ITC Holdings said last week it’s looking for utilities to buy capacity on the Lake Erie Connector, an underwater 345-kV HVDC transmission line that will transmit 1,000 MW of power back and forth between Ontario and Pennsylvania.
The “shovel ready” project has cleared the last of its permits, ITC Chief Operating Officer Jon Jipping told RTO Insider on Friday, and the company now hopes the five-year investment of time and money spent jumping through regulatory hurdles in the U.S. and Canada will pay off.
“We had a really big plan and gave ourselves enough time,” he said of ITC’s progress since acquiring the project in 2014. “The connection of these two markets is going to bring some real savings.”
Lake Erie Power Corp. first conceived of the project in 2013 as a solution to the Ontario Independent Electricity System Operator’s excess power and congested transmission lines and PJM’s growing demand for emissions-free generation. (See Merchant Transco Plans 1,000 MW Line into PJM.)
The Lake Erie Connector Project will use HVDC technology to transmit 1,000 MW of power between Ontario and Pennsylvania. | ITC Holdings
Jipping said Ontario’s renewables penetration could help PJM states meet their clean energy targets, while Pennsylvania’s vast reserves of shale gas could provide lower-cost energy to the Canadian province.
“We took a strategic and tactical view of the project to go and get the permits, spend the money and get the land rights because we really felt it lent a lot more credibility to what is a very unique project,” he said. “It’s two countries, it’s connecting new markets, going across a big lake.”
The project mirrors other underwater transmission lines in France and Spain, Jipping said, and carries lower risk thanks to the progression of HVDC technology. Still, he said the construction — which will take upward of three years — isn’t without challenges.
“I don’t want to say it’s easy, but it’s fairly straightforward,” he said. “Lake Erie is not very deep. It’s much less challenging, technologically, compared to the offshore wind projects in New Jersey.” (See Orsted Wins Record Offshore Wind Bid in NJ.)
PJM’s most recent generation interconnection facility study estimates network upgrades for the project will cost $4.7 million with an in-service date of March 31, 2024. The 73-mile bidirectional line will traverse underneath Lake Erie to connect a retired 4,000-MW coal plant in Nanticoke, Ontario, to a new converter station in Erie, Penn., which will eventually tie into Penelec’s existing Erie West substation. Neither the RTO nor the utility had anything to say about the project at this phase.
RTO Insider reached out to Erie County Executive Kathy Dahlkemper to discuss her dealings with ITC throughout the permitting process. Although she was unavailable for comment, Dahlkemper told Buffalo’s NPR affiliate in 2017 that she didn’t expect the project to cause problems in the community where ITC planned to build the new convertor station.
“You have to understand that this is coming into Erie County in probably one of the least populated areas, particularly along the lake,” she told WBFO. “So the impact to where people live to their property is actually fairly minimal because of where they are coming in to our county.”
Jipping told RTO Insider on Friday that early concerns from Erie residents about property values and water contamination were allayed through public meetings and slight changes to the developer’s initial construction plans. He said company representatives will return to the local townships once construction begins to answer more questions.
“We were able to explain what we were doing and were able pick routes that were minimally impacting the community,” he said. “We had to buy a little more property than we wanted and do some route changes, but that’s pretty normal for us.”
Pacific Gas and Electric restored power to 738,000 customers across central and Northern California over the weekend after its public safety power shutoffs (PSPS) and failed communications prompted a backlash from the public, state regulators and elected officials.
California Gov. Gavin Newsom backtracked on his earlier statements that the shutoffs were an appropriate means to prevent wildfires and said during a news conference last week that PG&E’s neglect of its power lines had led to the massive intentional blackout of more than 2 million residents.
“This is not, from my perspective, a climate change story as much as a story about greed and mismanagement over the course of decades,” the governor said Thursday during a press conference at the state’s Office of Emergency Services near Sacramento.
PG&E said it restored power to 738,000 customers it had blacked out to prevent wildfires. | PG&E
Responding to criticism in his own news conference, PG&E Corp. CEO Bill Johnson acknowledged mistakes. The utility’s website had crashed, its phone lines were overloaded and its shutoff maps were inconsistent if not incorrect, he said.
“To put it simply, we were not adequately prepared to support the operational event,” Johnson said.
The CEO said the utility decided to shut off power in 34 counties based on its weather predictions but did not have the “granularity” needed to limit shutoffs to areas where they were most needed. He vowed the company would do better next time.
PG&E instituted the blackouts as part of its effort to prevent the type of deadly and destructive fires that its equipment sparked during similar windy fall weather conditions in 2017/18. Those fires included the Camp Fire, which killed 86 people and destroyed much of the town of Paradise in November 2018.
At least one fire flared up last week near the San Francisco Bay Area community of Moraga but was quickly contained. No major wildfires occurred in Northern California during the blackout.
CPUC Responds
The PSPS was included in the wildfire mitigation plan PG&E filed with the California Public Utilities Commission earlier this year. The commission approved PG&E’s plan in May. (See California Regulators OK Utility Wildfire Plans.)
That did not stop the CPUC from slamming PG&E at its voting meeting Thursday in San Francisco. In that meeting, new commission President Marybel Batjer said PG&E’s actions were unsupportable. (See Calif. Regulators Bash PG&E Power Shutoffs.)
CPUC President Marybel Batjer | State of California
“The management and the response of the company, PG&E, to the [PSPS] have been absolutely unacceptable,” Batjer said. “The impacts to individual communities, to individual people, to the commerce of our state, to the safety of our people has been less than exemplary.
“This cannot be the new normal,” she said. “We can’t accept it as the new normal, and we won’t.”
