Page 1046 – RTO Insider

September 22, 2020

DOE Gas Summit Voices Industry Hopes, Gripes

A lack of infrastructure and “well funded” opposition groups are depriving Americans and U.S. trading partners of the country’s abundant and cheap natural gas, participants in the Department of Energy’s 2020 Natural Gas Summit said last week.

Energy Secretary Dan Brouillette kicked off the virtual event Thursday with a warm tribute to the oil and gas industry.

DOE Gas Summit — Energy Secretary Dan Brouillette | *DOE*

“We talk about this industry often in terms of number of jobs created, and that’s absolutely true: You are hiring Americans all across the country and, in fact, all across the world,” Brouillette told industry executives participating in the summit. “But you are also providing this president — and any future president who chooses to wrap their arms around this important industry — with foreign policy options that many presidents have not had in the last four to five decades.”

That spirit of bonhomie continued after Brouillette turned the mic over to the Trump administration’s top economic adviser Larry Kudlow, a panel moderator, who said: “No better cabinet officer than Dan Brouillette. None. Zero.”

Kudlow took a moment to praise his boss.

“President Trump has put a premium on energy and energy dominance, or energy independence, or however you want to call it, and he will continue to do so,” Kudlow said. “I don’t want to politicize this; I just want to say that the other team, if you will, has some bizarre plans that would do great harm to energy, to the economy, to jobs, and so forth.”

Kudlow made clear his stance on increased fossil fuel production in the U.S.

“I myself have become a tremendous proponent of LNG in negotiations with Europe. I’m an unpaid, un-commissioned salesperson,” he said. “Not too long ago, in 2008, I was the guy on TV who started the [CNBC show Kudlow & Cramer] every night for a couple months [saying,] ‘Drill, drill, drill.’ So, I think you understand my sympathies — or biases.”

Advancements in fracking have made the U.S. the world’s leading producer of natural gas.

And so it went during an event that was more a confab of gas industry insiders and supporters than a rigorous exploration of the potential impacts — good and bad — of expanded natural gas production and consumption in the U.S. and worldwide. Conspicuously absent from the summit were any representatives of “the other team,” presumably Democrats, environmentalists or Green New Dealers.

Here’s some of what RTO Insider heard.

Stepping on the Hose

“We know that the foundation of the economic recovery that we expect [after COVID-19] is going to be energy. This industry historically has provided inexpensive energy for the American people,” said Mike Sommers, CEO of the American Petroleum Institute.

While other costs such as housing and education have risen as much as two-thirds over the past 10 years, household energy costs have declined 14.7% “as a consequence of the energy revolution that has happened in this country,” Sommers said.

Trump’s regulatory and tax policies have “supported” this industry, which “is going to lead the way from an economic recovery perspective,” he said. “But I think what is really important for the United States natural gas industry, in particular, is how do we get the infrastructure online so that we continue to support America’s energy revolution.”

Activists “on the other side of this industry” are seeking to halt that recovery, Sommers said.

“What they’ve figured out … is that they can’t beat us on the supply side, and they can’t beat us on the demand side — the world is going to continue to demand these products,” he said. “What they do is try to step on the hose in the middle and stop this country from building the infrastructure that it needs to continue to grow.”

“When you look at the profile of natural gas, it not only reduces greenhouse gas emissions … it’s the No. 1 reason why the U.S. has reduced greenhouse gas emissions more than any other country, including Europe. And we did it through market economics, not heavy-handed government policies,” said Kathleen Sgamma, president of the Western Energy Alliance.

While the U.S. has led the world in volume of GHG reductions since 2000, it is still the second-largest emitter, behind China. E.U. countries, which emit fewer GHGs overall, have actually seen larger percentage reductions over that time. The U.S. and Canada still remain the biggest per capita emitters by far, at 18 tCO2e and 20 tCO2e, respectively.

Sgamma added that natural gas use has also contributed to the 77% decline in other air pollutants in the U.S. since 1970.

“If you want to see a clean energy transformation, it has to include natural gas,” American Gas Association CEO Karen Harbert said.

Sgamma said “the other team” is not “really interested in a solution that actually works and protects the environment. I think they’re interested in government control of the economy [and] government control of energy; and that involves a scarcity to the consumer, like the scarcity of natural gas in the dead of winter in New England, which when you hit that reality, it causes Russian imports to come in because they won’t let a pipeline be built.”

States such as Oregon, Washington and New York are using Clean Water Act certification processes “to stop interstate commerce by preventing pipelines,” she said, appealing to the Trump administration to “remove states’ ability” to take such actions.

Deputy Interior Secretary Katherine MacGregor, a former oil and gas lobbyist, lauded Trump for “absolutely chang[ing] the game of deregulation in Washington, D.C.” She called the administration’s move to shorten National Environmental Policy Act reviews from 4.5 years to under one year “nothing short of significant.”

“If you think about it, when you’re permitting a pipeline like Kathleen’s talking about … there’s so many different statutes you have to deal with, and there’s so many levers that folks who don’t want production can pull,” MacGregor said.

PennEnergy Resources CEO Richard Weber said any other county in the world would envy the U.S. position of having abundant natural gas. Gas projects confront opposition from “four or five very well funded, very left-wing environmental groups — or so-called environmental groups, because I think if you really cared about the environment you would embrace natural gas,” he said.

Farmington, N.M., Mayor Nate Duckett | *DOE*

“We’ve solved the supply problem here in America,” Brouillette said. “What is challenging us, and what I think is challenging the industry, is an infrastructure problem. We need more pipelines. We need more export facilities. We have to improve our permitting processes so that we can allow this infrastructure to be built more quickly, more efficiently.

“The product has no value without its ability to get to market. … So, we must work much more aggressively to get that done,” he said.

Nathan Duckett, mayor of Farmington, N.M., said he “absolutely agrees” with the rollback of regulations on gas infrastructure. His city, which sits in the gas-rich San Juan Basin is “surrounded by public lands.”

“If they were to stop the extraction of natural gas from public lands, that would be a huge detriment to our area,” Duckett said, calling it a “stake in our heart.”

‘Fundamentally Wrong’

“I have nothing against renewables — nothing,” Kudlow said. “I think, as an amateur, solar has probably made the most inroads in the renewable field.”

But, he continued, “you only have 10% of energy coming from renewables, but my friends on the other team say we can do it all through renewables, maybe in 15 or 25 years. … If we’re only at 10% now, how does that happen? I just don’t get that. I don’t see a pathway.”

Renewables accounted for 11% of U.S. energy use and 17% of electricity consumption last year, according to the Energy Information Administration.

