Page 1050 – RTO Insider

September 2, 2020

MISO, SPP Regulators Ponder Monitors’ Recommendations

MISO’s and SPP’s market monitors on Monday presented their last report to state regulators working to improve the RTOs’ interregional coordination, but members seemed more interested in the lack of joint projects between the two.

MISO Independent Market Monitor David Patton presented his report on interface pricing to the Seams Liaison Committee (SLC), composed of regulators from the Organization of MISO States (OMS) and SPP’s Regional State Committee (RSC). It was the last of the monitors’ studies and reports commissioned by the SLC.

When invited to give their chief concerns about the grid operators’ coordination, stakeholders seemed less focused on interface pricing and more interested in why the RTOs have been unable to agree on beneficial interregional transmission projects.

The American Wind Energy Association’s Daniel Hall criticized the RTOs’ use of different planning futures, models and assumptions in their coordinated system plan (CSP), the studies they use to search for interregional projects.

“There is a need for large interregional projects, but it’s not showing up in the regional studies, and that’s a problem and we need to address that,” he said.

MISO last week said it doesn’t plan to endorse any interregional project possibilities this year after a fourth CSP with SPP. (See MISO, SPP Close to Ruling out Joint Projects Again.)

ITC Holdings’ Brenda Prokop said many transmission owners are similarly questioning the design of the RTOs’ interregional planning, especially since because the TOs are forecasting a “strong need” for transmission buildout along the seam.

“We’re wondering if it’s the most cost-effective and efficient way for the RTOs to be planning in their separate regional process,” Prokop said. She also asked that MISO and SPP “line up” their models and assumptions.

Hall suggested the regulators consider urging the RTOs to create a new category for small, economic interregional transmission projects, called targeted market efficiency projects. MISO and PJM debuted the project type three years ago and have since approved two portfolios of smaller projects.

American Electric Power’s Jim Jacoby said regulators should support the creation of the project type. MISO and SPP considered developing smaller projects two years ago but called off the effort. (See MISO, SPP Mulling Small Interregional Project Type.)

Hall also urged regulators to investigate the eradication of rate pancaking and the possibility of a joint dispatch model between the two RTOs. He said the monitors’ earlier conclusion that joint dispatch wouldn’t benefit the grid operators doesn’t consider reliability advantages and the possibility of capacity-sharing.

Members: Tx, Please

The IMM’s study on interface pricing concluded that the RTOs need only include congestion from their monitored constraints when calculating interface prices. Currently, both MISO and SPP estimate the flow’s impact and congestion costs on all market-to-market (M2M) constraints, even those they aren’t monitoring.

“Both of us are pretty much estimating the full impact of scheduling the transaction,” Patton said. “In the report, we call this a redundant payment, and it is the primary problem identified in the report that needs to be solved.”

Patton said interface payments can be large because the RTOs’ congestion-calculating redundancies exaggerate the cost of moving power over constraints.

He also said nothing in the RTOs’ joint operating agreement provides for refunds when interface prices are overinflated by twice-counted congestion on M2M constraints.

“So ultimately, those payments are just going to show up as uplift that SPP customers pay on MISO constraints, and vice versa,” Patton said.

MISO SPP monitor recommendations — Texas PUC Chair DeAnn Walker questions SPP staff during an RSC meeting. | © *RTO Insider*

Texas Public Utility Commission Chair DeAnn Walker asked why the RTOs aren’t already calculating congestion on just their monitored M2M constraints.

“The RTOs aren’t doing this yet because it hasn’t risen to the top of the heap,” Patton said. He said the switch would entail software changes for both grid operators. That might be especially difficult for MISO, as its IT crews are already taxed with rolling out a new market platform.

The OMS and RSC have discussed presenting by year-end a list of recommendations on how the RTOs can better coordinate across the seam. (See MISO, SPP Regulators Mull Seams Recommendations.)

Walker said that as the regulators compile their list of recommended improvements, they might reach out to the monitors for advice.

“I don’t think they’re totally off the hook,” she said. “In forming our recommendations, we may ask for some input.”

“As market monitors, we see evidence of things not working well. I think state involvement is very important,” Patton said.

Hall said regulators should keep the SLC alive after it issues recommendations to oversee the RTOs’ handling of them and to continue monitoring areas of improvement in seams coordination.

The SLC will meet again Sept. 14. RTO staffs are expected to appear and respond to the monitors’ and members’ ideas for improvement.

September 1, 2020

Panelists Plug Storage, Tx Projects at MRO Conference

Strategically placed transmission or storage devices could serve as a reliability tonic to the middle of the country, according to panelists last week during the Midwest Reliability Organization’s annual reliability conference.

Missouri Public Service Commissioner Ryan Silvey said states like his will need more transmission to reliably transition to cleaner resources. Missouri historically preferred to build coal-fired baseload generation close to load, he said, but that paradigm is quickly changing. Coal generation has dropped to a 73% share of the state’s net generation, down from a peak of 81% a few years ago.

“We’re being shaped by renewable energy mandates, pressure from customers … and aging baseload generators,” Silvey said during the virtual conference Wednesday.

He said the state’s utilities are positioned to blow past the 15% renewable portfolio standard set to take effect in January.

“This is just happening from market pressures,” he said.

Missouri also has naturally low solar and wind generation potential, Silvey said.

“We will likely need to rely on generation sources outside of Missouri,” he said, adding that the state will likely need more transmission investment to tap into other states’ resources.

“Building those needed economic transmission projects has proven to be challenging,” Silvey said. He said Missouri’s position on the MISO–SPP seam adds extra obstacles to transmission construction because of the RTOs’ competing interests.

MRO transmission storage — Missouri PSC Commissioner Ryan Silvey | *Ryan Silvey*

A lack of MISO-SPP interregional transmission projects resulted in unintended consequences during MISO South’s January 2018 maximum generation event. Unusually cold weather had the RTO scrambling to send power to the region and left SPP’s Neosho-Riverton flowgate on the Kansas-Missouri border at its limit, ultimately resulting in uncontrolled loop flows in the area.

“Utilities actually had to disconnect to protect themselves from impacts,” Silvey said. “What’s going to happen when that flowgate gets another 300 MW of wind?”

Silvey stressed that for reliability’s sake, MISO must find a way to increase transmission capacity between its Midwest and South regions beyond its existing subregional transfer limits of 3,000 MW southbound and 2,500 MW northbound.

“MISO can’t really optimize and utilize all of its generation,” Silvey said. “Missouri is stuck in the middle. … We’re basically caught in the crossfire.”

MISO and SPP this year conducted a fourth coordinated system plan, a joint study that could have resulted in the RTOs’ first interregional transmission project. However, early results indicate that the RTOs failed to identify a beneficial cross-border project. (See MISO, SPP Staff Recommend 2020 Joint Study.)

