Page 972 – RTO Insider

March 2, 2021

FERC Approves $205,000 NorthWestern Settlement

FERC has accepted a settlement between WECC and NorthWestern Energy for violations of NERC reliability standards, under which the utility will pay $205,000 to the regional entity in addition to performing other mitigation activities.

NERC submitted the settlement to FERC in a notice of penalty in January, which the commission on Friday indicated it would not review (NP21-6), letting the penalty stand. The NorthWestern penalty was the only settlement publicly disclosed by NERC in January, but because of a rule change last year, the organization may limit or withhold disclosure of information relating to violations of the ERO’s Critical Infrastructure Protection (CIP) standards. (See FERC, NERC to End CIP Violation Disclosures.)

Tree Growth Leads to Line Failure

NorthWestern’s settlement stems from violations of FAC-003-4 (transmission vegetation management), specifically requirements R2, which requires applicable transmission owners and generator owners to keep vegetation from encroaching on a line’s minimum vegetation clearance distance (MVCD), and R6, which mandates that 100% of transmission lines be inspected at least once a year for vegetation encroachment. The violation of R2 was self-reported, while WECC discovered the second violation via a subsequent compliance audit.

In its self-report submitted Aug. 21, 2018, NorthWestern told WECC it had discovered two encroachments into the MVCD of its 230-kV transmission line, each of which caused a high-voltage flashover resulting in a sustained outage.

FERC NorthWestern Settlement — NorthWestern Energy generating facilities in Montana: The violation occurred on a 230-kV line between a substation in Billings and nearby Huntley. | *NorthWestern Energy*

The first encroachment was addressed on Aug. 10 when a crew performing a line patrol found a tree growing within the MVCD and removed it at the groundline, causing a flashover and outage that was restored within several hours. The next day a tree-clearing crew returned to remove additional trees along the same line. However, during clearing operations a second flashover and outage occurred, which the utility believed was caused by a different stem of the tree removed the day before. NorthWestern re-energized the line the same day after the remaining trees were cleared.

With both outages restored and the line cleared, the utility ordered a follow-on inspection across all of its bulk electric system transmission lines in case it had missed any other potential vegetation issues. This inspection was completed by Aug. 15, identifying nine additional areas in danger of encroachment and requiring corrective action plans to resolve.

Inspections Leave Room for Improvement

After NorthWestern submitted its self-report to WECC, the RE ordered an investigation from Nov. 27, 2018 through March 20, 2019, to identify potential noncompliance with Requirement R6. The investigation found that while the utility did conduct annual vegetation inspections, these “[relied] solely on … aerial patrols.”

Ground patrols were performed in areas where aerial inspection found potential problems, but WECC said this system was insufficient because the patrols were conducted “during the late to early spring season, [when] much of the vegetation is devoid of foliage.” This meant inspectors had trouble foreseeing the risk that vegetation might pose following periods of high rain later in the year.

Both violations posed a “serious and substantial risk to the reliability of the bulk power system,” according to WECC. While no load was lost because of the R2 violation that caused two outages Aug. 10-11, the RE noted the affected line connected to other 230-kV lines, as well as a switchyard handling both 100-kV and 230-kV lines. As a result, the outages led to a risk of “cascading or widespread outages.”

The R6 violation was assessed at the same risk level because it had led directly to the R2 violation. In addition, the fact that NorthWestern’s subsequent inspection found additional areas of concern clearly demonstrated that its annual aerial patrols were not enough to satisfy the requirements of the standard.

The utility submitted a mitigation plan to address these violations to WECC in June 2019. The plan built on the vegetation removals from the affected line, along with the full aerial assessment, with improvements to the utility’s vegetation management program. Features of the new plan include a second annual aerial inspection conducted in mid-summer; a requirement for ground assessments at water crossings; and technology enhancements to improve data collection consistency, assessment results and response time.

WECC confirmed the completion of NorthWestern’s mitigation plan on Dec. 31, 2019. The RE’s penalty assessment was based on the violation risk factor, which was high for the R2 violation and medium for the other, and the violation severity level, which was severe in both cases. In addition, both infringements lasted more than 160 days, exceeding the time horizon expected for remediation of one hour in the case of R2 and one day in the case of R6.