“It is fundamentally wrong at this point, in my view, to have a state or have a country adopt a 100% renewable policy,” Brouillette said. “There are a number of technologies that are coming online that are related to things like battery technology that may at some point allow some additional integration of renewable electricity generation into our electric grid, but it doesn’t exist today.”

Pointing to the recent grid emergencies that have plagued California, Brouillette called out the state’s policy goal of a carbon-free electricity system by 2050 on top of closure of its nuclear power plants.

“Now they’re looking at their natural gas industry and saying, ‘We don’t want you here. Our policy is going to be 100% renewables. And should we need some extra electricity, we’ll buy it from Arizona, we’ll buy it from Nevada,’ who are using natural gas and, in some cases, nuclear energy as well,” he said.

Brouillette likened California to his “environmentally sensitive” daughter who doesn’t want to buy a car but chooses to instead borrow one from her sister, which works fine until they both need it at the same time.

“And that’s what happened in California. They needed electricity because it was pretty hot, which is not unusual in California … but it was also hot in Arizona and Nevada. And those states chose to keep their electricity because they like their air conditioning and they wanted their lights to come on when they come home at night,” he said.

There are multiple competing theories about the main causes of the recent California blackouts, ranging from a shortage of imports to potential market manipulation. Theories Abound over California Blackouts Cause.)

September 22, 2020

FERC to Investigate Basin Electric Rates; Danly Dissents

FERC last week opened an investigation under Federal Power Act Section 206 into the justness and reasonableness of Basin Electric Power Cooperative’s 2020 rate schedule and the wholesale power contracts between the cooperative and 19 of its members (ER20-2441, ER20-2442 , EL20-68).

The commission found Basin’s rate schedule and power contracts raised factual issues that should be addressed through hearing and settlement judge procedures.

FERC said it accepted Basin’s 2020 filings because it considered them to be initial rates, effective Sept. 15. The commission disagreed with intervenors’ arguments that a lack of withdrawal and termination procedures rendered the wholesale contracts unjust and unreasonable, saying each contract includes provisions requiring notice of termination for the contract term’s end.

Basin Electric Rates — FERC Commissioner James Danly at his confirmation hearing in November 2019 | © *RTO Insider*

Commissioner James Danly dissented in the order, saying he didn’t agree with the commission’s decision to set for hearing whether the Mobile-Sierra presumption should attach to the wholesale contracts. Under Mobile-Sierra, FERC must presume that the electricity rate set in a freely negotiated wholesale contract meets the FPA’s “just and reasonable” requirement. The presumption may be overcome only if the commission concludes that the contract seriously harms the public interest.

“My disagreement … stems from my general disagreement as to the analysis applied by the commission in considering whether and when the Mobile-Sierra presumption should apply,” Danly wrote. He noted that Basin’s counterparties “almost uniformly agree[d] that ‘without a doubt’” the wholesale contracts were freely negotiated. Only Tri-State Generation and Transmission Association asserted its contract was “not accomplished on an even playing field,” he said.

“Given the near universal support for the [contracts] other than Tri-State’s generalized complaint about bargaining positions, there is no credible claim of infirmity in the [contracts’] formation … that would lead us to conclude that they do not represent the fully voluntary agreement of the parties,” Danly said. “This issue should not be set for hearing.”

FERC Combines Tri-State Membership Fee Dockets

FERC on Sept. 11 accepted Tri-State’s methodology for members’ one-time payments to become partial-requirements members, but it also established hearing and settlement procedures over the co-op’s buy-down payment (BDP) calculation, subject to refund.

The commission combined the proceeding with another docket involving Tri-State that it set for hearing in June concerning the cooperative’s proposed contract-termination payment (CTP) methodology for computing member exit fees (ER20-2417, ER20-1559). (See FERC Sets Tri-State’s Exit-fee Rules for Hearing.)

FERC found there were several common issues regarding Tri-State’s use of the two methodologies and agreed with United Power, a Tri-State member, to consolidate the proceedings.

Tri-State’s BDP methodology is designed to give its utility members additional flexibility for the self supply of power and more local renewable energy development.

In February, Tri-State’s board agreed to hold an open season to allocate 300 MW of systemwide member self-supply capacity for future member partial requirements contracts, equal to 10% of Tri-State’s total demand. Under previous rules, members were limited to self supplying only 5% of their power, with an additional 2% through community solar.

The cooperative said the BDP methodology establishes a framework for holding partial requirements customers responsible for the costs incurred in permitting them to switch to partial requirements service without imposing a financial burden on the remaining full-requirements members.

Tri-State said the proposed methodology uses the same underlying mark-to-market method as the CTP methodology. The mark-to-market method is a planning approach, Tri-State said, with the departing utility member’s required BDP based on a forecasted difference between the cooperative’s long-term financial forecast (LTFF) business-as-usual case and load-loss case.

FERC said its preliminary analysis indicated the proposed methodology had not been shown to be just and reasonable.

Several Tri-State members protested in the docket, raising concerns that certain material terms and conditions are referenced in the cooperative’s transmittal letter but are not included in the rate schedule. FERC found that terms and conditions of Tri-State’s proposal to impose a full transmission service requirement on partial requirements members needs to be filed with the commission under FPA Section 205 and included in its rate schedule.

September 22, 2020February 5, 2025

CAISO Seeks ‘Firm’ Tx for Resource Adequacy

A CAISO resource adequacy workshop Thursday was part of an initiative that started nearly two years ago, but it could not have been more timely following the heat waves and energy emergencies of mid-August and Labor Day weekend.

During those periods, the ISO had to compete for strained energy resources across the West, scrambling last-minute and paying sky-high prices for imports to cover peak demand. California was criticized by some for relying too heavily on imports that grew scarce as other states tried to meet heavy demand amid record temperatures.

The Resource Adequacy Enhancements Initiative, launched in October 2018, deals in large part with securing imports to cover such situations without the uncertainty that plagued the state and led to rolling blackouts Aug. 14-15. (See Theories Abound over California Blackouts Cause.)

“Our challenge, in this RA imports policy, is how do we strike that right balance between ensuring that our imports, which we rely on heavily, are reliable and dependable, and yet we understand we are competing for this supply broadly across the West?” said John Goodin, the ISO’s senior manager for infrastructure and regulatory policy. “How do we not make it so onerous that others reject the California market as too rigorous and go sell somewhere else?”

The CAISO market needs to be “liquid and able to trade and transact imports,” he said.

The authors of the initiative’s issue paper wrote that CAISO’s must-offer obligations, RA substitution rules and resource availability incentive mechanisms together “create a very complicated system of processes that differ vastly from other ISOs/RTOs.” Part of the initiative involves addressing those “overly complicated” processes.