Silvey called the 10 flowgates the RTOs studied this year — including Neosho-Riverton — a “canary in the coal mine.”

“Congestion is no longer limited to the hottest days of summer,” and renewables will accelerate that change, he said.

Silvey urged members, states and RTOs to “remove the red tape” and collaborate more on interregional projects.

The Case for Storage

NextEra Energy Resources’ Jeff Plew said that until 2017, batteries were mostly pilot and niche projects. But now, he said, they’re rapidly becoming the grid’s “Swiss Army knives.”

“The gist of it is they can do a lot of things,” he said. “Now, they can’t do things at the same time. You can’t use the scissors and the nail file at the same time, but you can switch rapidly between [functions].”

Plew cited batteries’ near instantaneous response time, their ability to provide real or reactive power, their chameleon-like ability to act as either generation or load, their zero start-up costs, the relative ease of siting and their modular nature that makes them easy to scale up.

He also said batteries tend to perform better than conventional generation during extreme cold weather conditions, with inverters rated for temperatures as low as -40 degrees Celsius.

“Continued cost declines have made batteries a compelling alternative to traditional fossil-fueled peaker options in meeting flexible capacity needs,” Plew said.

Carbon-free mandates in several U.S. cities and decarbonization goals mean that storage must become a vital piece of markets in the next 20 to 30 years, he said. “Storage has got to be a significant piece of the puzzle here.”

American Transmission Co. Senior Transmission Planning Engineer Randy Johanning said his company’s $8 million Waupaca area energy storage project is poised to fend off reliability issues in central Wisconsin.

The 2.5-MW/5-MWh battery project — which is MISO’s first storage-as-transmission project — has been on hold because the RTO didn’t have FERC Greenlights MISO Storage-as-Tx Proposal.)

The project is expected to be in service by the end of 2021. MISO and FERC predict storage-as-transmission solutions will most likely solve transmission reliability needs.

“We did consider traditional wires solutions here,” Johanning said, adding that the storage solution avoids the need for a more “invasive” rerouting of lines and additional rights of way.

He also said the project presents less financial risk than transmission lines that must be financed over 40 years and whose usefulness is dependent on nearby generation. He said battery storage’s current 20- to 25-year lifespan becomes less of a drawback when considering that ratepayers won’t have the costs reflected in their bills for decades.

Johanning advised that utilities thinking of using storage should focus on which specific issue they are trying to solve, taking pains to size and site their storage carefully.

September 1, 2020

CPUC Fires Executive Director for Improper Hiring

An ugly feud between the members of the California Public Utilities Commission and its executive director, Alice Stebbins, played out in public Monday during an online hearing in which the commissioners unanimously voted to fire her.

“A vote was taken to dismiss the executive director … effective Sept. 4,” CPUC President Marybel Batjer said after the commissioners deliberated in closed session for more than three hours. She did not elaborate and quickly ended the video call.

CPUC Alice Stebbins — CPUC Executive Director Alice Stebbins | *CPUC*

Both sides hurled accusations Monday morning during arguments Stebbins had requested remain public, an unusual move in a personnel matter.

Batjer outlined the results of a state investigation that found Stebbins hired poorly qualified former colleagues for key positions, including a deputy executive director. The CPUC president said Stebbins’ behavior had been “abhorrent” after the accusations came out, as she immediately went to the media and leveled her own accusations of wrongdoing at the commission.

Stebbins argued she was being targeted as a whistleblower because she reported the CPUC had failed to collect $200 million in fees from regulated utilities.

“I and my staff blew the whistle on that, and that’s why I’m being fired,” Stebbins said.

Her lawyer told the commissioners they had violated the state’s open meeting laws by texting about Stebbins’ case and deciding her fate well in advance of Monday’s hearing.

‘Appalling and Disgraceful’

The case began in July when the State Personnel Board (SPB) issued a report to the CPUC concluding Stebbins had improperly hired former colleagues who lacked job qualifications. The report was made public Aug. 6.

In particular, the SPB said Stebbins had “preselected” Bernard Azevedo, her longtime coworker at the state Air Resources Control Board and Water Resources Control Board, as the deputy executive director of the CPUC’s Administrative Services Division, which manages facilities, budgets and contracts.

“‘Preselected’ means you had already made up your mind to hire this person before the recruitment process occurred,” Batjer said. State law requires civil servants to be hired based on merit, she noted.

Azevedo was less qualified than other applicants, the report said. He had no college degree, and his experience was limited to accounting. The job description called for someone with significant experience in administration and budgeting who could represent the CPUC before the State Legislature.

Other candidates had post-graduate degrees and had managed fiscal affairs at executive levels, it said. CPUC employees who rated the candidates said they felt pressured to hire Azevedo because Stebbins made it clear whom she preferred, it said.

Four months after Azevedo was hired, Stebbins added new duties to his role and increased his six-figure salary by 49%. She then took away some of the duties, “thereby removing the justification for the higher salary,” Batjer said, citing the report. Asked about the situation, Stebbins falsely claimed Azevedo was still performing the duties, Batjer said.

“It is appalling and disgraceful to engineer the hiring of a marginally qualified former colleague over more qualified candidates, to spike the person’s pay and then make false statements to justify the compensation,” Batjer said.

Other CPUC appointments and transactions under Stebbins were of “highly questionable legitimacy,” the SPB found.

After the board’s report was sent to the CPUC, the commission undertook its own investigation. Stebbins was removed from her usual personnel duties but continued to make hiring decisions against clear orders, Batjer said.

She criticized Stebbins for failing to show concern for her employees or to take responsibility.

“Instead, you repeatedly suggested that the commissioners should use our political influence to, in your words, ‘make the SPB report go away,’” Batjer said. “Your suggestion was abhorrent.”

Stebbins’ claim that the CPUC was owed $200 million is false, Batjer said. The commission had $50 million in uncollected fees at the end of 2019, including a $20 million fine of a bankrupt, defunct telecommunications company, she said. It had repeatedly tried to collect that fine, including by going to court, she said.

‘A Chilling Message’

Stebbins was given 45 minutes to make her argument. Her attorney Karl Olson began by telling the commissioners that the “firing of Ms. Stebbins would be a clear case of retaliation against a whistleblower.”

On May 15, Azevedo filed a detailed report about the $200 million in uncollected revenue, Olson said. It showed the CPUC collected only $21 million in fiscal year 2018-19 and, as of June 30, 2019, was owed $200 million, he said.

“This contradicts what the commission … said today about how the $200 million was an exaggeration,” he said.