She called for a review of the public policies that led to by far the largest blackout to prevent wildfires ever to hit the state.
Commissioner Genevieve Shiroma suggested the massive shutoff wouldn’t have been necessary if PG&E had maintained and upgraded its infrastructure to prevent fires.
“The sheer magnitude [of PG&E’s PSPS] is indicative of the condition of the utility in terms of what we call the hardening — that means the condition of the poles, the lines, the wires, the transformers, the transmission lines — and the maintenance, or lack thereof, of the system and the vegetation management,” Shiroma said.
The CPUC’s deputy executive director for safety, Elizaveta Malashenko, told commission that the shutoffs affected about 2,400 miles of transmission lines and 24,000 miles of distribution lines. CAISO had been working to contain the shutoffs so that they didn’t spill over into neighboring areas, she said.
The state had tried to help PG&E keep its website and servers working, soliciting help from the likes of Microsoft and other tech companies, she said.
Southern California Response
Several wildfires did occur in Southern California as hot dry Santa Ana winds blew late last week. The largest of the blazes was the Saddleridge Fire, which burned nearly 8,000 acres above the San Fernando Valley, forcing widespread evacuations.
Residents told several news outlets they’d seen flames beneath a Southern California Edison transmission tower Thursday night as the fire started, but those reports have yet to be confirmed by fire officials or SCE.
SCE had shut off power to thousands of its customers in the greater Los Angeles area to prevent fires, but a spokeswoman told the Los Angeles Times that the transmission line in question had not been de-energized.
All but four SCE customers had power as of Monday, the company said on its website.
Firefighters continued to make progress on the Saddleridge Fire, which was about 43% contained as of Monday morning, according to the California Department of Forestry and Fire Protection. Cal Fire said the blaze had caused at least one death.
BURLINGTON, Vt. — More than 300 people last week attended the annual Renewable Energy Vermont conference, where state officials, renewable energy advocates and a Vermont congressman described their efforts to combat climate change while calling for even more measures.
REV Executive Director Olivia Campbell Andersen asked state officials what action has had the most impact on their work to transition to a clean energy economy.
Vermont Department of Public Service Commissioner June Tierney highlighted the increase in media coverage of renewable energy, which has helped drive legislative engagement.
“Our legislature is really engaged now, which really makes a difference,” Tierney said. “Kudos to Connecticut and New York for leading. … I’m not so concerned about being in the vanguard, but of bringing people along.
“We have been leaders in Vermont. … When we adopted a renewable energy standard in 2015, it was the finest in its time,” she said. “But the most impactful thing has been the regulator’s mind, and the degree to which the regulator has been open to these changes.”
She said more is demanded of regulators in a small state like Vermont, where the legislature has invested the responsibilities for planning, envisioning and economic regulation in the DPS.
Rep. Peter Welch (D-Vt.) said, “Tax credits make a huge difference at the beginning of a technology,” adding that the House of Representatives “may be able to do something on the electric vehicle front by extending the tax credit.”
Welch is a member of the bipartisan Advanced Energy Storage Caucus in Congress and co-sponsor of the Energy Storage Tax Incentive and Deployment Act (H.R.2096), which would establish an investment tax credit for energy storage.
The caucus is focused on integrating renewables into the grid, increasing electrification of heating and transportation, and improving energy efficiency, he said.
“Whether the existing investment [EV] tax credits we have now will be extended or not, we don’t know yet, but my experience has been that there is hugely bipartisan support to extend,” Welch said. “The question is always when and how that’s going to get done, and it usually gets done at the very end of the session, when there’s an overall omnibus budget bill and tax agreement. … My prediction is they will be extended.”
Vermont Lt. Gov. David Zuckerman said, “The Trump tax cuts supposedly offered about $500 million to Vermonters in savings in their federal taxes, but over $300 million is going to the top 10% of Vermonters. My guess is that most of that $300 million is probably not going to be spent in Vermont; it’s going to be sent to Wall Street.”
Zuckerman proposed instead to take half that money from wealthy residents and spend it on in-state programs such as weatherizing houses or expanding broadband access in rural areas.
“We do not have time for slow, incremental change,” Zuckerman said.
Burlington Mayor Miro Weinberger proposed imposing a statewide carbon pollution fee in Vermont to help cut carbon dioxide emissions 37% by 2040, calling it “perhaps the most critical thing we can do to address the climate emergency, and that would create a transformative tailwind that pushes into all of our other efforts to decrease carbon emissions.”
Weinberger said the carbon charge would not be a tax, but a “revenue-neutral carbon fee,” as “money collected by the state would be rebated back to Vermont households and businesses and keep those resources working in the economy.”
Regional Reflections
Peter Olmsted, chief of staff at the New York Energy Research and Development Authority, said his state started its clean energy revolution a decade ago as it sought “to understand how the utility business model was going to evolve and respond to the needs of consumers, the need to respond to climate.”
However, understanding the necessary changes to regulators’ thinking has been “the bigger challenge for us, whether it be a matter of prioritization of issues, capacity and resources, [or] an asymmetry of information between the regulator and the regulated,” Olmsted said.
Regarding reliability, Olmsted said that “80% of our transmission lines were put in service before 1980, and over the next 10 years, the investment to upgrade those is going to be on the order of $30 billion.”
New York needs to reconcile aging infrastructure with plans to develop “a significant amount of renewable energy and clean energy resources on the grid simultaneously… so energy storage we believe is a key ingredient in that,” he said.
The interconnection “queue for NYISO has just exploded,” Olmsted said. “We were at 200 MW in the queue in 2018 when we commenced our energy storage roadmap process, and we’re now seeing upwards of 5,500 MW in our queue, so we know the demand and the interest is there.”