Goodin spoke Thursday about the need for the ISO to ensure that it has dedicated generation and transmission capacity for RA imports.

“You not only have to lock up the source, but you have to lock up the transmission as well,” he said.

The ISO’s “perennial concerns” are that “speculative” supply and double-counted resources are clouding its RA import estimates, Goodin said. CAISO wants out-of-state suppliers to dedicate specific generation resources, including pooled resources, to serving California load so that CAISO is not relying on supply that doesn’t materialize, he said.

The ISO prefers resources come from a seller’s capacity reserves and that non-delivery be subject to fines.

“That’s the key point,” Goodin said. “It’s backed by capacity reserves, and it pays damages if it’s not delivered. Those are the two requirements we’re very interested in.”

Firm Transmission

More recently, the ISO has been worried about not having the means to bring in energy from out of state.

The “hotter topic is the delivery assurance,” the transmission side of RA imports, Goodin said.

During the “heat storms” of August and September, vital transmission lines linking Southern California to the Pacific Northwest were pushed to their limits and sometimes beyond, he said in his presentation to the RA Enhancements Working Group. Slides showed the strained situation at the California-Oregon Intertie (COI).

The COI and Pacific DC Intertie were at or near maximum capacity during the mid-August Western heat wave. | CAISO

Goodin argued the situation underscored the need for firm transmission service that’s guaranteed, especially in times of crisis.

“RA import capacity must be dependable and deliverable on high-priority transmission service,” one of his slides said.

Some stakeholders — such as the Bonneville Power Administration, Calpine and LS Power — back the proposal for firm point-to-point, source-to sink transmission.

However, the plan is unpopular with other stakeholders who contend it isn’t necessary and could even prove harmful.

Opponents include California’s community choice aggregators, represented by the California Community Choice Association, and the state’s three large investor-owned utilities: Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.

The publicly owned Sacramento Municipal Utility District also opposes firm transmission, arguing there’s no supporting data demonstrating the need for it. Though at or near maximum capacity, the COI’s 500-kV lines retained some transfer capacity during the crises in August and September, opponents contended.

Financial services firm Morgan Stanley argued that firm point-to-point transmission will do more harm than good.

“The CAISO should reject the arguments promoting source-to-sink firm requirements,” Ali Yazdi, a head energy trader with Morgan Stanley Capital Group in Canada, said in his written comments on the ISO’s fifth revised straw proposal, now under discussion. “These stringent rules will only serve to squeeze out competition, reduce diversity of supply and, in fact, harm reliability.”

The plan could lead to long-term hoarding of transmission rights by entities that stand to gain the most, Yazdi said. He reiterated his comments during Thursday’s workshop.

Morgan Stanley and others favor an alternative proposal by CAISO that requires firm transmission delivery only on the last line of interest, the last leg to the CAISO balancing authority area. Goodin said the alternative remains a viable option.

Thursday’s meeting was one of two held last week by the RA working group; the first dealt mainly with unforced capacity evaluations. Comments on the sessions are due Oct. 1, and a draft final proposal is due Nov. 3. The CAISO Board of Governors is expected to take up the plan in the first quarter of 2021.

September 22, 2020October 21, 2025

Counterflow: No Carb California

Steve HuntGood news! California may not know what caused the rolling blackouts last month, but it does know that 25 years from now, a zero-carbon grid would be totally reliable.

Good news! California may not know what caused the rolling blackouts last month, but it does know that 25 years from now, a zero-carbon grid would be totally reliable.

That’s the verdict of California Energy Commission Chairman David Hochschild and other commissioners at a joint agency workshop on state law SB 100, which requires a zero-carbon grid by 2045, early this month. (See Study: Calif. Must Build Renewables at Record Rate.)

The core scenario presented at the workshop calls for a staggering amount of new solar (109 GW), new wind (30 GW) and new batteries (50 GW). For context, this would be a 528% increase from existing solar, 488% in wind and 5,417% in batteries.[efn_note]Existing solar and wind resource data from the Energy Information Administration’s Electric Power Monthly, Table 6.2.B. Existing battery resource is existing and planned by end of 2020. https://www.utilitydive.com/news/largest-battery-resource-connects-caiso-system/581540/.[/efn_note] All this results in a projected annual resource cost of $66 billion and a generation rate cost component of 16 cents/kWh — about double the current one.

We’ll get into the weeds below, but there were some red flags right at the outset. First is that the study’s modeling was adapted from the California Public Utilities Commission’s 2019 integrated resource planning model, which is the same model that said the chance of rolling blackouts last month was 1 in 500.

Second, CEC staff said that the study was “not explicitly testing the reliability of the portfolios.”

Third, this gathering of multiple agencies unintentionally confirmed the elephant in the room: no unity of command for planning and reliability. As long as that continues, so will the blackouts and the finger pointing.

With those warm fuzzies out of the way, let’s roll into the weeds.

Peak Day Resource Adequacy

With general load growth and high electrification (electric vehicles, building electrification, etc.), the study projects peak-day demand in 2045 of 87 GW and adds a planning reserve margin of 15% for a resource adequacy requirement of 100 GW (slide 11).[efn_note]The workshop slides are here, https://efiling.energy.ca.gov/getdocument.aspx?tn=234549.[/efn_note]

How is that covered? Slide 17 from the workshop shows how. Please focus on the middle column showing “SB 100 Core,” which is the principal scenario, supposed to reflect compliance with SB 100.

Starting from the top of the stack, first is “Variable Renewable ELCC,” which looks to be about 20 GW. But existing and new solar of 130 GW at an effective load-carrying capability (ELCC) of 2%, as shown on the slide, would be about 3 GW, and existing and new wind of 36 GW at an ELCC of 19% would be about 7 GW, for a total solar and wind ELCC of 10 GW. Not 20 GW. Problem.[efn_note]It is possible that the reported ELCCs on slide 17 are marginal values rather than cumulative, in which case this concern may be misplaced.[/efn_note]

Next in the stack is “Long Duration Storage”[efn_note]”Long duration storage” is a bit of a misnomer as it appears to refer to hydro pumped storage of 12 hours duration.[/efn_note] of roughly 7 GW, and then four-hour batteries of about 30 GW. Batteries are problematic for reasons I’ve discussed before.[efn_note]It is possible that the reported ELCCs on slide 17 are marginal values rather than cumulative, in which case this concern may be misplaced.[/efn_note] If you don’t believe me, check out the concerns of CAISO here. (By the way, this CAISO document from last year foretold last month’s crisis pretty well.)[efn_note]http://www.caiso.com/Documents/Jul22-2019-Comments-PotentialReliabilityIssues-R16-02-007.pdf (pages 12-14).[/efn_note]

Next is “Zero Carbon Firm” of roughly 12 GW. This is a catch-all for a variety of possible resources, most of which were excluded from the study as impractical and/or uneconomic and don’t show up in any material way in the chart of capacity additions (slide 15). It seems to be basically green hydrogen fuel cells.