Olson also said the commissioners had repeatedly spoken in text messages about firing Stebbins, reaching a consensus long before Monday’s hearing.

CPUC headquarters in San Francisco | © *RTO Insider*

“You all agreed in serial private meetings to fire Ms. Stebbins,” the lawyer said. One commissioner texted, “I can’t imagine her remaining,” according to Olson. Another texted, “It’s not tenable for her to stay,” he said.

“Wrong. What’s not tenable is to violate the state constitution,” which requires open meetings, he said. “You made the decision in secret texting sessions.

“You probably know the law, and you consciously and brazenly defied it,” Olson added.

Two commissioners spoke with Stebbins by telephone the night of Aug. 3 and told her they had decided to fire her, he said. He contended Stebbins should have been given a second chance.

“There was and is no reason to fire Ms. Stebbins, because the SPB report was contrived and unfounded and did not detract from the fact that she had done an excellent job,” he said. “She hired 800 people and was moving the PUC in the right direction. The SPB raised unfounded questions about five people who were doing an excellent job including Mr. Azevedo.

“If you go ahead with this firing, this kangaroo court, in which President Batjer seems to be serving as prosecutor, judge and jury, you will send a chilling message to whistleblowers in state service: People who report illegal and improper activity will be fired,” Olson said.

September 1, 2020August 13, 2024

NRC OKs NuScale’s Small Modular Reactor Design

The Nuclear Regulatory Commission last week approved the final safety evaluation report for NuScale Power’s small modular reactor (SMR) design, which proponents hope will revive the nation’s nuclear power industry. Others are skeptical that this latest promise of a nuclear “renaissance” will come to pass given cheap natural gas and declining renewable and storage costs.

The commission greenlit the SMR design on Friday after completing its Phase 6 review of NuScale’s design certification application (DCA), making the Portland, Ore.-based company the first and only SMR manufacturer to successfully complete a DCA review.

“This is a significant milestone not only for NuScale, but also for the entire U.S. nuclear sector and the other advanced nuclear technologies that will follow,” company CEO John Hopkins said in a press release.

Two of the biggest threats to nuclear plants are the loss of water to keep their fuel from overheating and loss of power needed to operate pumps, valves and monitoring equipment.

NuScale’s pressurized light water reactor simplifies or eliminates systems used in earlier-generation plants and employs passive safety features that the company says will ensure the plant can shut down safely.

The passive design was instrumental in the approval process. “The NRC concludes the design’s passive feature will ensure the nuclear power plant would shut down safely and remain safe under emergency conditions, if necessary,” the commission said.

NuScale’s SMR, called the NuScale Power Module, encompasses the reactor, steam generators and pressurizer, and the use of natural circulation eliminates the need for large primary piping and reactor coolant pumps, according to a company spokesperson. Each module has a generating capacity of 60 MW, and the design is scalable, allowing for combinations of up to 12 modules for a total of 720 MW.

By comparison, the smallest nuclear reactor in the U.S. is New York’s R.E. Ginna Nuclear Power Plant, which has one reactor with a capacity of 582 MW. Arizona’s Palo Verde nuclear power plant, the largest in the U.S. with three reactors, has a total capacity of 3,937 MW.

High construction costs and three reactor accidents still scar the industry: Three Mile Island’s partial meltdown in March 1979; the April 1986 accident at Chernobyl; and the 2011 accident at the Fukushima Daiichi plant, in which three nuclear cores largely melted after the plant was swamped by a 45-foot tsunami that disabled the power supply and cooling.

NuScale says its plant can safely shut down and cool itself indefinitely without pumps, AC or DC power, or additional water.

As in traditional reactors, control rods are inserted to stop the fission reaction. But NuScale says its design allows the decay heat removal system and the steam generators to reduce the core thermal power to about 1.1 MWt (megawatt thermal) in one day. (The heat from 3 MWt is enough to generate 1 MW of electricity.)

After three days, core thermal power drops to about 0.8 MWt and reactor pool water begins to boil. For the next 30 days, the water level decreases as core thermal power falls to 0.4 MWt. After 30 days, the reactor pool is emptied, but the reactor remains cool indefinitely by transferring heat to the surrounding air via natural convection.

The company said it is actively engaged with its manufacturing partners to ensure its SMR is ready for delivery to its first client in 2027. It says it has signed agreements with entities in the U.S., Canada, Romania, the Czech Republic and Jordan.

In addition, a 12-module, 720-MW NuScale plant is planned by the public power consortium Utah Associated Municipal Power Systems (UAMPS). The first module is expected to be operational by mid-2029, with the remaining 11 modules to come online for full plant operation by 2030, a company spokesperson told RTO Insider.

To date, NuScale has invested close to $1 billion in the technology development and licensing, which includes more than $300 million in cost-shared funding from the U.S. Department of Energy. NuScale’s majority investor is Fluor, a global engineering, procurement and construction corporation.

Marc Nichol, senior director of new reactors at the Nuclear Energy Institute, said SMRs could aid in bringing the U.S. closer to meeting its clean energy target and making electricity more accessible. “This milestone demonstrates the nuclear industry can meet the demands for reliable, safe and affordable carbon-free energy here in the U.S.,” he said. Adding that clean energy is in demand globally, Nichol said there is a growing interest in SMR technology in Canada, Europe and the Middle East.

Neither NEI nor NuScale directly answered questions about the economic viability of SMRs and how they will compare to renewables and natural gas generation.

A paper published in February in the journal Renewable and Sustainable Energy Reviews found that a manufacturer would need to sell four 180-MW SMRs at $1.5 billion each to recover the cost of a $1 billion factory. It cited a base construction cost of $3,465.72/kW for the 12-module NuScale SMR.

NuScale announced in 2018 that it had reduced the cost of a 12-module plant to $4,200/kWh. The company has set a goal of a $65/MWh levelized cost of electricity.

Lazard’s latest levelized cost of energy puts onshore wind at $28 to $54/MWh, utility scale solar at $32 to $42/MWh, gas combined cycle plants at $44 to $68/MWh and conventional nuclear at $118 to $192/MWh.

‘Big Grain of Salt’

Critics of nuclear power have expressed wariness over NRC’s announcement last December that it is considering shrinking the emergency planning and evacuation zones around the smaller, new reactors from the current 10-mile radius.

“When you’re talking about a reactor that’s never been built or operated, you have to take with a big grain of salt the claims that it’s actually safer or more secure,” Edwin Lyman at Union of Concerned Scientists told NPR.

Lyman said weaker reactor containment shells and off-site operators at certain facilities are on the industry’s wish list. UCS believes companies should follow current construct rules, even when building smaller reactors. “You have to work out the kinks of these new plants,” he told NPR. “And then over time, you might be able to adjust your requirements accordingly. But you don’t do that at the get-go.”

