were getting our concerns out to the industry.”
ERCOT did issue a press release at 8:50 a.m. Feb. 14, warning of potential rolling blackouts. It later set a new winter demand peak at 69.2 GW several hours before generation fell off the grid.
Winterization to be Reckoned With
Winterization has emerged as the primary area of focus in preventing a reoccurrence of the rolling blackouts. Abbott has called to “mandate and fund” winterization and several legislators took up that call.
However, the same thing happened during the winter of 2011, when 14 GW of generation were knocked offline and forced ERCOT to call for rolling blackouts. The state fared much better during a 2018 winter storm, when only about 4 GW of generation was lost.
Winterization, recommended after 2012, has never been enforced.
“We’re not regulators, and we don’t have the [enforcement] authority, so we’re trying to assist generators in ERCOT [in getting] better from learning what we have learned and what others have learned,” Magness said.
Magness and several generation owners reminded the legislators that Texas’ energy infrastructure is built for the 100-plus-degree heat of July and August. Following the same winterization protections as in the northern states by encasing turbines with walls would lead to overheating and reduced efficiency during the heat of summer.
ERCOT joins with the Texas Reliability Entity to host an annual workshop on winterization practices. Generators are required to file their winterization plans with ERCOT, which in turn files a report with the PUC.
NRG’s Gutierrez said that in the end, the winterization efforts may not have mattered. Temperatures in the ERCOT footprint were much colder for longer than in 2011. The Dallas-Fort Worth metroplex saw a low of -2 degrees Fahrenheit and spent 140 hours below freezing. In 2011, those numbers were 13 and 101, respectively. Austin’s low was 6 F and Houston’s 13 F.
“Did we winterize? Yes,” he said. “Did we secure fuel supply? Yes. Did we bring as much capacity as we could? Yes. Did we bring critical supplies? Yes. Did we put all human resources? Yes. It was not enough, not enough.”
The Pennsylvania Department of Environmental Protection (DEP) is drafting a proposed rulemaking to require automakers to include light-duty electric vehicles as a percentage of their model offerings and make EVs more commonly available at car dealerships.
Officials said the proposed amendment to the state Clean Vehicles Program would make Pennsylvania the ninth state in the Northeast and Mid-Atlantic regions to adopt a light-duty zero-emissions vehicle (ZEV) percentage requirement. DEP said the revision would ensure that automakers make available in Pennsylvania new ZEVs that otherwise would be offered in surrounding states with such a requirement.
Officials expect DEP’s Bureau of Air Quality to present the proposed rule for consideration to the Environmental Quality Board in the fall.
During a recent budget hearing, state Rep. Tim O’Neal (R) asked DEP Secretary Patrick McDonnell if he was in favor of banning the sale of gasoline powered vehicles, and McDonnell said “no.”
O’Neal said he was concerned the proposed rule and program development would be too similar to regulations coming out of California and could lead to the banning of the sale of new gasoline vehicles. O’Neal asked if a California policy for EVs is appropriate for Pennsylvania.
Electric vehicle charging stations located outside the Pennsylvania State Capitol complex in Harrisburg | Pa. DEP
McDonnell said the proposal is still being developed and that the exact percentages of offerings have yet to be determined.
“This is about improving consumer choice and meeting consumer demand within the Commonwealth of Pennsylvania for electric vehicles,” McDonnell said.
According to a recent study by the American Council for an Energy-Efficient Economy, Pennsylvania ranks 17th among the 50 states and Washington, D.C. in transitioning from gas-fueled vehicles to EVs.
The D.C.-based nonprofit rated the states on their efforts to reduce greenhouse gas emissions and improve access to EVs. The study found the easiest ways states can promote EVs are to install more charging stations, offer rebates, tax credits and grants for the purchase of electric cars and buses and to develop utility programs offering lower costs for EV owners.
Charging Infrastructure Expansion
On Feb. 19, DEP announced more than $900,000 in funding for the installation of fast chargers in high-traffic areas as part of its Driving PA Forward program, using proceeds from Pennsylvania’s share of Volkswagen’s settlement for falsifying EPA emission tests.
The DEP awarded $750,000 to EVgo Services of California for the addition of 14 fast chargers at three locations: a shopping plaza in Philadelphia, located within a half-mile of Interstate 76 and three miles of Interstate 95; a market in Delaware County within two miles of I-95 and I-476; and a gas station in Allegheny County, less than a mile from the Pittsburgh International Airport and four miles from I-376.
The DEP also awarded EV Build of Kansas $186,619 to install two fast-charging plugs in a mall parking lot in Bucks County along high-traffic Route 309 and within four miles of I-476.
Officials said the projects increase the number of locations in a network of highway segments that DEP and PennDOT are helping to develop into electric vehicle corridors for long distance EV drivers. The corridors are expected to have EV chargers every 50 miles along highway routes and no more than five miles from the roadway.
Driving PA Forward has funded 40 fast chargers since the program launched two years ago, officials said, and more than 1,300 level 2 EV chargers have been installed or are in development by companies, local governments and travel organizations around the state.
The DEP Energy Programs Office recently released an update to the state’s Electric Vehicle Roadmap to provide information on driving and purchasing EVs. The booklet is designed to present an overview of the benefits and basics of EVs, a look at current EV use in Pennsylvania and tips for consumers.