California renewables — As of 2019, there is 80 GW of in-state capacity in California. | *California Energy Commission*

Those won’t come cheap. This unproven technology involves additional “off-grid” solar and wind generation converted to hydrogen by electrolyzer,[efn_note]The Inputs & Assumptions document refers to “assuming off-grid California wind or solar to power the electrolyzer…” https://efiling.energy.ca.gov/getdocument.aspx?tn=234532 (page 41, fn. 20).[/efn_note] compression and storage of the hydrogen, transportation of the hydrogen and conversion of the hydrogen back to electricity via fuel cells. The study presents a projected hydrogen fuel cost of $37.68/MMBtu, 825% more than natural gas, which also doesn’t appear to include the cost of the fuel cell itself and perhaps not fuel cell efficiency loss.[efn_note]Inputs & Assumptions document (pages 84 and 43).[/efn_note] By the way, the soup-to-nuts efficiency is 30%, which makes green hydrogen fuel cells a good way to turn a lot of renewable generation into not so much usable a resource.[efn_note]https://www.greentechmedia.com/amp/article/the-reality-behind-green-hydrogens-soaring-hype. By the way, a good critique of the hype around dirt-cheap future hydrogen is here, https://theicct.org/sites/default/files/publications/final_icct2020_assessment_of%20_hydrogen_production_costs%20v2.pdf.[/efn_note]

Next is about 5 GW of “Import Capacity.” We know how that goes when the West is hot. California has only 2,230 GW of dedicated import resources (Palo Verde and Hoover).[efn_note]Inputs & Assumptions document (page 91).[/efn_note]

Finally, the stack shows about 28 GW of “Fossil Firm,” which was explained at the workshop to essentially be the existing gas fleet. It also was stated at the workshop that carbon sequestration was excluded from the study.[efn_note]”Candidate Resources … • Removed Natural Gas w/ CCS due to insufficient cost data” (slide 7).[/efn_note] So this gas can’t be a zero-carbon resource.

Here’s how I add it up from what’s tangible. Solar and wind ELCC capacity value of 10 GW, long-duration storage of 7 GW, dedicated import resources of 2 GW and if you optimistically add batteries of 30 GW, you get to a zero-carbon resource adequacy value of 49 GW. And then there is the non-zero-carbon gas of 28 GW, which isn’t supposed to be there.

Good luck on that peak day when you need 100 GW.

The workshop did present a true zero-carbon scenario in which more green hydrogen fuel cells essentially replace the gas fleet (slide 33, comparing year 2045 columns). Assuming that, by my math, California would need about 50 GW total of this very expensive, unproven resource.

Piece of cake.

Multiday/Monthly/Seasonal Resource Adequacy

The study does not consider multiday, monthly or seasonal resource adequacy. But such consideration is critical in a system that relies on limited-duration storage resources like batteries.

Why? Because batteries depend on the availability of excess generation over consumption on a given day to recharge batteries depleted the day before. Fossil fuels, in contrast, are effectively 24/7 energy storage, and not dependent upon other resources to recharge. Big difference.

The problem can manifest over varying time periods: whenever there isn’t enough excess generation to recharge batteries before they’re needed again. That could be because of cloud cover for a week that greatly reduces solar generation that would otherwise recharge the batteries, or fires producing smoke and ash that reduce radiance and cover solar panels. Maybe an extended lull in winds greatly reduces wind generation for a week or two.

Beyond this sort of day/week volatility, there is predictable monthly and seasonal variation. This chart from EIA data shows monthly solar generation in California in 2019.[efn_note]At EIA’s Electricity Data Browser here, https://www.eia.gov/electricity/data/browser/, choose the “Net generation” data set, then filter for California and all solar generation, and select the time period and monthly output on a time series basis.[/efn_note] You can see that the high months are more than twice the low months.

In contrast, this chart shows that California’s monthly electric consumption (unlike some other regions with, for example, heavy summer air conditioning load) is fairly steady throughout the year.[efn_note]At the Electricity Data Browser, choose the “Retail sales of electricity” data set, then filter for California and all sectors, and select a time period and monthly output on a time series basis.[/efn_note]

So the problem is with a month like December, with relatively low solar generation and yet average consumption. I crunched study inputs and EIA data to find that California consumption in December would be about 46,250 GWh.[efn_note]The study projects California annual generation in 2045 of 500,000 GWh (slide 16), which I grossed up for transmission and distribution losses of 7.24% (Inputs & Assumptions, page 7) to get annual consumption of 539,000 GWh. Then, to get December’s share of that, I divided December 2019 consumption by total 2019 consumption from EIA’s Electric Power Monthly for December 2019, Tables 5.4.A and 5.4.B. Applying the share percentage of 8.58% to annual gives December 2045 consumption of 46,250 GWh.[/efn_note] When I add up California’s existing renewable generation that month (including imported hydro and Palo Verde nuclear), I get 8,760 GWh.[efn_note]Existing California renewable generation for December 2019 comes from Electric Power Monthly for December 2019, Tables 1.10.A, 1.14.A, 1.15.A, 11.16.A and 1.17.A. Imported hydro and nuclear estimated from the Inputs & Assumptions document, pages 22 and 29.[/efn_note] Then I apply December capacity factors for wind and solar to the new wind and solar resources and get 18,000 GWh.[efn_note]California renewable capacity factors for December 2019 calculated from Electric Power Monthly for December 2019, Tables 1.14.A, 1.17.A and 6.2.B. I used the study’s capacity factor for offshore wind of 52%. The capacity factors are applied to the new renewable resources listed at the beginning of the column.[/efn_note] So, total existing and new renewable generation is 26,760 GWh.[efn_note]Please note that batteries and other storage such as 12-hour pumped storage can’t help a monthly deficiency. They can’t recharge without depleting the supply needed for load.[/efn_note] There is a 19,490-GWh deficiency, i.e., blackouts.

Now, we could assume that the existing gas fleet is still around, despite being a non-zero-carbon resource. I reckon 28 GW of gas running at a 94% capacity factor could cover the deficiency — if levels of consumption and other generation cooperated perfectly. But that doesn’t do much for a zero-carbon future.