DOE’s National Nuclear Security Administration mirrored a few of Lyman’s concerns in comments sent to NRC, saying the current rules provide “the last layer of a defense-in-depth for low-probability, high-consequence accidents.”

A spokesperson for the commission declined to comment on the safety worries. “The NRC ensures nuclear power plants (and other civilian uses of radioactive material) are safe; questions about the relative benefits of reactors designs are best directed to the Department of Energy’s Office of Nuclear Energy, or to the Nuclear Energy Institute.” Neither responded to RTO Insider’s questions.

Expansion Troubles

Nuclear supporters hope SMRs are the good news the beleaguered industry needs.

As recently as 2010, nuclear proponents talked excitedly of a “renaissance” in the U.S. NRC, which hadn’t issued a construction permit for a nuclear reactor since 1978, streamlined its licensing process and hired hundreds of additional staff to process applications for 30 new generators received after 2007. Some environmentalists had begun to talk about nuclear power as part of the solution to climate change.

By the end of 2010, however, most of the applicants were having second thoughts because of falling natural gas prices, reduced demand projections as a result of the Great Recession and Congress’ rejection of legislation to impose costs on carbon emissions.

While about a fifth of domestic electricity is produced by nuclear power, according to the Energy Information Administration, experts predict a decline in usage in the next few years. Just last week, Exelon announced it would shut down its Byron and Dresden nuclear plants in November 2021 if it fails to win subsidies. (See related story, Exelon to Close Ill. Nukes as Gov. Touts Clean Energy Plan.)

Not helping the industry are failed projects, delays and costly overruns common within new reactor construction.

Georgia Power’s plans to expand Plant Vogtle ran into soaring construction costs, as had been warned by the project’s critics.

Vogtle’s AP1000 design also incorporates passive safety features not present at the Fukushima plants or the current U.S. fleet of reactors. A July 2011 Near-Term Task Force report on insights from the Fukushima accident said the AP1000’s passive designs should keep the reactor core and spent-fuel pools from overheating for 72 hours without power or operator action.

Vogtle, currently the only commercial nuclear power plant expansion underway in the U.S., is billions of dollars over budget. The two reactors under construction were slated to begin commercial output in the spring of 2016 and 2017, but state officials said it is “highly unlikely” the reactors will be online soon.

A Georgia Power spokesperson said in June the company hopes to bring Vogtle Unit 3 online in November 2021 and Unit 4 in November 2022.

The Vogtle project lined up billions of dollars in federal loan guarantees and hundreds of millions of dollars in federal tax credits under both the Obama and Trump administrations.

In neighboring South Carolina, the V.C. Summer expansion by state-owned Santee Cooper experienced years of overruns and delays before the $9 billion project was canceled in July 2017 — dubbed by The Post and Courier as “one of the greatest business failures in state history.”

September 1, 2020

Soapbox: The Potential New Normal for Load Profiles

By Patrick McGarry

A few years ago, during my EMBA program at the University of Florida, I visited my Managerial Statistics professor one weekend. As I approached his office, I noticed a large sign taped to his door that declared:

“In God we trust. All others must bring data.”

The message basically summed up the main point of our program, which is that critical thinking requires the objective analysis and evaluation of an issue devoid of gut feeling and cognitive biases. Utilizing reliable and accurate data offers the best option to understanding today in order to predict tomorrow.

As I listen to all the futurists make COVID-19 pandemic impact predictions, I remind myself of that sign on the professor’s door.

Behavior during market disruptions is historically a poor indicator of longer-term expectations. During the Great Recession, notable economists predicted the end of the age of overconsumption. The SUV would become a relic of the past, and $4/gallon gasoline would be a death knell. If you didn’t understand that prediction, then you certainly would once gasoline reached $8/gallon.

Of course, neither happened, and today, SUVs comprise nearly half of all the automobiles in the U.S., while the fracking revolution has flooded the global market in cheap and abundant oil.

People struggle to predict the future because disruptive events arise spontaneously, with little notice, and tend to be highly influential.

When Rosa Parks decided not to give up her seat on a Montgomery, Ala., school bus, how many people predicted the beginning of the civil rights movement?

None.

The future is always more unforeseeable than it seems.

However, the recent COVID-19 shelter-in-place orders have provided utility data scientists with some reliable and accurate data to gain insight into changing residential and commercial load demand profiles. Predicting them as accurately as possible will be critical for planning the most economically efficient electricity grid operations and for designing rates.

What Do the Data Say?

The Pacific Northwest National Laboratory (PNNL) recently released a study assessing the first full month (April 2020) of COVID-19 impacts to residential and nonresidential load. “Changes in Electricity Load Profiles Under COVID-19: Implications of ‘The New Normal’ for Electricity Demand” examined two years of observed electricity consumption data from more than 3.8 million residential and nonresidential customers of Commonwealth Edison in Illinois.

In comparing load demand pre-COVID-19 to data following the national shelter-in-pace environment, the researchers discovered that the onset of the pandemic shifted weekday residential load profiles to closely resemble weekend profiles from previous years. (See Figures 1 and 2.)

Mean weekday and weekend loads in April 2020 for residential and nonresidential customers. Diurnal maximum values indicated by circles. | *Pacific Northwest National Laboratory*

Correlation between the residential load profile for a given day in 2020 and the mean weekday/weekend load profile from the same month in 2019 | *Pacific Northwest National Laboratory*

PNNL observed that the April 2020 residential load profile demonstrated a correlation consistently over 0.95 with the 2019 Mean Weekend Profile.

The U.S. Energy Information Administration reported that residential electricity sales were 6% higher in April 2020 than in any April from the previous five years, while commercial and industrial sales decreased 9% and 10%, respectively.

COVID-19 demand — U.S. monthly electricity sales by end-use sector, January 2015 to April 2020 (millions MWh) | *U.S. Energy Information Administration*

While much more research will be needed this fall to determine a “new normal,” we do know that weekday changes in residential loads have the potential to significantly change the total load profile.

The load data utilized in the PNNL study came from two extremely different environments: the pre-COVID-19 setting with rich data from many years, and the national emergency shelter-in-place order setting during April 2020.

PNNL’s ComEd study data set covered customers that had deployed advanced metering infrastructure devices. Anonymous end-use electricity data are classified by class (four residential and 11 non-residential classes) and a zip code.

The main components of the PNNL study were:

demonstrating how load profiles shifted as the U.S. transitioned to widespread shelter-in-place orders during March-April 2020 based on 30-minute aggregate loads for residential and nonresidential sectors; and
a sensitivity analysis to explore how historical weekday total load profiles may have shifted if shelter-in-place conditions or widespread teleworking had occurred in prior months and years.