“We’re trying to enable an economy-wide decarbonization, which mirrors the executive order seeking 100% zero carbon by 2040,” Gillett said. “We’re also working to make a resilient, reliable and secure electricity commodity supporting growth in the green economy.”
The cornerstone of the state’s grid modernization proceeding is affordability, not only for residential customers, but also for commercial and industrial ones, she said.
RMI View
Jules Kortenhorst, CEO of the Rocky Mountain Institute, said, “We were a think tank, but the time for thinking is over. We are facing a climate crisis and the clock is ticking.
“The accelerating pace of an energy transition may become the wind in our sails, just when we need it most,” he said in comparing two contrasting views of the transition, one that thinks it best to go slow and the other that says the planet is on an exponential curve for warming.
Kortenhorst finds hope in the seemingly most mundane area of efficiency: “boring old building codes.”
“If we don’t get our buildings to near net-zero emissions, there is no way we’re going to reach our climate goals,” he said.
He also highlighted that solar is in many places of the world already the most cost-effective way to produce electricity, and 90% of natural gas projects in the country are now beaten economically by wind and solar.
“And it’s a global trend … in the buildup to the Paris [Agreement on climate change], India said it would build half coal and half solar. … Now they see the economic benefit of leapfrogging,” he said.
“As we are starting to deploy batteries to stabilize our electricity grid and to make solar available at the end of the afternoon when the sun is setting, we are driving down the cost such that electric cars become cheaper, at which point Ford, GM and Chrysler see that the future is electric, which drives costs down even further, which makes it easier to store the solar energy in batteries for our grid,” Kortenhorst said.
“These feedback loops are starting to build on themselves, and we see a dramatic shift in the way in which people are starting to understand that if we weave a complex of web of renewable energy solutions, we will be able to shift to a low-carbon energy future much faster and much more cost-effectively.”
Vermont imports four times as much energy as it produces within the state, and the largest utility, Green Mountain Power, “is highly dependent on imports from [Canadian] hydropower and nuclear power from Millstone and Seabrook, [which] are long distances away, as is most of the hydropower,” said Kim Hayden, who leads the energy and environment practice group at the Burlington-based law firm of Paul Frank + Collins.
“Seabrook and Millstone are among the two most vulnerable nuclear units in the country subject to inundation, based on [studies that took] a lot of time and effort by the Nuclear Regulatory Commission after Fukushima,” Hayden said. She noted that one study resulted in NRC adopting a rule (84 FR 39684) requiring owners of coastal plants to modify their infrastructure “to withstand the levels that are now expected from storm surges and severe inundation.”
Hayden called for better planning, such as fixing the transmission constraints associated with the Sheffield-Highgate Export Interface (SHEI), which prevents the development of new renewable energy resources in northern Vermont. She also said the state should increase its renewable energy standard.
Rebecca Towne, CEO of the Vermont Electric Cooperative, agreed with Hayden’s concerns about long-distance imports, saying that utilities would ideally like to pair load and generation in the same location — and hopefully synchronize the periods of demand and output.
“Vermont is not a very big state, and so it doesn’t take a very far transmission line to get out of state … and anything that goes by transmission line, by nature, whether it’s in-state or out-of-state, is not paired generation and load,” Towne said.
“So the SHEI challenge is too much renewable generation in the northern part of Vermont, versus the load,” she said. “The problem we run into is the location and timing of all that generation and the load is mismatched. The real way to fix that is to go with more transmission lines, but that doesn’t really make any sense, mostly because our load is going down.”
Storage has the unique characteristic of being either load or generation, depending on when it’s needed, said Chris McKay, director of sales for battery energy storage solutions at WEG Electric in Barre, Vt.
“That ultimate dial or control is something you can do with a battery that the utilities and other planners are trying to create through other means, with controllable loads and dispatchable generation,” McKay said.
PJM will pay two trading firms $12.5 million to end a dispute over the 890 million MWh GreenHat Energy default under a settlement agreement filed with FERC on Thursday.
Apogee Energy Trading and Boston Energy Trading and Marketing (BETM) will accept credits of $5 million and $7.5 million, respectively, to resolve the firms’ claims of economic harm that resulted from PJM’s decision to not liquidate GreenHat’s entire portfolio of financial transmission rights during the 2018/19 planning period (ER18-2068). After the company defaulted in June 2018, PJM reran only the July FTR auction — a decision the RTO says kept costs to members down and avoided a cascade of market violations that would increase uncertainty for years to come.
“Those payments are integral to an overall package that allows payors in PJM to avoid the risk of the additional default allocation assessments that might result if the proceeding were litigated to conclusion,” the RTO’s attorneys wrote in the settlement. “PJM and many settling parties also attach considerable value to the settlement’s removal of a cloud over the July auction and subsequent FTR auctions in the same planning period, and in avoiding the possibility of disruption to such auction results.”
Apogee and BETM had opposed PJM’s request to waive existing rules to settle the remainder of GreenHat’s portfolio. PJM sought the waiver to reduce the impact on the monthly FTR auctions throughout the rest of the year. After FERC denied the request, the firms protested the RTO’s subsequent motions for rehearing and clarification.
Throughout discussions, PJM and the two firms disagreed over how much economic harm the original auction results caused. In the agreement filed Thursday, the RTO said the payments serve as a proxy for rerunning the July auction.