As with the peak-day analysis, to achieve true zero carbon, the study presents a scenario that assumes green hydrogen fuel cells replace gas generation. The study projects a green hydrogen fuel cell cost of $126/MWh in 2045 (slide 28), making the cost of covering the December deficiency around $2.5 billion.

And that’s just one month, on top of the massive costs of new solar, wind and battery resources.

What’s the Takeaway?

A zero-carbon, reliable, affordable future remains an enormous challenge. We should be realistic and not sugarcoat this.

Nor should we throw staggering amounts of solar, wind, batteries and fuel cells at the problem and hope for the best. We need to think about all the options, especially on the consumption side of the equation. Efficiency (e.g., LED lighting, which has reduced carbon emissions twice as much as rooftop solar[efn_note]http://www.energy-counsel.com/docs/LED-Kills-the-Edison-Star-2017-01-24%20RTO-Insider-Individual-Column.pdf.[/efn_note]), demand response, load shifting (hot water heating) and time-of-use rates are a few examples.

And on the resource side, let’s not make big mistakes, such as subsidizing rooftop solar that costs four times as much as grid-scale solar.[efn_note]Grid-scale solar is about $40/MWh levelized cost of energy while rooftop solar is about $155/MWh. https://www.lazard.com/media/451086/lazards-levelized-cost-of-energy-version-130-vf.pdf (page 2, using the midpoint for grid solar and averaging the midpoints for both rooftop solar types). California could more than cover the (staggering) costs of 70 GW of new grid solar simply by not subsidizing rooftop solar.[/efn_note] And is it too late to save Diablo Canyon like I urged four years ago?[efn_note]http://www.energy-counsel.com/docs/Helter-Skelter-September-Fortnightly.pdf.[/efn_note] Remember when those insisting on closure said an estimated cost of $69 to $72/MWh made it too expensive to keep?[efn_note]https://www.nrdc.org/experts/peter-miller/diablo-canyon-legislation-signed-law-governor-brown.[/efn_note]

Now even that inflated cost looks like a bargain compared to $126/MWh for green hydrogen fuel cells.

September 22, 2020

ELCC Method Endorsed by PJM Stakeholders

PJM members on Thursday endorsed a revised joint stakeholder proposal to use the effective load-carrying capability (ELCC) method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources.

The Markets and Reliability Committee and Members Committee approved the ELCC over the objections of Independent Market Monitor Joe Bowring and others, who said the proposal, which could have a profound effect on the capacity market, was flawed.

The joint stakeholder proposal, Package D, received a sector-weighted vote of 3.98 (79.6%) from the MRC after a friendly amendment clarifying issues was added at the meeting. In a first-round vote at the MRC, the proposal without the friendly amendment received a sector-weighted vote of 2.56 (51.2%), failing to meet the two-thirds threshold for endorsement.

The Members Committee approved Package D with the friendly amendment later Thursday by a sector-weighted vote of 4.05 (81%).

PJM — Betty Watson, Modern Energy | © *RTO Insider*

ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources. A resource that contributes a significant level of capacity during high-risk hours will have a higher capacity value than a resource that delivers the same capacity only during low-risk hours.

Betty Watson, senior director of policy and market design at Modern Energy, one of the sponsors of Package D, praised the work done by PJM and stakeholders since April when the issue was brought to the Capacity Capability Senior Task Force (CCSTF).

“The package approved by stakeholders today represents an important step forward for the participation of energy storage and intermittent renewables in PJM,” Watson said. “Just as important, the package represents the result of meaningful stakeholder cooperation and finding common ground.”

ELCC Background

Melissa Pilong of PJM provided an update of the work completed at the CCSTF. In October 2019, FERC opened a paper hearing under Federal Power Act Section 206 on the capacity capability of energy storage resources in PJM. Pilong said ELCC, which was already under consideration for solar and wind resources in the RTO, could serve as an alternative to the 10-hour minimum run time requirement for storage that was rejected by FERC last October.

FERC partially approved PJM’s Order 841 compliance filing but set a paper hearing to determine whether its 10-hour minimum for storage seeking capacity obligations was unjust and unreasonable. (See FERC Partially OKs PJM, SPP Order 841 Filings.)

Pilong said that by January, PJM began soliciting feedback from stakeholders on proposed alternatives to the 10-hour requirement. PJM then submitted a motion to hold the FERC hearing in abeyance to pursue an ELCC construct with stakeholders. The commission ultimately granted PJM’s abeyance motion, setting a deadline of Oct. 30 for a response from the RTO.

The MRC approved an issue charge in March to consider using ELCC to set the capacity value of limited-duration resources such as battery storage. The issue was then sent to be worked on by the newly created CCSTF. (See PJM MRC Moves Forward on Storage, Hybrids.)

Proposed Packages

Andrew Levitt, PJM’s senior business solution architect, presented Package A, the main motion endorsed by the CCSTF, receiving 64% support in a nonbinding vote in the subcommittee.

Levitt said the PJM package had several key characteristics, including specifying the ELCC methodology for simulated dispatch of energy storage resources, hydroelectric resources with storage and other limited-duration resources. It also provided for an annual reassessment of derate factors, performance factors and accredited unforced capacity (UCAP) values for all applicable resources.

Levitt said the package was designed to accommodate a diversity of resource classes, including new technology like four-hour energy storage resources and hybrids.

Package A ultimately failed at the MRC, receiving a sector-weighted vote of 1.29 (25.8%).

Watson reviewed Package D at the MRC, which was the alternative solution endorsed by the CCSTF with 57% support in a nonbinding poll. Watson said the joint stakeholder transition package was formulated to find a balance between accurate and stable market signals, stakeholder preferences, the various business models of asset owners and existing and future resources.

Watson said the package was a “true negotiated outcome” and not the design of any one stakeholder. It built upon the foundation of Package A and went even further, Watson said, adding in a transition package that provides values for the class average ELCC percentages. The transition package will be evaluated in the 2026 quadrennial review, Watson said, in which PJM will “evaluate its efficacy and appropriateness and make recommendations as to whether some or all components of this package should be reconsidered through a stakeholder process.”

The friendly amendment added to Package D was developed after further discussions with stakeholders, Watson said, with an agreement to further evaluate the operations of limited-duration resources following FERC approval of the ELCC-related filing that includes a four-hour limited-duration class. PJM will also initiate a stakeholder process to further evaluate the coordination of the operation of limited-duration capacity resources with system needs and to consider rules to ensure that their operational behavior is “appropriately aligned with the resource adequacy construct and system reliability by examining issues including, but not limited to, bidding, operations, emergency procedures and energy market offer requirements.”