According to PNNL research scientist Casey Burleyson, “This paper was only possible because ComEd chose to make this unique data set available to the community. There is no shortage of eager scientists and engineers asking interesting questions. When you combine researchers with utilities willing to embrace the open-data movement, you enable real-time value-adding studies like we’ve done with this COVID-19 work.”

What is the New Normal for Load Profiles?

We could talk forever about potential future impacts of COVID-19, but the topic of teleworking is of extreme interest to the energy industry. Up until the pandemic struck, most long-term planning discussions relative to the grid, generation and rate design did not really consider any evolution in how the U.S. workforce would be deployed. Now, however, those obvious changes will dramatically affect both residential and commercial load profiles.

While “gut feel” would indicate big changes ahead, we don’t yet have all the data — or a vaccine — to help draw precise conclusions on the full impact of the pandemic. However, we do know they’ll be felt differently in different parts of the U.S., which never has (nor ever will) have a one-size-fits-all load profile.

The unprecedented magnitude and length of pandemic-related disruptions raise the probability of lasting telework changes in our workforce. As a result, utilities need to be studying the current load patterns extremely closely in order to perform scenario planning.

With respect to shelter-in-place residential weekday load profiles, the PNNL study found:

a more gradual morning ramp;
higher mid-day loads; and
smaller, less steep ramping during the evening peak.

Interestingly, PNNL’s conclusions are consistent with the initial load profile observations from NYISO.

As mentioned earlier, PNNL used data historical load profiles versus a COVID-19 profile in analyzing different scenarios around increased teleworking along with reduced commercial loads. It determined that in the long term, increased teleworking could potentially lead to 5 to 7% higher spring and summertime peak hourly loads occurring up to 2.5 hours earlier.

It also found that the flattened daily load profile could potentially lower ramping needs, reduce oversupply risks and change market prices.

Rate Design and Budget Impacts

If some as-yet-unknown percentage of the workplace switches to teleworking for the longer term, one could logically deduce that residential power bills will go higher and that commercial/industrial bills will go lower. In an economy facing headwinds not seen since the Great Depression, this development could present significant rate design and budgetary challenges for utilities across the country.

Prior to the COVID-19 pandemic, the utility industry was beginning a discussion about reforming electric rate designs based in part on the fact that fixed costs are increasing. Grid modernization and investments to meet sustainability goals come at a significant capital cost, and utilities are struggling to cover these fixed costs, especially in the area of generation.

In a world in which some residential customers have the capacity to invest in distributed energy resources at home to potentially protect themselves from future, higher bills, others do not have that ability. Key questions in this area include:

Will the consumer be able to shoulder higher power bills, and, if not, how badly will the economy be impacted?
How will this impact “the electrification of everything”?
Could COVID-19 workforce developments be the impetus for utilities to change from a single volumetric rate to a fix charged component with a set monthly fee?

While we can’t yet fully answer these questions, we can assume that budgetary pressures will continue to be substantial while portfolio optimization dollars will become much more valuable.

Reliability and affordability will continue to be the two major challenges facing utilities in a post-COVID world. As always, operational effectiveness and efficiency will continue to be more important than ever.

Conclusion

Conjecture often makes a podcast interesting but does very little for the utility industry to predict the future. Fortunately, data scientists and research engineers utilize powerful, increasingly precise methodologies in forecasting realistic future scenarios.

There are things we know.

There are things we do not know.

There are things we do not know that we do not know.

COVID-19 is a “known unknown” and will clearly impact the future composition of residential and commercial load profiles, though the degree of the virus’s influence is still coming into focus. Considering all the disruption now at hand in the energy industry, clearly understanding likely future loads will be a necessary and critical first step in scenario planning.

We have some of the data we need to begin this process. But during the next few months, one of the most important new normal planning tasks for individual utilities will be to collect, store and examine in fine detail their own meter data.

Patrick McGarry is senior director of Power Costs Inc.

September 1, 2020

CPUC OKs 1.2 GW of Storage by 2021, 38,000 EV Chargers

The California Public Utilities Committee on Thursday greenlit a major expansion of the largest utility-run electric vehicle charging program in the nation and approved contracts signed by investor-owned utilities to procure 1.2 GW of battery storage.

The contracts were signed in response to a CPUC procurement order in 2019 intended to head off projected shortfalls starting in the summer of 2021, but the shortage conditions arrived a year earlier than expected. A weeklong August heat wave across the West strained grid conditions and led to the rolling blackouts of Aug. 14-15.

CAISO Blames Blackouts on Inadequate Resources, CPUC.)

The CPUC also renewed the state’s Electric Program Investment Charge (EPIC) program for another 10 years, providing nearly $1.5 billion for research and development during that time. Grants from the ratepayer-funded program are distributed by the California Energy Commission to finance cutting-edge clean energy, storage and EV projects, among others.

“Developing new technologies and solutions that are laser-focused on improving reliability, safety and affordability attracts investment to California and keeps our clean economy growing,” Commissioner Martha Guzman Aceves said in a statement. “Several EPIC-funded microgrids even supported the grid during the recent grid crisis, demonstrating real-time value to ratepayers.”

1.2 GW of Battery Storage

In 2018, the CPUC and CAISO identified potential capacity shortfalls starting in the summer of 2021 and extending for at least several years, caused by the state’s shift to solar and wind power and away from fossil fuel plants.

The projected shortfalls, like the rolling blackouts of mid-August, could be triggered by peak summer demand shifting to later in the day, as the sun sets and solar power wanes. Continuing high demand during the “net-peak” hour can strain available supply.

To ensure resource adequacy, the CPUC in November 2019 ordered the utilities under its authority to collectively procure 3,300 MW on a pro rata basis. (CAISO had asked for 4,700 MW and blamed the CPUC for coming up short, following the rotating outages.) The procurement contracts the CPUC approved Thursday were the first tranche of resources under the reliability effort.

The commission ordered Pacific Gas and Electric, the state’s largest utility, to procure 717 MW of new resources by 2023. At least half that amount must come online by Aug. 1, 2021, it said. (See California PUC Votes to Keep Old Gas Plants Operating.)

CPUC storage chargers — PG&E contracted with NextEra Energy Resources for storage at its Blythe Solar Energy Center. | *NextEra*

PG&E submitted seven contracts to the CPUC for 423 MW of lithium-ion battery storage, all of which the regulatory agency approve d Thursday. PG&E said the storage projects all will come online by next July.

