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November 5, 2024

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Renewables Highlight 2021 PJM RTEP Report

PJM saw interconnection requests for solar generation more than triple since 2019, now making up more than half the interconnection queue, according to the 2021 Regional Transmission Expansion Plan (RTEP) report released Tuesday.

The annual report highlighting transmission projects approved last year by the PJM Board of Managers features several trends, including the continuing shift in the RTO’s generation mix driven by new natural gas-fired plants, the deactivation of coal-fired plants and the increasing volume of renewable generation.

PJM processed 1,351 new service requests in 2021, nearly triple the 476 requests made in 2018. The new service requests totaled 104,316 MW of nameplate capacity in 2021.

A total of 139,937 MW of generation interconnection requests was actively studied by PJM last year, a number nearly equal to the RTO’s all-time winter peak of 143,295 MW set on Feb. 20, 2015.

On the renewable energy front, solar generation currently makes up 58% of the interconnection queue, a total of 94,000 MW of the 160,000 MW of resources in the queue. In the 2019 RTEP, solar requests stood at 47% of the 75,432 MW in the queue.

“Previously, solar projects were smaller in size and limited to a handful of areas,” the report said. “Now, individual projects can reach hundreds of megawatts, driven by states’ renewable portfolio standards goals, and are seeking interconnection in every PJM transmission zone.”

Project Numbers

The PJM board approved a total of $920 million among 118 baseline transmission projects in 2021.

Total approved RTEP projects (PJM) Content.jpgTotal approved RTEP projects by the PJM Board of Managers as of Dec. 31, 2021. | PJM

Of the projects, 52% ($478 million) of them were driven by transmission owner criteria, 25% ($229 million) by PJM and NERC criteria and 23% ($213 million) by 52 generator deactivations or retirements.

PJM noted that large-scale transmission projects above 345 kV remain “uncommon” in the RTO, as load growth fell below 1% to a normalized 10-year RTO summer peak growth rate of 0.6%. The average 10-year-annualized summer growth rates for individual PJM zones ranged from -0.5% to 1.5%.

“Load forecasts from the past five years reflect broader trends in the U.S. economy and PJM model refinements to capture evolving customer behaviors,” PJM said in its report. “These include more efficient manufacturing equipment and home appliances and distributed energy resources, such as behind-the-meter, rooftop solar installations.”

PJM said the projects approved in 2021 responded to “diverse needs” such as upgrades and replacement of aging equipment and facilities to meet reliability and resilience criteria, the “minimization” of system congestion for market efficiency, localized reliability needs and generator deactivations.

In preparation for new generation resources coming onto the grid, the board also approved 34 network system enhancement projects totaling more than $47 million. The board has approved network facility reinforcements totaling more than $6.5 billion since the inception of the RTEP process in 1997.

Offshore Wind

With the growing number of offshore wind projects coming into the interconnection queue, PJM said the injection of thousands of megawatts of power will change how power flows across the grid in the Northeast and Mid-Atlantic. PJM said “efficiently harnessing” the new power source is going to require extending the existing transmission grid to offshore generation sources and deliver their energy to load centers along the East Coast.

Maryland, New Jersey and Virginia have established offshore wind targets totaling 14,723 MW with planned in-service dates of 2035.

In 2021, PJM planned for the offshore wind transmission expansion, partnering with NYISO and ISO-NE with the goal of achieving 30 GW of operational offshore wind by 2030. The RTO also worked with New Jersey under the “state agreement” approach to help identify the most efficient and economic solutions to accommodate offshore wind.

“Although offshore wind is on a longer planning horizon, the potential for development is substantial,” PJM said in the report. “Future system enhancements will solve the challenges that these locationally constrained resources present. Moreover, they will also address the interregional implications associated with wind lease areas that can also serve adjoining systems north and south of PJM’s RTO borders.”

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IEEFA: Blue Hydrogen not Clean nor Competitive

The private, nonprofit Institute for Energy Economics and Financial Analysis (IEEFA) argues that “blue” hydrogen, produced using natural gas, cannot be environmentally friendly or affordable.

In a report completed in February and discussed in a webinar Thursday, IEEFA analysts bluntly rejected the entire Department of Energy initiative to create regional hydrogen hubs producing and using blue hydrogen as a costly technological blunder based on “flimsy economic and environmental footing.”

Blue hydrogen production starts with high-temperature steam reforming of methane (CH4), splitting the hydrogen atoms from the carbon atoms. The resulting carbon dioxide is simultaneously captured and sequestered.