“When sophisticated parties reach such a settlement, the resulting compromise value can be expected to reflect the parties’ efforts to protect their respective interests, based on their separate assessments of adverse litigation outcomes, the cost of litigation, impacts on market viability and the value of preserving settled market outcomes,” PJM wrote. “Such is the case here. Rather than engage in complex and extended litigation about each method, practice and assumption that might be used to rerun or resettle the July auction, Apogee, BETM and the payor settling parties explored whether they could reach agreement on payment levels, informed by the differing estimates of economic harm by PJM and Apogee, and by PJM and BETM.”
In addition to Apogee and BETM, the settling parties were American Electric Power Service Corp., American Municipal Power, Buckeye Power, DC Energy, Direct Energy Business, Direct Energy Business Marketing, Dominion Energy Services, Duke Energy Kentucky, Duke Energy Ohio, East Kentucky Power Cooperative, EDF Trading North America, EDF Energy Services, EDP Renewables North America, Elliott Bay Energy Trading, Exelon, FirstEnergy Service Co., LS Power Associates, Mercuria Energy America, Mercuria SJAK Trading, NextEra Energy Marketing, NRG Power Marketing, the PJM Industrial Customer Coalition, the PSEG Companies and Southern Maryland Electric Cooperative.
Although PJM did not describe the settlement as uncontested, it said “none of the settling parties shall seek rehearing of an order approving or accepting this settlement without modification or condition.” The other settlers aren’t asking for money because they believe they benefited from the way PJM ran the July 2018 auction and settled the remainder of GreenHat’s portfolio.
PJM members are funding the credits to Apogee and BETM through default allocation assessments. PJM said it will establish another $5 million fund for additional claimants, though it anticipates there won’t be any, based on the limited protest filings it received during the proceeding.
After receiving their credits, Apogee and BETM will be subjected to the same default allocation assessments that other members face. PJM spokesperson Jeff Shields told RTO Insider on Monday the default will cost members $177.5 million — substantially less than the cost of rerunning the July auction.
“The settlement is the product of intensive good faith negotiations among the participants to this proceeding,” he said. “It brings to a close open issues around the treatment of defaulted GreenHat portfolio. The settlement is supported by a broad array of stakeholders, there has been no indication that it is opposed by anyone, and it is in the public interest.”
PJM said it will rerun the July auction for the sole purpose of supporting the credit payments established in the settlement. The simulation will liquidate the entirety of GreenHat’s portfolio, which would impact FTR auctions in any month between September 2018 and May 2019. If any of the FTRs offered for liquidation would set price, then the simulated auction is rerun after removing 50% of the total defaulted FTR positions, regardless of path or period. PJM would waive all applicable Tariff rules concerning simultaneous feasibility test violations; prohibitions on selling FTRs not owned by an auction participant; FTR forfeitures; and requirements for participants to post additional credit based on tentative clearing results.
“The agreement not to apply the Tariff rules listed above is a key benefit of the ‘black box’ approach to settling this case,” the RTO’s attorneys wrote. “If PJM actually reran the auction, the referenced rules could cause cascading deviations from actual settlement results in other auctions conducted for the 2018/19 planning period, likely creating additional Tariff violations, further disrupting the market and undermining market participants’ faith in the finality of the FTR auctions.”
PJM asked FERC to waive both the reply comment period and the regulations necessary to effectuate the settlement. The RTO and the settling parties will answer questions on the deal in a meeting at FERC from 1 to 3 p.m. Oct. 17. The meeting will be available via teleconference (Phone: 800-375-2612; Meeting Access ID: 379441).
Bruce Rew, SPP’s senior vice president of operations, predicted a year ago that there was “a good chance” the RTO would reach the 70% barrier for renewable energy penetration.
Rew’s prognostication skills are not in doubt. The RTO tweeted last week that it met 73.67% of its demand Wednesday with wind, hydro and other non-fossil resources.
| SPP
The mark came at 2:14 a.m. CT, when SPP’s load was 22.5 GW. Renewable resources suppled 16.5 GW of that power, with wind supplying 65.4% and hydro 8.3%. The grid operator also set a record for wind generation on Sept. 30, when it produced 17,109 MW at 12:30 a.m. That broke the previous mark of 16,972 MW, set Sept. 11.
ERCOT, which has 22,313 MW of installed wind capacity, holds the RTO high for wind generation, set in January at 19,672 MW.
An important fall pastime, along with baseball playoffs, is to look back to see which electric market design model performed best over the summer. For the last several summers, a lot of eyes have been on the ERCOT market, given its relatively low reserve margins and lack of a mandatory forward capacity market. The results are in. There was no firm load shed because of supply shortages, and ERCOT’s 2019 Summer Operational and Market Review stated, “Overall, the market outcomes supported the reliability needs.” My colleagues and I at Grid Strategies ran the revenue adequacy numbers and found that prices did what they should, providing appropriately strong signals to attract new market entry while charging customers only for what they needed.
The key distinction between ERCOT and regions with a capacity market or resource adequacy requirement is that in ERCOT, responsibility for assessing the level of supply and demand need for investment lies with market participants, not the grid operator itself. Other regions are charging customers more than 20% of the total cost of energy, capacity and ancillary services through capacity markets. In contrast, ERCOT focuses on grid operations more like an air traffic controller, saving consumers that money. It uses spot energy and reserves prices to accurately value energy over time and at each location, and lets market participants handle their own price risk management and supply assurance through bilateral contracts. Spot energy values at times of scarcity are allowed to reach $9000/MWh — reflective of true consumer valuation of supply at that time and place — and the value of reserves, which is based on a downward sloping operating reserve demand curve. By keeping dollars in spot markets as opposed to a capacity market, this market design attracts flexibility from demand response, storage, hydro and any other source that delivers when it is needed. There are no drawn out subjective debates with RTO management and stakeholders about what resources should count how much toward the elusive concept of “capacity,” and what public policies should be mitigated, as is the case in the Northeast. (See our paper showing how the minimum offer price rule costs PJM consumers $5.7 billion extra per year.)