A bill to make carbon offset projects affordable for small landowners is making its way through the Hawaii legislature.
Senate Bill 493 would establish an “agriculture and forest carbon-positive incentive program” to encourage small agricultural producers to reduce emissions by helping them pay for carbon sequestration efforts and clean energy use. Part of the state’s effort to reach carbon neutrality by 2045, the program is intended to create jobs and stabilize the food and water supply for a state almost entirely dependent on shipped goods.
The text of SB493 notes that “while carbon offset credits pay for carbon-positive actions, certification is cost prohibitive to small landowners. Incentivizing carbon-positive actions through a payment of services program would allow small farmers, ranchers and landowners to be compensated for taking actions to help Hawaii reach its climate-positive goal.”
The incentive program would be broken into two phases. Phase I activities would help farmers, ranchers and landowners implement a regenerative annual cropping system; improve pastureland, including growing trees and shrubs around pastures (agroforestry); engage in reforestation; protect land from disturbance; institute rotational grazing; and improve foraging.
Phase II activities would focus on energy creation and consumption. The program would cover, “but is not limited to,” biofuel production, methane capture, improved forest management, grazing intensity, mixed production systems, and efficient nutrient and waste management.
Details of SB493 are being debated, including how the incentives would be funded. The current bill proposes to create a special fund to be financed, in part, by revenue from the state’s Environmental Response, Energy and Food Security Tax. That tax was established in 2010 to discourage fossil fuel use and fund energy and food-security initiatives by adding $1.05/barrel tax to all petroleum products except aviation fuel. The bill also calls for unspecified funding from the state’s general revenue.
Various state agencies would have a hand in the program. Hawaii’s Department of Agriculture and Department of Land and Natural Resources (LNR) would establish compensation rates and contract terms for the program, with terms ranging from one to 30 years. The Hawaii Green Infrastructure Authority (HGIA) would establish and chair a committee to review applications, with participation from Agriculture and LNR. Eligibility would be determined at the point of application.
General administration of the program would fall to the HGIA and the state’s Greenhouse Gas Sequestration Task Force (GHGSTF), which was established in 2018 under the auspices of the Office of Planning (OP) to harmonize the state’s climate initiative goals with its clean energy and carbon sequestration efforts. The GHGSTF would be required to identify a number of program co-benefits, such as job creation; food security and agriculture for local consumption; water security; increased biodiversity; soil health; and invasive species reduction and removal.
Who’s in Charge?
The GHGSTF addressed SB493 during a Feb. 16 meeting, in which members also discussed various reports and plans pertaining to Hawaii’s broader 2045 carbon-neutral goal. During the meeting, OP Director and GHGSTF Chair Mary Alice Evans expressed concern that the task force does not have enough funding to meet its goal of providing state lawmakers with key reports.
“We weren’t able to get additional funding due to the pandemic, so we will have to make do with the vast expertise of our members to be able to meet at least the interim report and hope that by the time we get to the interim report that there are funds available to finish up the final report to the legislature,” Evans said.
In its Feb. 5 testimony on the bill, the GHGSTF explained that its role of identifying and prioritizing carbon-positive activities is jeopardized by a chronic lack of funding. Evans said, “The OP has struggled providing administrative support to the Greenhouse Gas Sequestration Task Force. Since 2018, the OP has noted this need for additional staffing and funding to support the task force’s work.” The GHGSTF’s Feb. 16 meeting was being held after “a yearlong hiatus because of these significant funding and staffing challenges,” Evans said.
Other testimony submitted Feb. 5 showed strong support for the bill, including from the LNR Department, the HGIA, the Sierra Club and the Environmental Caucus of the Democratic Party of Hawaii, along with smaller groups and individuals.
The Tax Foundation of Hawaii acknowledged the potential benefits of carbon sequestration but questioned whether they “justify grabbing a pot of barrel tax money without going through the normal budgeting process that also considers sweltering primary schools, underfunded state pensions, or disaster relief for rain-flooded or lava-burnt counties, as well as the economic decimation wrought by COVID-19.”
The group suggested that “a direct appropriation of general funds would be preferable” and that “earmarking revenues from any tax type for a particular purpose decreases transparency and accountability.” It also contended that Hawaii State Energy Office or Department of Agriculture would be better suited to administer the program than the HGIA.
The Agriculture Department testified that “the measure assigns extensive and unfamiliar responsibilities to the Department of Agriculture and the Department of Land and Natural Resources. … The department will need substantial assistance to acquire the appropriate expertise to develop compensation rates and carbon incentives contract terms, estimate sequestration rates for priority sequestration activities, develop the technical underpinning of compensation rates for sequestration activities, and conduct landowner outreach.” The agency also wondered what program beneficiaries would consider to be “fair compensation.”
Questioned about the probability of the bill passing, Evans told NetZero Insider that “the 2021 legislative session ends on April 29, and we often don’t know the fate of specific bills until the session adjourns.”
Public Service Enterprise Group CEO Ralph Izzo used the company’s earnings call Friday to lobby for increased subsidies for its New Jersey nuclear plants and predicted the sale of its non-nuclear generation by the end of the year.