Gray hydrogen, in which the carbon split from the methane is not captured, has been produced for years as an industrial gas, frequently used in oil refining. It is significantly less expensive than green hydrogen, produced by electrolysis of water using renewable energy. Thus, blue hydrogen has been advocated by an avalanche of DOE and industry webinars and reports as a more environmentally friendly compromise.

But IEEFA is sharply critical of that argument. Because blue hydrogen is made from natural gas (which is 77% methane), any analysis of its environmental integrity must account for drilling, fracking and leakage at the well head and pipelines. Though methane only lasts about 12 years in the atmosphere, it is 25 times more effective at trapping heat than carbon dioxide.

IEEFA analyst David Schlissel said a major problem in making blue hydrogen as clean as green hydrogen is that at least 90% of the resulting carbon dioxide would have to be captured.

“Capturing 90% or more of the CO2 produced at a project is the holy grail for CCS [carbon capture and sequestration]. Proponents of blue hydrogen will say outright, or will more likely suggest or imply, that 90% carbon capture has been proven or demonstrated at existing projects.

“But this is not true. No commercial-scale project has captured 90% or more of the CO2 produced by the project over the medium or long term, by which I mean years and decades, which they will have to do if carbon capture and sequestration will be an effective tool for reducing CO2 emissions and concentrations,” he said.

“Achieving this goal sporadically clearly is not enough. Blue hydrogen combines the worst of two worlds. It uses fossil fuels and an unproven carbon-capture technology. What could possibly go wrong?”

Blue hydrogen’s reliance on CCS means it has “has very weak economic prospects,” IEEFA analyst Suzanne Mattei said. And sequestering carbon deep underground is another expensive technology that has not been proven to be economically viable, Schlissel said.

Mattei added another problem blue hydrogen producers will face: The cleaned-up gas is not as attractive to many corporate buyers as green hydrogen will be.

“The blue hydrogen projects are of limited value to investors who are looking to up their green credentials. Because they are pulling this fuel out of the ground, sending it through pipelines; and the leakage problems are significant, rampant really,” she said.

Proponents have asserted that they will use responsibly sourced natural gas, she said. But “a major theme of our report is that you have to look at the real-world experience … that the Environmental Protection Agency has been trying to control methane from drilling and pipeline transport for a long time,” she said.

EPA is currently trying to develop a new regulatory process, she added. If the agency is successful in forcing the gas industry to address the problem, the cost of gas will increase, she said.

Blue hydrogen “is both an environmental issue and an economic issue,” she said. “Not every invention makes it into the mainstream. And blue hydrogen has been trying to get into the mainstream for a long time; it’s just not happening.”

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Solar Growth Expected to Slow from Supply Chain Challenges, Rising Prices

Supply chain delays and rising prices could cut U.S. solar market growth this year by almost 20% below prior projections, but demand remains strong and the petroleum price shocks caused by Russia’s invasion of Ukraine could help drive an industry recovery in 2023, said Michelle Davis, a principal analyst at Wood Mackenzie.

While the impacts of the war may not be felt immediately in domestic solar markets, Davis said, “increases in [natural] gas prices are only going to make solar more economic … even with solar price increases of the last year.”

“The big challenge for the solar industry right now is resolving those supply chain constraints and trying to tackle various policy and trade issues,” said Davis, lead author of the Solar Market Insight 2021 Year in Review report released Thursday by Wood Mackenzie and the Solar Energy Industries Association (SEIA).

“There is more demand than current supply, which is why we expect long-term for the prospects for the market to be very strong and for recovery to begin, starting next year,” she said in an interview with NetZero Insider.

Similarly, SEIA CEO Abigail Ross Hopper stressed the key role solar can play in U.S. energy security. “In the face of global supply uncertainty, we must ramp up clean energy production and eliminate our reliance on hostile nations for our energy needs … and our nation will be safer because of it,” Hopper said.

With Democrats and Republicans in Congress calling for a major increase in U.S. fossil fuel production, Hopper said, “America’s energy independence relies on our ability to deploy solar, and the opportunity before us has never been more obvious or urgent.”

The report shows that the U.S. added a record 23.6 GWdc of solar in 2021 ― a 19% increase over 2020 ― even as prices for utility-scale fixed tilt projects rose 18%. For the third year in a row, solar added the highest proportion of new power generation on the U.S. grid ― 46% ― with panels added to more than 500,000 residential roofs, another all-time high, the report says.