One would expect that when the system is low on capacity — as it was this summer with around an 8% reserve margin — prices would occasionally be very high and on average equal or exceed the amount that efficient new units need annually to recover their capital investment cost. In economic theory terms, in an efficient market at equilibrium, over the course of the year there would be enough “rent,” or profit earned from prices that exceed generators’ operating costs, that new generators see enough profit incentive to enter. So the question is, were prices over the last year high enough to attract and retain needed units? Our analysis below indicates the answer is YES.
Let’s take a look at the prices in 2019 so far (see our blog for data, assumptions and methodologies). The figure below uses ERCOT historical real-time ORDC data generated during each security-constrained economic dispatch interval to display the number of hours that prices have exceeded generators’ operating cost from January through September.
ERCOT price duration curve analysis (January to September) | ERCOT
As shown above, prices have been consistently higher this year than in previous years. So far, prices have already exceeded $200/MWh for 95 hours, with four hours and 10 minutes reaching the systemwide offer cap price. This September alone, with the most record-high temperature days since 2011, was responsible for 10 minutes worth of prices at the offer cap and 20 hours worth of prices above $200/MWh. For reference, 2018 saw 54 hours over $200/MWh and only 10 minutes at the offer cap. Since the creation of the ORDC in June 2014, ERCOT only saw prices hit the offer cap one other time in 2016 for five minutes.
So prices have been higher, but were they high enough to attract entry? To answer that question, we can look at net margin for different units. In Grid Strategies’ analysis of year-to-date data, efficient new peakers earned 35% above what they need to earn in an average year to pay for the capital cost of building the units, and combined cycle units earned 25% above that target. In most prior years when reserve margins were higher, they earned less than this target level.
Peaker net margin analysis | Potomac Economics
These high spot prices signal to retail electric providers to go out and sign more contracts with generators so they can shield themselves from high spot market prices in the future. Those long-term power purchase agreements are then used by prospective generators to finance their new plants. An influx of 4,000 MW of solar and 5,000 MW of wind plants expected by next summer will likely take care of much of this need. Market participants also have clear responsibility and incentives to seek sources that shield them from high prices when wind and solar output is low. The Public Utility Commission of Texas reviews those entities’ creditworthiness to make sure they are financially equipped to serve the load they commit to serve — an important and often forgotten regulatory responsibility of state commissions. Few customers actually had to pay the high spot prices, as they were covered by contracts signed well in advance, and the prices withstood the mild political opposition without regulatory intervention.
This year may have been the best test to date of the ERCOT market design. The results so far indicate that despite the hot summer and low reserve margin, no firm load was shed because of supply shortages, while the system did provide sufficient price signals to attract and retain needed resources. High spot prices did not attract political intervention, and consumers only paid for what they needed. ERCOT’s 2019 experience should answer a lot of questions about whether ERCOT’s unique market design works. One thing is for sure though: Our October pastime of reviewing the past summer’s power market results will come again as surely as the sun rises or the baseball playoffs begin.
Rob Gramlich is founder and president of Grid Strategies LLC, a clean energy grid consulting firm.
The latest salvo was Rocky Mountain Institute’s claim that the bulk of new natural gas generation is/will be uneconomic. As I said before, perhaps the advocates hope that if gas investment is scared off, then renewables and batteries become a fait accompli.
The first major flaw was that 40 to 50% of RMI’s “clean energy portfolio” (CEP) comes from demand response and energy efficiency. It assumed large amounts of those resources are available at low cost.
And, importantly, it assumed that these hypothetical low-cost resources were only available to its renewables/battery CEP portfolio and not to a gas portfolio. As a result, the economics that RMI attributed to its renewables/battery portfolio actually came from mixing in low-cost DR and EE that are not unique to that portfolio.
The second major flaw was that in its modeling, RMI used traditional fossil generation to recharge the batteries. Yes, ironically, traditional fossil generation was supplying a “clean energy portfolio.” And, most dramatically, in a last hour of covering peak load, the equivalent of a 1.5-GW gas generator was matched by: zero wind and a negligible amount of solar; batteries charged with traditional fossil generation; and huge amounts of DR and EE, neither of which are unique to a renewables/battery scenario. In other words, renewables contributed virtually nothing to matching the 1.5-GW gas generator.
RMI says investors are “taking notice,” pointing out that final investment decisions for new gas plants have declined since 2014. But at this level, they are the same as they were in 2010. Trend or cycle? And RMI is not correct that the capacity factor of combined cycle gas plants is declining; in fact, the article cited by RMI has a chart clearly showing the opposite.[efn_note]https://www.spglobal.com/marketintelligence/en/news-insights/trending/Pu5fAcJoqopojxYhGN0tMw2.[/efn_note]
Just as Energy Information Administration data show that the capacity factor of combined cycle gas plants is at a record[efn_note]EIA Electric Power Monthly, Table 6.7.A, for August 2019 and August 2014, available here, https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_a.[/efn_note] high:
Natural gas combined cycle average annual capacity factors | based on EIA data
Even if RMI were right about such things as capacity factors, none of it is really reflective of investor sentiment. The real indicators are things like the share price of NRG Energy — the best proxy for competitive fossil generation (about half of which is gas) — which is up from $11/share to $40/share in the last three years. And RMI’s own statement that there is “more than $100 billion in planned gas infrastructure investment through 2025.”