Under the agreements, Dynegy Marketing and Trading will operate a 100-MW battery storage facility at its Moss Landing natural gas plant on Monterey Bay; Coso Operating Co. will provide 60 MW of battery storage at its 145-MW geothermal project at the U.S. Naval Weapons Center in Inyo County; and NextEra Energy Resources Development will operate a 63-MW storage facility at its 225-MW Blythe Solar Energy Center in Riverside County.

PG&E contracted with Diablo Energy Storage for three battery projects totaling 150 MW in the San Francisco Bay Area and with LS Power Group’s Gateway Energy Storage for a 50-MW standalone project in San Diego.

The CPUC approved seven contracts signed by Southern California Edison for 770 MW of battery storage. In its 2019 order, the CPUC required SCE to procure nearly 1.2 GW of new resources by 2023, with at least half operational by August 2021.

SCE contracted with NextEra for approximately 230 MW of storage at the Blythe facility and for 230 MW at its McCoy Solar Energy Center in Riverside County; with Gateway for 100 MW of storage in San Diego County; with Southern Power, a subsidiary of Southern Co., for 150 MW of storage at its solar arrays in Fresno and Kern counties; and with Terra-Gen for 50 MW at its Sanborn facility in Kern County.

The CPUC approved all seven SCE contracts, some of which are tolling agreements or RA-only contracts.

“California recently experienced reliability challenges not seen in decades, and we are working to identify the root causes,” Commissioner Genevieve Shiroma said. “Our decisions today continue to build the foundation of our resource adequacy program by securing additional contingency resources for use when needed.”

Largest EV Charging Program

Also on Thursday, the CPUC authorized $437 million to fund the installation of 38,000 charging ports for EVs via SCE’s Charge Ready 2 infrastructure program, the largest single-utility EV charging program in the U.S., according to the commission.

SCE originally asked for $760 million, but the CPUC said its decision reduces ratepayer costs by 40% while reducing the number of charging ports by just 20%, partly by lowering the estimated cost per port to $15,000 from SCE’s requested $19,000.

The Charge Ready program started in 2016 with a pilot program of 1,500 charging ports and began expanding in 2018. The program prioritizes low-income communities and apartment buildings “because they face barriers to transportation electrification,” the CPUC said in a statement.

The program includes infrastructure upgrades to support EV chargers, including higher-voltage electric panels, conduit and wiring. A construction rebate offsets installation and charger costs for new multiunit dwellings that exceed state or local building codes.

Program participants must sign up for demand response programs and accept time-of-use pricing to align charging incentives with grid conditions, the CPUC said.

“This decision furthers California’s ambitious goals to increase [zero-emission vehicles to 5 million by 2030] and end harmful tailpipe pollution by filling gaps in the state’s EV infrastructure,” Commissioner Cliff Rechtschaffen said in a statement.

September 1, 2020January 18, 2024

SPP Stakeholders Agree on WEIS Tariff Changes

Stakeholders in SPP’s Western Energy Imbalance Service (WEIS) market last week approved three revision requests (WRRs) in response to FERC’s recent rejection of the RTO’s proposed Tariff.

The Western Markets Working Group and Western Markets Executive Committee held two joint web meetings to expedite protocol changes necessary to help SPP meet an early September schedule for refiling its WEIS Tariff.

FERC in July rejected SPP’s first attempt, saying the grid operator failed to respect nonparticipants’ transmission rights and could improperly burden reliability coordinators. The commission also cited shortcomings on supply adequacy, market power protections and line-loss calculations (ER20-1059 , ER20-1060). (See FERC Rejects SPP’s WEIS Tariff.)

While the groups easily passed three WRRs, it was unable to hold a vote on nonparticipant transmission. After nearly four hours of discussion and one minor editing change Friday afternoon, stakeholders agreed to postpone action until a yet-to-be-scheduled third joint meeting can be held this week.

In its order, FERC said any future WEIS market proposal “should include the mechanisms or agreements that will ensure that the SPP WEIS market respects the transmission capacity of nonparticipating entities with appropriate constraints in the [security-constrained economic dispatch].”

The commission said if SPP is unable to reach an arrangement with nonparticipating entities for their transmission capacity, it “must include constraints in its market model to appropriately respect the transmission rights of nonparticipating entities when calculating the market solution.”

Colorado utilities Xcel Energy-Colorado, Colorado Springs Utilities, Platte River Power Authority and Black Hills Energy, all of which plan to join CAISO’s Western Energy Imbalance Market, protested the first WEIS filing. They contended that an existing and neighboring joint dispatch agreement could be impaired by the WEIS market dispatch and that its market flows may harm the Western Interconnection Unscheduled Flow Mitigation Plan, which mitigates real-time flows on certain transmission paths to reliable levels.

WRR6 provides that SPP will include constraints in SCED to use the combined transmission capability made available by market participants (MPs) and participating balancing authorities on transmission facilities within a participating BA area or on transmission facilities used to transfer energy between participating BAs.

SPP staff also added a new section to the WEIS protocols that lists the responsibilities to communicate transmission capacity by SPP, MPs, BAs and the joint dispatch transmission service provider. The addition came following comments by Xcel and Black Hills.

“After some internal deliberation, we thought we could make the roles and responsibilities of communicating information clearer,” said David Kelley, SPP’s director of seams and market design.

The WEIS stakeholder groups approved three other revision requests addressing the commission’s order:

WRR7: Incorporates a pricing mechanism for MPs in BAs that experience supply-adequacy shortfalls. The mechanism responds to FERC guidance that its next Tariff proposal should ensure MPs are incentivized to maintain supply adequacy. Black Hills argued that the change doesn’t address the FERC order, saying it was concerned there still remains opportunities for deficient MPs to cause a BA to be deficient.
WRR8: Adds a marginal loss component to the LMP calculation, meeting FERC’s request that SPP include marginal losses in dispatch and LMPs to minimize imbalance costs, provide prices that accurately reflect marginal costs and preserve resources’ incentives to follow dispatch.
WRR9: Clarifies that demand response resources will be compensated at the LMP, as are other MPs offering resources in the market.

SPP hopes to launch the WEIS in February. The market will include eight members and cover the Western Area Power Administration’s Colorado Missouri and Upper Great Plains West areas.

September 1, 2020

ERCOT Technical Advisory Committee Briefs: Aug. 26, 2020

ERCOT stakeholders last week debated an artifact from the old zonal market, eventually tabling action without a revision request to act on.

Staff brought forward to the Technical Advisory Committee discussion of the “2% rule,” which directs that generating units with shift factors of less than 2% will not be dispatched by the real-time market to respond to transmission overloads. A desk procedure in 2011, shortly after the nodal market went live, clarified the use of the 2% shift factor cutoff in real time.