Utility-scale solar was the primary driver for market growth, with 17 GWdc installed in 2021, but an uncertain pipeline lies ahead, the report says.

“About one-third of the capacity slated to come online during Q4 2021 was delayed by at least a quarter. For the 2022 pipeline, developers have postponed at least 8% and canceled at least 5% of planned capacity,” the report says

Even so, Davis sees the sector as strong. “There are a lot of utilities across the country who are increasingly including way more procurements and mandates for solar in their own utility-specific targets,” she said. For example, she pointed to the Tennessee Valley Authority’s 227-MW Muscle Shoals project in Alabama, which helped catapult the state from 51st to 18th place in the report’s state rankings for new solar installed last year.

Utility-scale projects also put Texas at the top of the state rankings for the first time, with more than 6 GW of new projects, pushing California’s 3.6 GW to the No. 2 spot.

Triple-B and the NEM Effect

The market impacts of federal and state policy surface as another key theme in the report. With no change in current federal policies, Wood Mackenzie is projecting the U.S. solar market will expand from its current 120 GWdc to 464 GWdc by 2032. But with the 10-year extension of the federal investment tax credit in the stalled Build Back Better Act, the report says the 10-year outlook for solar could grow an additional 66% to nearly 700 GW.

Even at that level, the nation would fall short of the deployments needed to meet President Biden’s goal of a 100% clean energy grid by 2035, Davis said.

“We still see growth in the solar industry, even if the various clean energy incentives that are included in the triple-B Act don’t get passed,” Davis said, referring to Build Back Better. “If we care about hitting some of those decarbonization goals, you really need a catalyst like the clean energy incentives in the triple-B Act, to even hope to get partially there.”

SEIA is also pushing hard for the act’s tax credits for advanced manufacturing to accelerate the buildout of a domestic solar supply chain that would wean the U.S. industry off its dependence on China.

“If we want to have a greater level of energy security in this country, if we are going to build a U.S. solar manufacturing supply chain that is robust, that will be here 20 years from now, we as a nation need to make a stronger commitment to it,” Dan Whitten, SEIA’s vice president of public affairs, said at a March 3 industry event.

Panel prices and supply chain issues lie at the heart of the cost increases being seen across all sectors of the U.S. solar industry, from residential and commercial to utility-scale. For example, the report shows installed system costs in the commercial sector rising from $1.36/w at the end of 2020 to $1.55/w at the end of 2021 – with panels and supply chain accounting for about 75% of the increase.

In this context, supply chain is an umbrella term covering shipping and freight costs and “a lot of things that are not necessarily broken out in all the other categories,” Davis said. “Every developer is going to differ a little bit in how they’re passing along costs. Some of them are going to absorb some of those cost increases … some of them are going to pass along those costs to customers.”

On the state policy side, all eyes are on California as the state’s Public Utility Commission wrestles with the third version of its net metering regulations (NEM 3.0). The proposed revisions to the state’s current net metering plan would slash the compensation rates solar owners receive for the power they put back on the grid, from present rates of 20 cents to 30 cents/kWh to around 5 cents/kWh, according to Wood Mackenzie. Solar owners would also have to pay a “grid participation fee” of up to $40 per month. (See California PUC Proposes New Net Metering Plan.)

Alice Reynolds, the commission’s new president, has put the revisions on hold, pending further review, but Wood Mackenzie estimates that if enacted, NEM 3.0 could cut California’s residential and commercial solar markets in half. “And since California remains the largest distributed solar market in the U.S., these reductions result in nationwide market contraction for both segments starting in 2023,” the report says.

Hybrid Storage

One key development not discussed in the report is the growing number of projects that combine solar with battery storage. The 2022 Sustainable Energy in America Factbook by the Business Council for Sustainable Energy and BloombergNEF noted the trend, especially for the utility-scale sector. (See BNEF: 2021 a ‘Blockbuster Year’ for Clean Energy Investment.)

Acknowledging the omission, Davis agreed, “Utility-scale, in-front-of-the-meter solar installations are overwhelmingly attached with storage today.”

Speaking at a launch event for the Factbook on March 4, Jack Thirolf, head of public policy and institutional affairs for renewable developer Enel North America, said building a solar project without a battery “is going to be an oddity going forward.”

Enel is planning “a ton of projects,” Thirolf said. “And the use case absolutely appears to focus on not just on the energy but carbon reduction as part of energy.”