If gas is a bad investment, Wall Street didn’t get the memo. RMI may suggest its study is the memo, so that takes us back to the study itself.
RMI’s Reply on Assuming and Co-opting the Low-cost Resources
RMI’s aggressive assumption on lots of available DR and EE cannot be sustained by referring, as RMI does, to “definitive resource potential assessments” (my emphasis). Potential is just that.
But more important, RMI admits that it assumed the availability of (low-cost) DR and EE for its renewables/battery portfolio and not for its gas portfolio. It now says that’s OK because its study showed that DR and EE are “natural complements to zero-marginal-cost generation from wind and solar.”
I can’t find anything in the study that remotely supports that proposition. I can’t even find the words “complement” or “zero” in a word search. Please note that RMI saying in its study that it optimized resources in its modeling should not be confused with a showing that certain resources complement each other better than others.
Bottom line: The RMI study’s co-option of low-cost DR and EE resources for its CEP portfolio is a fundamental, unsupported flaw.
Low-cost Resources Threat to Gas?
RMI says that the implication of my critique is that inexpensive DR and EE are themselves a threat to gas investment. A clever thought. But too clever by half. It’s RMI, not me, that assumes vast availability of low-cost DR and EE.
And if DR and EE are a threat to gas, then they must be a bigger threat to more-expensive renewables. Is RMI warning Wall Street about renewable investment? No, I didn’t think so.
The CEP Dependency on Fossil Generation
RMI does not deny that in the last hours of peak conditions, fossil units are providing needed generation via batteries, and renewables are providing virtually nothing. RMI says that just reflects the leveraging of available fossil generation for the foreseeable future.
Fair enough I guess. So long as everyone understands that RMI’s modeling is not of a sustainable equilibrium condition. Instead, it depends on fossil generation sticking around so when solar and wind aren’t generating, the system can still serve load reliably. And as I’ve pointed out, if new gas generation is scared off, then the old fossil with much higher carbon emissions will be what carries the CEP portfolio.
Finally, RMI goes on to overplay its hand by claiming that nothing undermines its central finding “that CEPs can compete and win on gas plants’ own turf.” No. In its modeling, RMI’s CEP portfolio is undeniably dependent on fossil generation. RMI admits that. The converse is not true: A fossil fleet is dispatchable and is not dependent on renewables/batteries, as decades of reliability grid operation without renewables or batteries attest.
In the first 16 months after its creation in 2017, NERC’s Inverter-Based Resource Performance Task Force produced four disturbance reports, two alerts, several webinars and a reliability guideline. Its latest creation could be considered its Greatest Hits.
The task force began disseminating a 98-page inverter performance guideline a little over a year ago.
“Our recommendation to transmission owners is you need to be familiar with the guideline and incorporate what’s in [it] in your interconnection requirements,” Bauer said. “We got a lot of feedback from the industry, and they said, ‘What are the critical pieces in the performance guideline that we should include in our interconnection agreements?’ That’s really what spawned this latest guideline.”
Although many of the task force’s recommendations apply to balancing authorities, reliability coordinators or transmission operators, they are generally addressed to the TO, which is responsible for maintaining interconnection requirements under reliability standard FAC-001 and for conducting interconnection studies under FAC-002.
The new 52-page publication seeks to cover the growing number of inverter-based generator interconnections that fall between the distribution system and the bulk electric system (BES) threshold (capacity of 75 MVA and voltages of 100 kV) that is subject to NERC’s standards. The task force says “the vast majority of solar PV plants connected to the BPS [bulk power system], totaling over half the capacity, are not considered BES and are therefore not subject to NERC reliability standards.”
“Maybe it’s connected at less than 100 kV, but it’s more than 75 MVA. Maybe it connects at 69 or 92 kV. Or maybe it connects at greater than 100 kV, but it’s less than 75 MVA. Those are [what] I call the ‘tweener’ interconnections,” said Bauer, NERC’s associate director of reliability risk management.
“While each individual resource may not have a substantial impact to the BES, the overall response, behavior and control of these resources impact BPS reliability and stability,” the guideline says. “It is therefore critical to have consistency across the generating fleet.”
A growing number of inverter-based generator interconnections fall between the distribution system and the bulk electric system (BES) threshold (capacity of 75 MVA and voltages of 100 kV). | NERC Inverter-Based Resource Performance Task Force
If widely adopted, the guideline could act as a de facto standard. Although interconnections outside the BES definition are not directly subject to NERC standards, the task force realized it could still influence them indirectly: The guideline includes 18 recommendations for interconnection requirements and six for modeling.
The task force said the guidelines will serve as a “bridge” to the Institute of Electrical and Electronics Engineers’ P2800 effort to standardize the performance and capability of newly interconnecting BPS-connected inverter-based resources (IBRs). Completing the standard and getting it adopted by relevant authorities is expected to take about two years.
“A significant portion of [the 2018 performance guideline] looks a lot like an equipment specification, and NERC standards [have] never really delved into the area of providing equipment specifications,” Bauer said. “We recognized this fairly early on and … that’s what spawned this IEEE 2800 project.”
Unlike a NERC standard, which would cover legacy equipment, the new guideline is intended to apply only to new and “materially modified” interconnections involving IBRs. IBRs are not “brand-new” to the bulk system, said NERC’s Ryan Quint, citing wind farms installed since the 1980s.
The majority of solar PV resources are connected at voltage levels less than 100 kV and are sized at less than 75 MW in capacity, making them exempt from NERC reliability standards. | NERC Inverter-Based Resource Performance Task Force
“There is a lot of legacy equipment out there. Not all of that the legacy equipment can meet the recommended performance that we’re seeking today,” said Quint, senior manager of advanced analytics and modeling.