Also in the friendly amendment is a “clarification of intent of transition” with language recommended to the PJM Board of Managers to include in the cover letter for the proposal’s filing with FERC, stating, “Nothing in the joint stakeholder package is intended to preclude any potential changes to the structure and market design of PJM’s Reliability Pricing Model or create the expectation that the current market design will remain intact.”

“This package is not at all where the joint stakeholders started but really represents the evolution that we’ve all arrived at after months of dedicated work,” Watson said.

Besides the packages, stakeholders also voted to endorse corresponding Reliability Assurance Agreement (RAA) revisions.

Stakeholder Opinions

Monitor Bowring gave a presentation on his firm’s interpretation of the ELCC, saying it was “premature” for stakeholders to rush toward a solution on the issue. Bowring said the solutions in the packages could have significant impacts on the PJM capacity market for decades because of issues like a locked-in floor value based on a 10-year forecast of ELCC values.

Bowring said a 10-year ELCC forecast will be based on unknown inputs, including thermal and intermittent capacity levels, which would prevent a mechanism for understanding the ELCC forecast error. He said the ELCC should reflect the capacity resource mix and can only be accurately determined when incorporated into PJM’s market clearing engines.

“We just want to emphasize that the ELCC approach represents a really significant change to the capacity market,” Bowring said. “We don’t think there’s any reason to rush.”

Calpine’s David “Scarp” Scarpignato said FERC put PJM in a position where it’s difficult to meet deadlines while still adequately addressing the issues surrounding ELCC. Scarp said he hoped there would be more time to formulate a more clearly defined solution to the issue and wanted to see more data from PJM to make a more comprehensive decision.

“We weren’t given adequate time as stakeholders to truly give this justice,” Scarp said. “I imagine we’re going to have to rework some of this in the future.”

Tom Rutigliano of the Natural Resources Defense Council said both proposed packages were a “major improvement” in how PJM handles non-traditional resources and represented a “big step forward” in how the RTO handles resource adequacy in a “rapidly changing grid.”

Carl Johnson of the PJM Public Power Coalition said most stakeholder criticisms of the packages were “valid” and presented a difficult issue for members to solve as PJM makes its filing with FERC next month. Johnson said the packages provided little detail as to how resources would be represented in the ELCC model and how they would actually have to behave in real-world scenarios for the model to work.

“Above all, it’s certainly in my members’ interest that we do not send another mess to FERC or that we at least limit the mess,” Johnson said.

September 20, 2020

MISO Looks Back on Turbulent Summer

With a challenging summer in the rearview, MISO expects more traditional reliability risks this fall while making blueprints for an industry roiled by change.

MISO’s relatively low 114-GW summer peak in early July and average $21/MWh real-time prices belied a whirlwind season containing two emergency declarations. The peak was lower than both the grid operator’s projection (125 GW) and last summer’s peak (121 GW).

In late summer, MISO directed its first load-shed event after Hurricane Laura ripped through the heel of Louisiana. (See MISO Keeps Advisories in Effect a Week After Laura.)

MISO Executive Director of Market Operations Shawn McFarlane said the RTO began preparations for the hurricane about a week before the storm’s landfall. At the grid operator’s orders on Aug. 27, Entergy shed about 573 MW of load in the West of the Atchafalaya Basin load pocket.

The load-shed orders maintained grid stability and kept MISO South from experiencing cascading outages, McFarlane said during a summer review Sept. 15 before the Board of Directors’ Markets Committee.

MISO estimated that uplift payments totaled $90 million during the event. McFarlane said that is the largest the RTO has ever experienced from a single episode.

It could take until the end of October to restore power to all Louisiana ratepayers, based on Entergy’s restoration estimate, he said. About 80,000 Entergy customers remain without power, down from approximately 700,000 immediately after the storm.

McFarlane also said MISO monitored Hurricane Sally, which was brewing in the Gulf of Mexico before ultimately tracking east of its footprint.

The grid operator continues to review the Laura event and will hold future stakeholder discussions during the Market Subcommittee’s public session, McFarlane said. Subcommittee Chair Megan Wisersky has proposed a special joint meeting with the Reliability Subcommittee on Oct. 1 to discuss the hurricane’s impact on the grid.

RTO executives also reported that proactive communication with other grid operators was much improved during its other maximum generation event on July 7, when MISO Midwest was seized by a stubborn heat wave.

“It’s good to hear that coordination has improved. That’s what the public expects of us,” Board Chairman Phyllis Currie said.

“This was an exciting quarter. Usually I begin by saying it was an uninteresting quarter,” Independent Market Monitor David Patton said.

Patton said he is concerned about the availability of supply in Michigan’s Lower Peninsula, which racked up high congestion costs this summer. He said three resources in one transmission pricing zone that cleared the annual Planning Resource Auction were unavailable for most of the summer.

“They provided us virtually no value during the summer,” he said.

MISO: Fall Emergency a Possibility

McFarlane said MISO expects near normal load going forward.

“Load levels will more or less be at the level of what we call non-COVID,” McFarlane told the board. “We haven’t totally confirmed this, but our suspicion was air conditioning load was making up for economic impacts” during the summer, he said, explaining that mostly empty offices were still being temperature controlled while widespread work-from-home employees kept their houses comfortable too.

MISO might have to declare an emergency this fall if conditions are right, despite its 152 GW of available capacity paired with a 113-GW forecasted seasonal peak.

“As we say every quarter, if we end up in a high-load, high-outage situation, it may require access of our emergency resources,” McFarlane said.

He said higher outages paired with extreme weather conditions could lead to tightening supply. MISO said it’s preparing to work around more outages than usual this year, as the pandemic lockdowns in spring led to maintenance rescheduling.

“In the spring, 20 GW of outages were deferred,” McFarlane said.

MISO expects to have a little more than 115 GW of total available capacity in September after factoring in outages. If load stays at normal levels — about 112 GW — the grid operator doesn’t foresee a problem. But if high demand pushes load to 119 GW, MISO will have to dip into at least a few gigawatts of its 14.6 GW in load-modifying resources and operating reserves. The supply picture worsens if MISO has only 104.1 GW of capacity, as predicted by its worst-case outage scenario.

The RTO said that as usual, the largest amount of generation outages are slated to occur in October and November. It said the two months contain the highest potential for significant generation outages on monthly peak days.

MISO projects about 94.2 GW of available capacity in October with nearly 90 GW of usual load and a 95.2-GW high load. Increased outages could cull capacity to just 90.6 GW, making emergency measures all but certain in a high-demand scenario.

In November, MISO said available capacity should rise to 97 GW, handling both a typical 90.3 GW load and a 95.7 GW high load. However, if generation doesn’t return as expected, MISO could have just 92.6 GW of capacity on hand during the month, spurring operational challenges.