Mitigating credits were applied in light of the utility’s cooperation throughout the process and the timeliness of its initial self-report from the date of discovering the R2 issue. In addition, it did not fail to complete any applicable compliance directives, submitted all requested documentation on time and made no apparent attempt to conceal the violation. WECC determined that NorthWestern’s management was not involved in and did not condone the actions that led to the noncompliance.

March 2, 2021

Mass. Bill Taps Tax Refunds for Climate-vulnerable Countries

Massachusetts could be the first state to allow residents to donate their tax refunds to help developing nations build resilient communities.

Massachusetts state Reps. Antonio Cabral (D) and Tram Nguyen (D) re-introduced legislation last month that would include a new section on tax forms asking taxpayers whether they want to donate their state tax returns to the Least Developed Countries Fund. Parties to the United National Framework Convention on Climate change created the fund in 2001 to help the world’s least developed countries prepare for natural disasters and make communities more resilient to adverse weather.

The bill was held up in committee during the last legislative session, when much of the state’s focus was on COVID-19 alleviation and recovery.

The bill establishes the Massachusetts Fund for Vulnerable Countries Most Affected by Climate Change, a voluntary tax-return contribution option that would be incorporated into the United Nations Least Developed Countries Fund. Cabral told NetZero Insider that he is optimistic the bill will pass this year, as there is a major focus on climate legislation in the state.

“A lot more people are not only talking the talk but also walking the walk,” he said. “But this is a new concept, and it takes time for people to get their heads around it.”

Government entities can contribute to the international fund, but individuals cannot. For that reason, it remains largely underfunded, Larry Yu, chair of the Climate Reality Project Boston chapter, told NetZero Insider.

The U.S. contributes less than 10% of the fund, but the Massachusetts bill, if passed, would pave the way for other states to contribute as well, Yu said.

“Then the contribution becomes more significant,” he added, as climate change is causing increasingly intense natural disasters.

Massachusetts Tax Refund Bill — A Massachusetts bill would allow taxpayers to allocate refunds to help developing countries hit by climate-related natural disasters, like Tropical Cyclone Idai, which caused flooding on the Mozambican coast, as seen here. | *Shutterstock*

In 2019, Cyclone Idai killed more than 1,000 people in Zimbabwe, Malawi and Mozambique, and left millions more without food or access to services. Water shortages in Eastern Africa are displacing thousands of people from their homes.

“That [natural disaster] didn’t really hit the news in the [U.S.],” Yu said.

The bill, and addressing climate change in general, is a matter of “moral responsibility, not foreign aid,” Adil Najam, professor of international relations and earth and environment at Boston University, told NetZero Insider.

The least developed countries are 48 of the poorest countries in the world, the majority of which are in Africa and Asia. They are also the countries least responsible for contributing to the climate crisis.

The energy infrastructure in Massachusetts impacts the rest of the world, Cabral said.

The bill is not addressing the question of who is at fault, Najam said. Instead, he added, it addresses shared responsibility.

Donating state income tax returns to the fund is “something easy to do, but very meaningful,” he said.

March 2, 2021February 2, 2024

Lidar Project to Unearth Nev. Geothermal, Lithium Potential

Federal agencies have teamed up to conduct detailed surface and subsurface mapping of a large swath of western Nevada, a project aimed at revealing sites with a high potential for geothermal energy or lithium.

The U.S. Geological Survey and the Department of Energy in September announced the project, called Geoscience Data Acquisition for Western Nevada (GeoDAWN). The study will use light detection and ranging, or lidar, for surface mapping of the area, and geophysical techniques, including aeromagnetic surveys, to look beneath the surface.

DOE officials said last week that the $10 million project is well underway, with completion expected next year. The data will be made public when the project is finished.

The project area includes a roughly 200-mile-long piece of the Walker Lane geologic area, a fault system that runs near the Nevada-California border. The GeoDAWN area also extends into a portion of central Nevada and up to a section of the state’s northern border.

The GeoDAWN area has a high potential for discovery of new geothermal energy resources, according to USGS. The study will also look for spots with large amounts of critical minerals including lithium, which is needed for lithium-ion batteries such as those used in electric cars.

The project will reduce the risk for companies interested in geothermal exploration, said Susan Hamm, geothermal technologies office director in DOE’s Office of Energy Efficiency and Renewable Energy. The project could potentially lead to the establishment of new geothermal energy plants within the next decade, she said.

“It’s going to generate many exciting leads,” Hamm told NetZero Insider.