Under the rule, if a transmission constraint exists for which there are no generator shift factors of at least 2%, operators must verify a mitigation plan or temporary outage action plan exists for the contingency and they are to review the plans with the affected transmission owner. If no plans exist, then the operators are to develop a mitigation plan with ERCOT’s operations support engineer. If no plans have been developed within 30 minutes, the operations desk issues a transmission watch, a step down from an emergency.

ERCOT has conducted several recent analyses on the effects of activating low shift-factor constraints in the economic dispatch engine. Staff found that the effect of activating the constraints is dependent on the system’s topology near the constraint and observed no oscillation in the resource’s output level.

The Congestion Management Working Group has been unable to reach a consensus on whether to eliminate the rule, despite working on the issue since last year.

“It feels like we’ve been talking about it forever,” said CPS Energy’s David Kee, who chairs the Wholesale Market Subcommittee, to which the working group reports.

ERCOT’s Independent Market Monitor, however, believes the 2% rule should be eliminated, with all congestion priced in real time, regardless of generation’s effect.

“Prices matter. The whole market is predicated on that,” said Monitor Director Carrie Bivens in arguing against out-of-market actions. “Whether or not an existing resource can move to resolve the constraint is not relevant to whether it should be priced. We don’t need to define in advance what the response will be. The magic of the market is that it can and does respond to those market signals.”

Bivens said incorporating a price signal for what would be an out-of-market action on hidden congestion would incentivize the market to resolve the issue.

She noted that ERCOT only activates contingency constraints if three thresholds are met: the system is loaded at 98% of the emergency limit; a resource shift factor of 2% or more exists; and a similar constraint is not already activated.

Other markets have lower constraint thresholds, are lowering them or don’t have them at all, Bivens said. MISO’s Independent Market Monitor is urging the RTO to remove its 1.5% threshold; PJM just removed its threshold; and CAISO is discussing a change to its 2% rule, she said.

With an efficient congestion revenue rights (CRR) market, she said, the overall cost to load does not increase. “If the real-time congestion rent goes up, the day-ahead market’s congestion rent will rise and the CRR revenue goes up,” Bivens said.

“This is a pretty significant issue for the market. It’s in the ERCOT procedure manual, but this needs to be documented in a guide procedure,” Morgan Stanley’s Clayton Greer said. “In my view, we’re going to see [the] effective elimination of the 2% rule anyway with all the distributed generation going out on the system. I’d rather just rip the Band-Aid off, let the market see the change and everyone adapt to the change [at the same time].”

Kenan Ögelman, ERCOT’s vice president of commercial operations, said the Monitor “brought up a worthy issue for consideration,” but because the 2% rule doesn’t reside in the protocols or another binding document, options are limited.

“This is something that needs to be resolved to move the issue forward, one way or another,” Ögelman said.

“Maybe it would be cleaner if there was an NPRR [Nodal Protocol revision request],” said Eric Goff, a residential representative in the Consumer segment.

TAC Chair Bob Helton, of ENGIE, said he will discuss the matter offline with Ögelman and TAC Vice Chair Clif Lange, of South Texas Electric Cooperative, and work on a document that stakeholders can vote on.

On that, members were able to reach consensus.

PRS Prioritizes List of Approved RRs

The Protocol Revision Subcommittee (PRS) and ERCOT staff have spent the past few months prioritizing work on approved revision requests to balance resource availability with the flood of changes.

ERCOT’s Troy Anderson said 40 items on the priority list, “an unusual amount,” have yet to be started. That doesn’t take into account RRs from stakeholder groups working on real-time co-optimization, energy storage and distributed generation.

“We’ll be starting on real-time co-optimization, the [Battery Energy Storage Task Force] and [distributed generation] in the very near future,” Anderson said. “We have to be careful not to put those items at risk. This doesn’t mean the remaining items won’t get done. We will seek opportunities for those items when the resources become available or we have the opportunities to work on them.”

Anderson shared with the TAC a graphic that listed more than 70 RRs or other initiatives currently underway or waiting in the wings. ERCOT has a limited number of resources available to work on the backlog.

“We want to ensure we have prioritized the right items to be worked on soonest,” Anderson said.

ERCOT’s 2020 release targets for the more than 70 approved revision requests | *ERCOT*

Committee Passes 3 Change Requests

The TAC approved three revision requests in two roll-call votes.

The first vote paired an NPRR (NPRR984) with an accompanying Other Binding Document request (OBDRR023), both related to emergency response service (ERS) in what Helton dubbed “the Clayton ballot.” Greer, the ballot’s namesake, said during July’s TAC meeting that he would vote against anything related to ERS. True to form, he cast the lone vote against the measures on behalf of Morgan Stanley, but he did side with the majority on behalf of his proxy, EDF Trading’s Kevin Bunch.

NPRR984 changes the number of ERS standard contract terms from three to four per program year to align the terms with typical seasonal conditions and improve ERS’ procurement. OBDRR023 changes ERS’ procurement methodology to match NPRR984’s protocol changes.

In addition, the committee unanimously approved NPRR10 27, which removes gray-boxed language from the protocols related to NPRR702 (Flexible Accounts, Payment of Invoices, and Disposition of Interest on Cash Collateral) following the elimination of prepay accounts.

September 1, 2020

Stakeholders Speak out on FERC CIP Concerns

Responses to FERC’s Notice of Inquiry on potential gaps in NERC’s Critical Infrastructure Protection (CIP) standards reveal widespread reluctance on the part of industry stakeholders toward the commission’s suggestion of enhancing the standards (RM20-12).

FERC issued the NOI in June, citing concerns that the current version of the standards do not adequately address the rapidly evolving landscape of cybersecurity threats. (See FERC Starts Inquiry on CIP Standards.) Specifically, the commission based its questions on a review of the National Institute of Standards and Technology’s (NIST) Cyber Security Framework, with it asking stakeholders whether the standards provide sufficient protection in the fields of cybersecurity risks pertaining to data security; detection of anomalies and events; and mitigation of cybersecurity events.

The commission also asked for comments on the danger of a coordinated cyberattack against geographically distributed targets, and whether FERC should take action to address this threat.

Separate Spheres for NIST, CIP

Responses to the first part of the inquiry were mostly negative, with several commenters objecting to FERC’s comparison of the CIP standards to the NIST framework. For example, the Large Public Power Council and the American Public Power Association pointed out that organizations are supposed to customize the NIST framework to their specific needs. Moreover, the framework is entirely voluntary, making the idea of “compliance” a contradiction.

FERC CIP Concerns — FERC headquarters in D.C. | *FERC*

In a joint comment, Jason Christopher, principal cyber risk adviser for industrial security firm Dragos, and Tim Conway, industrial control systems curriculum director for cybersecurity training organization at the SANS Institute, noted that FERC’s inquiry seems to share themes with a white paper it published at the same time proposing an incentive framework for cybersecurity investments. (See FERC Seeks Comments on Cyber Investment Incentives.)