Grid operators need more granular data because of the growing penetration of IBRs, he said.
“Clarity and consistency [are] needed for inverter-based resources because their electrical response and behavior when they’re connected to the grid is dominated by controls rather than physics,” Quint said. “The inverters, the plant-level controllers, the communication — all the stuff that interacts to make the plant behave the way it does — is all based on a control system … that can be [programmed] to some extent to meet certain performance requirements and ensure reliability of the grid. … The goal is not to have expensive, overbearing requirements for inverter-based resources. It’s just to bring clarity to what the grid really needs.”
Monitoring
In producing reports on the August 2016 Blue Cut Fire, the October 2017 Canyon 2 fire, and the 2018 Angeles Forest and Palmdale Roost disturbances, the task force discovered that some of the IBR facilities “lacked the data we really needed to analyze those events in great detail,” Bauer said.
He said investigators need high-resolution, time-synchronized data. “We actually recommend where we would take measurements at. Of course, we would want a measurement at the point of interconnection, but there’s also a really big need to see data down in the plant … down at the individual inverter level.”
Weak Grid
Bauer said a recent incident in the U.K. has highlighted the need to understand how inverters affect the grid’s short-circuit strength.
The U.K. grid lost 800 MW of generation, shedding load to 1 million customers, after the voltage-regulating control on a very large wind facility became unstable.
“Make sure you study all potential configurations on your system to ensure that you can’t end up in a weak grid situation, because that’s in essence what happened in the U.K.,” Bauer said. “They had some planned maintenance outages, which put them in a weak grid situation … and that’s what caused their control to go unstable.”
“Weak grid” concerns are on the mind of engineers in New England, ISO-NE associate engineer Brad Marszalkowski said. “Lately we’ve been doing [electromagnetic transient modeling] for every interconnection request because they’re all inverter-based resources,” he told the webinar. “We see a lot of these weak grid issues.”
Be Proactive
Jeff Billo, ERCOT’s senior manager of transmission planning and the task force’s vice chair, also offered some lessons learned during the webinar.
ERCOT, which has 22 GW of wind and almost 2 GW of utility-scale solar, could add another 10 GW of wind and about 4 GW of solar in the next 15 months, if all the signed interconnection agreements backed with financial security postings come to fruition.
ERCOT, which has 22 GW of wind and almost 2 GW of utility-scale solar, could add another 10 GW of wind and about 4 GW of solar in the next 15 months, if all the signed interconnection agreements backed with financial security postings come to fruition. | ERCOT
The Texas grid operator recently created a new task force in response to interconnection requests for “multi-hundred-megawatt” batteries, Billo said. (See “TAC Approves Task Force to Study Battery Energy Storage,” ERCOT Technical Advisory Comm. Briefs: Sept. 25, 2019.)
Billo cited Texas’ IBR growth “to emphasize how important the work is at IRPTF to ERCOT and why we’re taking this as seriously as we are.”
ERCOT has banned IBRs from using momentary cessation since 2015, he said. “However, we were surprised when we got the survey responses back from the second NERC alert last year. There were some of the newer solar resources that were using that momentary cessation. We’ve identified that we need to clarify our requirements.
“We don’t want to wait until we start seeing problems on our grid before we start to implement some of these requirements,” he continued. “We’ve found it’s really important to be proactive in getting the requirements out, because once you have a problem on your system, it’s really too late. It’s near impossible to go back and retrofit the equipment that’s already in the field.”
California officials on Monday continued to heap criticism on Pacific Gas and Electric for initiating a massive blackout across much of its territory last week, with the state’s top regulator ordering “immediate corrective actions” to the company’s policies and Gov. Gavin Newsom calling for refunds to the 738,000 customers affected.
In a letter to PG&E CEO Bill Johnson, California Public Utilities Commission President Marybel Batjer condemned the utility for “failures in execution” during the largest public safety power shutoff (PSPS) in the state’s history, while directing the company’s top executives and board members to attend an emergency meeting Friday to share what they learned from the controversial shutoff and how they plan avoid a repeat.
“It is critical that PG&E, along with all the other utilities in the state, learn from this event and take steps now to ensure mistakes and operational gaps are not repeated,” Batjer said.
Batjer’s letter followed her harsh comments during last week’s CPUC voting meeting, saying PG&E’s “absolutely unacceptable” measures cannot become the “new normal” for the state. (See PG&E Restores Power amid Backlash.)
PG&E has said it recorded about 50 instances of damage to its equipment in areas affected by last week’s PSPS, including these downed lines in Shasta County. | PG&E
The tone of the Oct. 14 letter was more conciliatory, with Batjer commending the cooperation and transparency of PG&E staff who “worked to overcome challenges” during the event. But she also called out PG&E on several shortcomings, including its failure to heed recommendations from state and local agencies, which contributed to a critical breakdown of public communication and coordination. Those recommendations included establishing a communication structure that allows emergency personnel to receive information outside general updates to local governments, developing lists of critical facilities with county and tribal governments, identifying critical fuel-supply needs and coordinating with local governments to select PSPS-specific community resource centers.
Batjer pointed to the performance of PG&E’s website — a “cornerstone” of the company’s public information effort, which crashed within 24 hours of the PSPS declaration. That left PG&E staff struggling “to provide necessary information to their customers, the public and frontline safety officials with affected state, county and tribal governments.”
Batjer also faulted PG&E for failing to scale its operations to meet the increased customer inquiries precipitated by the event. In response, she ordered the company to identify the maximum outage that could occur during a PSPS and ensure “commensurate bandwidth requirements” for web and call services to be available at all times.