Changes Ahead

MISO Executive Director Ken McIntyre, a former NERC and ERCOT staffer, is helping the RTO modernize its operations and markets as the electric industry moves toward renewable and more dispersed generation.

“Today, we rely on operator experience and years and years of on-the-job-training. Tomorrow, we will have to rely on advanced monitoring and decision-support tools that predict conditions and provide guidance. Today, more days are the same. Tomorrow, more days will be different. The seasonal and peak demand profiles will become … less obvious and less meaningful for day-to-day operations,” McIntyre said.

He said MISO can launch automated tools using artificial intelligence in control rooms that can “pre-position the grid” for extreme weather or outages.

Vice President of System Planning Jennifer Curran said operations decisions will rely more on artificial intelligence and automated processes in the future.

“Today, we rely on operators with years of experience, and many of them are near retirement,” Curran said during the full board’s Thursday meeting. “There’s not a ready pool of additionally experienced operators to replace them.”

Director Barbara Krumsiek asked how MISO might incorporate “non-traditional forecasting arenas,” such as social forces, to predict energy demand. She pointed out that a coronavirus vaccine’s introduction could rally the economy and cause electricity demand to spike.

McIntyre said MISO might gather society trends by “scraping” data on social media to influence forecasts.

Patton also said MISO should transition to a “more sophisticated, probabilistic forecast” in their control rooms. He said that when faced with tight conditions, MISO tends to overcommit resources. That overcompensation often results in high revenue-sufficiency guarantee payments but low LMPs, he said.

“The tools could be much better to let operators make more surgical decisions,” he said.

September 20, 2020

MISO Readying Intensive Transmission Planning

Two recently announced special transmission planning efforts could have MISO members soon stringing miles of new wires across the footprint.

Stakeholders heard last week that a recently announced long-term transmission plan may result in project approvals as early as late 2021. At the same time, MISO and SPP will partner on an extra study focusing on transmission projects that could bring more of the renewable generation in the RTOs’ interconnection queues online. (See MISO, SPP to Conduct Targeted Transmission Study.)

Jennifer Curran, MISO’s vice president of system planning, said during the Board of Directors’ teleconference Thursday that while member companies’ renewable transition plans are disparate, stakeholder attitudes have shifted in favor of new transmission to support the metamorphosing generation portfolio.

MISO transmission planning — Jennifer Curran, MISO | *MISO*

“I think in our stakeholder community, we’re in quite a different place, even from a year ago,” Curran said. “Not all stakeholders are enthusiastic about new transmission … but we have received a lot of letters, feedback [and] emails from stakeholders saying, ‘Yes, it’s time to get going.’ 2030 is the equivalent of tomorrow when you’re talking about long-term, large-scale transmission projects. The work must begin today.”

MISO in mid-July confirmed it will undertake a series of long-range transmission planning studies under its annual transmission planning cycles. (See MISO Foresees Massive Shift to Renewables by 2040.)

Curran likened long-term planning to considering buying a new car rather than replacing a high-mileage car’s bald tires and fixing an oil leak. Long-term projects will not be approved en masse in a special portfolio, but under different annual MISO Transmission Expansion Plans, she said.

“With the Multi-Value Projects, it took four or five years to decide on projects for board approval. I just don’t think we have that kind of time here to bring projects forward for approval in 2025,” Curran said during the board’s System Planning Committee meeting Sept. 15.

From 2020 to 2022, MISO expects members to bring more than 25 GW in new generation online. That number pales in comparison to the 756 projects, totaling 113 GW, currently awaiting interconnection in its queue. (See MISO Processing Heftiest Interconnection Queue Ever.)

Curran acknowledged it will be challenging to find that “just-right, Goldilocks” level of long-term project approvals.

MISO and stakeholders will also work on cost-allocation processes next year as more immediate project needs emerge, she said.

The Organization of MISO States last week announced it has formed a special committee to examine and advise MISO on possible cost-allocation methods for long-term transmission projects. The special committee will be helmed by Indiana Utility Regulatory Commissioner Sarah Freeman.

Curran said the regulators’ perspective on cost allocation will be invaluable to MISO.

Teamwork with SPP

In a first, SPP CEO Barbara Sugg joined the MISO board’s virtual meeting on Thursday to discuss the RTOs’ increasingly crowded generation interconnection queues, the catalyst for the new joint study.

“SPP and MISO are such similar organizations dealing with such similar issues. … Our interconnection queue certainly draws the most criticism in SPP, and I’d wager MISO gets its share of criticism too. I think there’s no better time to collaborate and work together,” Sugg said.

“We thought about those queues … and how to make a difference for both of our members,” MISO CEO John Bear said in agreement.

MISO Executive Director of System Planning Aubrey Johnson said the study will likely last a year and is meant to identify project opportunities that wouldn’t be unearthed in the RTOs’ coordinated system plan studies.

Sugg gave MISO staff her “heartfelt thanks” for joining forces with SPP to possibly plan transmission together.

MISO Board Chairman Phyllis Currie said it was refreshing to see the cooperation between the two RTOs.

“I think her presence today says a lot about the level of commitment,” Currie said of Sugg’s address.

“Meeting after meeting, I’ve heard from our stakeholders that we need to do something about our seams issues. I hope this is evidence that we hear you,” Currie told stakeholders. “We can’t solve all seams issues, but I think it’s important we show that we’re listening to concerns.”

Director Baljit Dail said the “fantastic” teamwork between MISO and SPP was difficult to imagine more than a decade ago when he joined the board. “It may have taken a bit of time to get there, but we got there,” he said.

Clean Grid Alliance’s Beth Soholt also commended MISO and SPP for agreeing to the “important undertaking.”

Director Mark Johnson asked that MISO executives update the board on the study’s progress during the March quarterly board meeting.

September 20, 2020

NC Muni Wins Right to Add Storage over Duke Objections

FERC on Thursday granted North Carolina Eastern Municipal Power Agency’s (NCEMPA) request for a declaratory order allowing it to add battery storage to its system under its full-requirements power purchase agreement with Duke Energy Progress (EL20-15).

The commission rejected Duke’s opposition to the request, ruling that the PPA permits NCEMPA to use battery storage technology as either demand-side management or demand response. The commission cited a sentence in the agreement stating that it does not “preclude [NCEMPA] and/or its members from instituting or promoting activities designed, in whole or in part, to manage or reduce the members’ demands and/or loads through demand-side management programs.”