In particular, they pointed to the paper’s assertion that “the standards development process does not lend itself to addressing rapidly evolving cybersecurity threats” as indicating a crucial misunderstanding of the way the NERC standards and the NIST framework complement each other.

“While this may be an easy soundbite, the truth is more nuanced,” Christopher and Conway said. “The requirements themselves may have issues, but the ability to adapt to new threats is based on applying new and specific technologies or techniques used for compliance — not necessarily in the ability to comply with specific requirements themselves. … The what to achieve, regardless of how a technology may be deployed, is relatively timeless, independent of evolving threats.”

Arguments for Unified Standards

Supporters of the commission’s desire to reform the standards included the U.S. Army Corps of Engineers and the Bureau of Reclamation, which in a joint comment argued that “maintaining a competing set of standards for critical infrastructure” — referring to the CIP standards — is dangerous for grid stability compared to “[leveraging] the comprehensive set of published NIST standards.” The organizations urged FERC to follow the lead of other federal agencies and adopt a regulatory framework that is objective-based, rather than compliance-based.

“The focus should not be on what is wrong with the CIP standards, or how to better align them to NIST, but what is right with the NIST standards and how a convergence on a single set of standards would improve [bulk electric system] resilience and security,” the agencies said.

The New Jersey Board of Public Utilities also stepped forward to back the commission’s comparison of the CIP standards to the NIST framework, citing specific differences between the two structures to bolster the claim that NERC’s standards have serious deficiencies. Examples include the CIP standards’ lack of a mandate for monitoring data in transit for anomalies and continuity of operations, along with the lack of security requirements for low-impact BES cyber systems to match those for high- and medium-impact systems.

Multiple Defenses Against Mass Attacks

The security implications of unaddressed low-impact systems were a significant factor in FERC’s second area of inquiry, concerning coordinated cyberattacks. The commission’s key concern is whether “smaller, geographically distributed generation resources” such as rooftop solar panels and battery storage facilities — classified as low-impact systems — could provide entry points for an attacker, especially given the exclusion of such assets from NERC’s reliability standards.

Responses largely characterized the current standards as sufficient. NERC itself, commenting jointly with the regional entities as the ERO Enterprise, said that it “recognizes the emerging threat of a coordinated cyberattack” and highlighted a number of processes that it said provided an “in-depth approach to risk mitigation.” Among the tools cited was the NERC Alert process, through which the organization provides “concise, actionable information” to the industry, and forums such as the Reliability Issues Steering Committee that identify emerging risks to the BES.

Southern Co. joined NERC’s defense of its standards, asserting that multiple currently effective CIP standards, as well as several more under development, contain adequate controls for “identifying, preventing and mitigating coordinated cyberattacks.” In reference to low-impact cyber systems, Southern acknowledged the potential for harm in leaving them unaddressed but recommended that future CIP requirements aimed at securing such assets take aim at “the external connectivity that connects them together” rather than the systems themselves.

September 1, 2020

FERC Affirms its Jurisdiction over Tri-State G&T

FERC late last week affirmed that it has exclusive jurisdiction over Tri-State Generation and Transmission Association’s rates and member exit charges, one in a flurry of orders Friday related to the Colorado-based cooperative (EL20-16).

The order pre-empts the Colorado Public Utilities Commission’s jurisdiction over Tri-State and would negate an exit-fee methodology proposed by co-op members United Power and La Plata Electric Association (LPEA). FERC in June accepted Tri-State’s proposed contract-termination payment methodology and set hearing and settlement judge procedures, but a Colorado administrative law judge in July Colo. ALJ Proposes $235M Exit Fee for United Power.)

Tri-State G&T — Tri-State’s headquarters in Westminster, Colo. | *Ludvik Electric*

Tri-State became FERC-jurisdictional in March, when the commission recognized its status following last year’s addition of MIECO, a wholesale energy services company that provides natural gas to the co-op, as its first non-utility member. (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 16, 2020.)

In its order last week, the commission said that, after “further consideration,” it was modifying the March order to find that Tri-State’s assessment of an exit charge “constitutes a commission-jurisdictional rate subject to our exclusive jurisdiction.”

FERC concluded that, as a result, the Colorado PUC’s jurisdiction over complaints regarding Tri-State’s exit charges “is pre-empted as of Sept. 3, 2019,” the date the co-op admitted MIECO.

“This is a monumental decision for our members and Tri-State, and allows us all to move forward in our clean energy transition with much more certainty,” Tri-State CEO Duane Highley said in a statement.

Highley said FERC was the “appropriate regulatory commission to consider these important issues.”

“At the FERC,” he said, “each of our members, no matter in which state they are located, can participate fully, have a voice and be treated equally on wholesale contract and rate matters.”

The commission also reaffirmed that Tri-State’s addition of new members was lawful under the Federal Power Act. It rejected United’s and LPEA’s claims that adding MIECO violated the law.

In a separate order, FERC also dismissed the members’ rehearing requests (ER20-1559). It also sustained Tri-State’s filed rate schedules in additional rehearing requests by United and the Sierra Club (ER20-689, et al. and ER20-676, et al.).

FERC to Investigate Tri-State Policies

FERC also found that Tri-State’s use of fixed-cost equalization in its policy and rate is consistent with federal law and agreed with the cooperative’s use of net metering for energy storage projects, rejecting United’s and Sierra’s claims and setting the matters for hearing (EL20-66).

The commission said Tri-State’s policy reflects “the cost consequences that follow from the choice made by [qualified-facility] sellers to sell their power directly to Tri-State’s utility members rather than to Tri-State under the transmission option.” Referring to precedent set by Order 69, FERC said fixed-cost equalization “is simply a billing mechanism for implementing the avoided-cost pricing for full-requirements contracts.”

While FERC held the settlement judge procedures in abeyance, it also opened FPA Section 206 investigations into whether two Tri-State board policies, a rate schedule and the member project contracts are just and reasonable. It said the policies, rate schedule and contracts raised issues of material fact that cannot be resolved based on the record before it.

One policy describes each member’s option under its wholesale electric service contract to use self-owned or -controlled distributed or renewable generation resources to serve up to 5% of its annual requirement. The second addresses Tri-State’s purchases of power from QFs and sets the terms for Tri-State’s recovery of lost revenue (fixed-cost equalization) when a utility member’s QF power purchases and its non-QF self-supply power exceed the 5% threshold.

The rate schedule in question sets forth the methodology for calculating billing adjustments due to Tri-State under the two board policies.