Other corrective actions required by the CPUC include:
Accelerating the restoration of power, with a goal of less than 12 hours — similar to the requirement after major storms;
Taking steps to minimize the magnitude of future PSPS events;
Establishing a more effective communication structure with county and tribal government emergency management personnel;
Improving processes and systems for distributing maps to counties and tribal governments showing the boundaries of the most recent PSPS-affected areas;
Developing a list of existing and possible future agreements for on-call resources that can be called upon in an emergency;
Ensuring PG&E personnel involved in PSPS response in emergency operations centers are trained in California’s Standardized Emergency Management System.
‘Right Decision’
In a letter to Batjer Monday, Gov. Newsom lauded the CPUC for its “swift response” to his request for an immediate “comprehensive inquiry” into the PG&E’s blackout event.
But a separate letter to PG&E Corp. CEO Bill Johnson had sharper words, with the governor castigating the company over the “unacceptable scope and duration” of the outages, which he said were “the direct result of PG&E prioritizing profit over public safety, mismanagement, inadequate investment in fire safety and fire prevention measures and neglect of critical infrastructure.”
Newsom also echoed Batjer’s criticism of PG&E for its failure to heed the recommendations of public agencies in executing its PSPS measures.
“PG&E’s lack of preparation and poor performance is particularly alarming given that, prior to the event, top executives responded to the scrutiny and questioning of state and local agencies by asserting that PG&E could handle a public safety power shutoff event,” Newsom wrote. “And PG&E turned down recommendations and offers of assistance from public agencies that are experts in crisis management, including the Governor’s Office of Emergency Services [OES].”
Newsom urged Johnson to have PG&E refund $100 to each residential customer affected by the blackout and $250 to each small business customer.
“This refund should be funded by shareholders, not ratepayers,” Newsom said.
Johnson defended PG&E’s actions, saying the company “closely” coordinated its activities with the CPUC, OES and the California Department of Forestry and Fire Protection before and during the event.
“Representatives from those agencies were embedded in our Emergency Operations Center and we welcomed and accepted their help and counsel, and PG&E employees were also embedded at Cal OES in Sacramento,” Johnson said in a statement. “We also worked closely with county and local officials throughout the PSPS.”
But he also acknowledged there were “areas” where PG&E “fell short of its commitment to serving our customers during this unprecedented event,” specifically in its customer communications.
Still, Johnson pointed to what he considered a key — and positive — outcome of the PSPS: that no fires were sparked in PG&E’s territory. The company has said it recorded about 50 instances of weather-related damage to its equipment in PSPS-impacted areas, including downed lines and vegetation making contact with wires.
“We appreciate the significant impact that turning off power for safety has on our customers and the state. While we recognize this was a hardship for millions of people throughout Northern and Central California, we made that decision to keep customers and communities safe,” Johnson said. “That was the right decision.”
CARMEL, Ind. — MISO is planning a spring filing with FERC to implement a payment structure for resources that re-energize islanded areas of the grid following a blackout.
“It’s interesting to stand up here and talk about something that we hope never happens. But we do see value in having a process,” Director of Settlements Laura Rauch told stakeholders at Thursday’s meeting of the Market Subcommittee.
MISO’s preliminary proposal stipulates that, as a starting point for pricing, compensation for restoration energy will rely on resources’ last submitted offers before an emergency strikes, resulting in unique costs based on each resource rather than a uniform clearing price. The RTO will allow for recovery of start-up costs, emergency purchases and resource-specific energy costs. It will also include recovery for any unusual costs incurred during operation, provided they can be verified by the Independent Market Monitor. The RTO will also accept after-the-fact updates of offers.
Restoration pricing differs from MISO’s existing black start services definition because black start resources derive their revenues from the capacity they provide, not the energy market.
Rauch said restoration events will be considered over when the day-ahead market once again takes over economic dispatch of resources in the islanded area.
“We’ll need to define the area of impact and the island,” she added.
Rauch said MISO realizes load and generation totals during a restoration event “may be imbalanced” but said total generation costs will be allocated on a load-ratio share. The RTO had originally considered allocating resource costs based on local balancing authority boundaries, but this summer it said load ratio would be simpler to implement.
RTO officials have also said a fixed-price compensation approach for restoration energy would be a blunt instrument that would at times result in under- or over-collection by generators.
“The downside is that it’s much more complex,” MISO Director of Market Services John Weissenborn said in June of a unit-by-unit pricing calculation and settlement based on offers.
MISO Preps Tariff for Short-term Reserves
Although MISO filed with FERC on Oct. 4 to include a short-term reserve product definition in its Tariff (ER20-42), stakeholders shouldn’t expect generators to fire up to furnish the reserves until late 2021.
The RTO asked that the commission act on its request by Jan. 31 but make the revisions effective Dec. 7, 2021, seeking a waiver of FERC’s 120-day maximum notice requirement to give its Monitor and stakeholders “adequate time to budget for in advance and develop and test significant software and other operational adjustments.”
MISO said it’s already begun working with tentative market platform replacement vendor General Electric on software design details.
The reserves are meant to supply energy within 30 minutes to meet reliability needs and reduce make-whole payments, and MISO expects them to be especially useful in portions of MISO South, where the RTO’s subregional transmission limit restricts imports.
MISO expects the short-term reserves product to clear $4 million in revenue annually when it goes live in 2021. It also estimates an approximate $5 million annual net production benefit when the reserves are used. Part of the savings will result from RTO operators taking fewer out-of-market actions, for which it must make revenue sufficiency guarantee payments. (See “Short-term Reserves,” Stakeholders Confused over MISO Roadmap.)