Finding geothermal clues

GeoDAWN will combine a number of techniques to look for geothermal potential and minerals. In addition to lidar and aeromagnetic surveys, the project will use airborne radiometry and geochemical analysis of rock and brine samples.

Lidar involves bouncing laser beams off the surface of the Earth from an aircraft and measuring how quickly the light returns. The data can be used to produce highly detailed maps of the Earth’s surface.

Magnetic surveys, also conducted from an aircraft, detect small changes in magnetic fields and can spot underground features such as faults.

Many geothermal resources are hidden or “blind,” meaning there’s no surface feature such as a hot spring to show where they are, Hamm said.

Fault patterns are one indicator of where a geothermal resource might lie. Researchers are still discovering what other features are associated with a geothermal resource.

The study will also examine areas where geothermal resources have already been found, for example, during mining operations. Machine-learning will be used to look for the features of those areas at other sites.

“It couldn’t be more exciting,” Hamm said.

Building on Past Work

The project will build on past research on geothermal resources in Nevada.

Researchers from the Nevada Bureau of Mines and Geology previously combined several sets of geologic and geophysical data for a large area in central Nevada. The data included characteristics of surface faults and measurements of gravity and temperature gradients.

The study led to the creation of a geothermal potential map, pointing researchers to two previously undiscovered, blind geothermal systems. At one of those sites, in Gabbs Valley, temperatures of 255 degrees Fahrenheit were found at a depth of 500 feet.

NBMG Director James Faulds said information acquired through the GeoDAWN project will be an important addition to data used in the earlier study. NBMG, which is housed at the University of Nevada, Reno, serves as the geological survey for the state and has provided technical assistance to the project.

New geothermal hot spots may be discovered through GeoDAWN, and the project’s findings will help rate promising geothermal sites already identified, Faulds told NetZero Insider.

GeoDAWN will also help Nevada catch up on lidar data collection. Up until recently, only 6% of the state had been covered by high-resolution lidar, the lowest percentage of any state, according to Faulds. GeoDAWN will bring that figure up to around 31%, he said, with other projects adding about another 9%.

The USGS 3D Elevation Program (3DEP) is working to achieve nationwide lidar coverage by 2023. Faulds said 3DEP has provided matching funds to others interested in lidar projects, such as local water authorities, but that hasn’t been much help for the vast amount of federal land in Nevada. Faulds said he encouraged federal agencies to talk to each other about ways to get more lidar coverage for the state.

In addition to USGS and the DOE Office of Energy Efficiency and Renewable Energy, partners in GeoDAWN include the Bureau of Land Management and the U.S. Department of Agriculture’s Natural Resources Conservation Service.

Mapping Lithium Potential

Nevada lags in lidar data acquisition despite having what may be the most geothermal potential among the 50 states, based on its geology, Faulds said. The state is second only to California in the production of geothermal energy.

Nevada also stands out in terms of lithium potential.

The U.S. is heavily dependent on imports to meet its lithium needs, according to USGS, and currently the only domestic source of lithium is in Nevada.

In contrast to geothermal resources, no one has made a map of lithium potential in the state, Faulds said.

“That is … badly needed to better evaluate where some of those sort of hidden and additional lithium resources might be,” he said.

March 2, 2021

TCI Releases Draft Rule for Cap-and-Invest Program

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.

TCI Cap-and-Invest Program — 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.”

March 1, 2021November 2, 2023

WoodMac: Utility IRPs Driving Record Growth in Storage

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.”

February 28, 2021

PSEG Presses for Higher Nuke Subsidies

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 Nuclear Subsidies — 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.”

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.

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.

Earnings call transcript courtesy of Seeking Alpha.

February 28, 2021

CenterPoint, OGE Look to Exit Enable

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.

The acquisition was announced Feb. 17. (See Energy Transfer to Acquire Enable Midstream.)

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 OGE — 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.

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.

February 28, 2021

NYISO Looks to Enhance ICAP Market Design

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.

installed capacity — 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.

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.

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.

February 28, 2021

MISO Begins Cold Snap Examination

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.

MISO Cold Snap — 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.

The RTO’s load shedding orders were much shorter than ERCOT Provides ‘Explanations, not Excuses’.)

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.

February 28, 2021

NYISO Management Committee Briefs: Feb. 24, 2021

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 Management Committee — 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.”