NCEMPA) storage — NCEMPA serves 32 cities and towns with their own municipal electric distribution systems in North Carolina. | *Electricities of North Carolina*

“When used as NCEMPA proposes, battery storage technology is inherently a load-shape-modifying device, designed not to reduce a customer’s overall load, but to shift the incidence of such load, i.e., to manage the customer’s demands,” the commission said. “Similar to other demand-side management activities, such as pre-cooling buildings overnight or midday to avoid withdrawing energy to provide air conditioning during afternoon peak-load conditions, NCEMPA’s proposed use of battery storage technology simply determines when energy is consumed.”

NCEMPA said it intended to use storage to reduce its load when prices are high because of increased system demand.

The commission noted that Order 841 — although not applicable in this case because NCEMPA is not part of an RTO or ISO market — “confirms that battery storage resources are capable of providing demand response service.”

The commission rejected Duke’s “restrictive interpretation” that battery storage is a form of generation, saying that it allows “a withdrawal of energy for later injection back onto the grid.”

Duke’s “argument ignores the fact that NCEMPA still would be purchasing its full energy requirements from Duke. The power used to charge the batteries would come from Duke’s generation, and then that power would be discharged from the batteries to serve NCEMPA’s customers,” FERC said. “The fact that NCEMPA is buying power from Duke at one hour and then using that same power from Duke in another hour does not change the fact that NCEMPA is meeting its full requirements through Duke.”

NCEMPA serves 32 cities and towns with their own municipal electric distribution systems. Between 1981 and 2015, it was the co-owner with Duke of two coal-fired generating units and three nuclear-fueled generating units operated by Duke.

September 20, 2020

FERC: No MISO Rules on Mid-queue Fuel Change Studies

FERC on Thursday said that MISO’s Tariff was silent on the issue of whether a generation project can switch from wind to solar while in the RTO’s interconnection queue (ER19-1823-003).

It also said that there was no requirement in Order 845 that requires grid operators to study projects that opt to change fuel types.

The issue stems from a Leeward Renewable Energy Development wind project currently in the definitive planning phase (DPP) of MISO’s generator interconnection queue. The developer wants to convert the project to using solar energy while also retaining its position in the queue.

Leeward said MISO was disregarding its own Tariff when it refused to perform an analysis to determine whether switching the project would constitute a material modification. Borrowing a phrase from Order 845, Leeward argued that the switch would result in “equal to or better” electrical performance.

Order 845 allows interconnection customers to make certain technological advancements to their generation projects without triggering a material-modification rule. Under the order, a customer can offer evidence that a requested technological change results in “equal to or better” performance. MISO must evaluate such claims and render a decision before projects can proceed.

MISO fuel change — | *Leeward Renewable Energy Development*

Order 845 also dictates that changes between wind and solar technologies should not automatically be treated as non-material modifications because “such changes involve a change in the electrical characteristics of an interconnection request, and the transmission provider would likely need to evaluate the impacts of such changes.”

MISO argued that it should not have to evaluate “mid-DPP fuel change requests” under Order 845 and said its Tariff doesn’t permit fuel type changes to projects after they enter the DPP.

But FERC said the Tariff allows Leeward to at least make a case for a fuel change in its generation project. It said Order 845 didn’t change MISO’s pre-existing material-modification provisions in its generator interconnection procedures. While Order 845 doesn’t require the grid operator to study fuel type changes, FERC said MISO also doesn’t have language in its generator interconnection procedures to preclude itself from studying fuel change requests.

“We find that the question of whether these pre-existing Tariff provisions allow an interconnection customer to submit a fuel change request after its project enters the DPP is therefore outside the scope of MISO’s Order No. 845 compliance filing,” FERC said.

The commission added that its decision was without prejudice to MISO making any filings to “further address the permissibility of, and requirements for, fuel change requests.”

September 20, 2020

FERC Upholds MISO Self-fund Order, Glick Dissents

FERC on Thursday left MISO transmission owners’ ability to self-fund network upgrades intact over a protest from the American Wind Energy Association and the dissent of Commissioner Richard Glick (EL15-68-005, et al.).

MISO in August 2018 reinstated TOs’ rights to self-fund network upgrades necessary for new generation. That meant generator interconnection agreements signed between June 24, 2015, and Aug. 31, 2018, could be revised to allow TOs to fund network upgrades and bill interconnection customers. (See MISO Gauging Aftershocks of TO Self-fund Order.)

The change came after the D.C. Circuit Court of Appeals remanded FERC’s 2015 decision barring TOs from electing to provide initial funding for network upgrades.

MISO Self-fund Order — FERC Commissioner Richard Glick | © *RTO Insider*

AWEA argued that the commission’s ultimate decision is “patently discriminatory” because it will allow those who had never applied for the self-fund option to do so and treat different interconnection customers differently. The association pointed out that before mid-2015, only one MISO TO has ever opted to self-fund a network upgrade.

FERC disagreed with the claims of discriminatory treatment.

“The fact that transmission owners may not have elected transmission owner initial funding in GIAs they were a party to prior to the interim period … does not, by itself, support a finding that such transmission owners should be barred from electing transmission owner initial funding on an ongoing basis,” FERC wrote.

AWEA also argued that FERC strayed from its usual mode of “preserving the sanctity of contracts.” It said the commission “has previously only departed from that precedent in extreme circumstances, such as fundamental industry restructuring and reorganization of a bankrupt utility.” The association contended that TOs shouldn’t be allowed to self-fund upgrades under multiparty facilities construction agreements because MISO’s original compliance filing didn’t mention such agreements.

FERC disagreed, noting that prior orders found that MISO’s facilities construction agreements and multiparty facilities construction agreements should be treated like GIAs.

Glick said the commission’s order didn’t “meaningfully” address AWEA’s concerns about the possible discrimination of some interconnection customers.

“Today’s order … doubles down on the unwise decision to permit the reopening of numerous previously negotiated interconnection agreements, despite considerable evidence that allowing transmission owners and affected-system operators to retroactively elect to self-fund the network upgrades associated with those agreements will result in substantial harm to interconnection customers and could lead to project terminations,” he wrote.

AWEA also argued that resource owners may have already started depreciating network upgrade investments in their books. FERC said that since 2015, generation owners have been put on notice that TO self-funding could again become a possibility.

Glick said that FERC stumbled by simply reversing its 2015 decision after the D.C. Circuit’s remand. He pointed out that the commission five years ago found that allowing TOs to unilaterally elect to fund upgrades could deny interconnection customers the “opportunity to finance network upgrades with more favorable rates and terms.”

He also said FERC’s decision to treat GIAs, facilities construction agreements and multiparty facilities construction agreements similarly was done without “any additional analysis or meaningful response to arguments raised by protesters.”