“It also gives us so much more resilience. Thinking about changes in electricity markets, pricing and structures and fundamentals today are not going to be what they are in 15 years,” he said. “We need to be able to build in flexibility to be able to adapt; we’re building our projects so we can add more storage and different kinds of storage.”

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NERC Reports Mixed Data on Supply Chain Progress

Results from NERC’s recent supply chain effectiveness survey show that the organization’s Critical Infrastructure Protection (CIP) reliability standards are having a positive impact on the industry, staff said Tuesday.

However, more work remains to clear up misunderstandings about their requirements and applicability.

NERC conducted the survey between Oct. 12 and Nov. 30 last year, after the Board of Trustees requested an update on the effectiveness of the supply chain risk management (SCRM) standards:

  • CIP-013-1 (Supply chain risk management);
  • CIP-005-6 (Cybersecurity — electronic security perimeter(s)), parts 2.4 and 2.5; and
  • CIP-010-3 (Cybersecurity — configuration change management and vulnerability assessments), part 1.6.

All three standards took effect Oct. 1, 2020, following their approval by FERC two years prior. (See FERC Finalizes Supply Chain Standards.) Since then the commission has approved their replacements, CIP-013-2, CIP-005-7 and CIP-010-4, which will take effect on Oct. 1. (See FERC OKs Updated Supply Chain Standards.)

The voluntary survey was sent to “approximately 900 compliance contacts at registered entities,” with 201 responding. Eleven surveys were handed back without selecting any answers from the multiple-choice component or providing any comments. Of those that did fill out the survey, 114 said the SCRM standards were applicable to them, while 76 said they were not.

Presenting the survey results at Tuesday’s meeting of NERC’s Reliability and Security Technical Committee, Tony Eddleman, director of NERC reliability compliance at the Nebraska Public Power District and chair of NERC’s Supply Chain Working Group, highlighted responses that indicate registered entities are going beyond the letter of the relevant standards.

In particular, he noted that 24 of the 76 entities that said the SCRM standards did not apply to them — nearly a third — said they are “applying the SCRM principles … to [their] operational, business and/or contract language.” In addition, more than half of those that said the standards do apply to them said they are applying SCRM principles to systems that are not in their scope, such as low-impact bulk electric system cyber systems, which are not covered in the current or upcoming versions of the standards.

“What they told [is] that the standards are a good basis to determine what is needed if the entity wants to have a formal program,” Eddleman said. “So the standards are relatively new, and some entities don’t have compliance requirements, but they are using these to help develop programs.”

Not All Entities Clear on Requirements

While the willingness of entities to go beyond the minimum required by the supply chain standards is promising, the survey also brought to light some potential problems with the standards. For example, even though more than 60% of respondents said they felt the standards’ requirements are clear, they still said they had “questions about compliance evidence,” indicating that they were not sure how auditors might assess their compliance. Additionally, more than 40% of respondents indicated they did not have “a clear understanding of what constitutes a violation” of the standards.

Another finding that raised eyebrows at NERC was that while entities reported dedicating about 22% of their CIP compliance program resources on average to SCRM issues, those compliance programs themselves have only grown about 9% since the introduction of the standards. This indicates to NERC that rather than hire new staff specifically for supply chain compliance, utilities have tended to simply assign employees who normally handle other CIP issues to the SCRM beat. Eddleman expressed concern that this approach might put excessive burdens on already-stretched security professionals.

“One of the quotes that we saw … kind of summed up several of the comments we received … and it said, ‘We all cringe when we know we have to make a purchase,’” Eddleman said. “Supply chain risk management is requiring significant resources … and it’s stealing resources from other CIP programs, [which] is not just a resource strain on utilities, it’s also on vendors.”

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Nevada Looks to Other States for Ways to Replace Gas Tax Revenues

In the search for ways to bolster the state’s transportation funding, Nevada might borrow approaches used in other states, such as a parcel delivery fee adopted in Colorado or Utah’s per-mile charge for EV drivers.

Those are some of the ideas being considered by an Advisory Working Group on sustainable transportation funding convened by the Nevada Department of Transportation (NDOT). The group met Tuesday to narrow down some of the transportation funding options.

Formation of the working group was a requirement of AB413, passed during the state’s 2021 legislative session. The 29-member panel began meeting in July. A report on the group’s findings and recommendations is due by Dec. 31.

Funding Shortfall

The working group is looking at sources of revenue for the State Highway Fund, whose use is restricted to highway construction, maintenance and repairs.

In addition, the group is evaluating “flexible” funding options that could be used for transportation projects that fall outside of the restricted uses of the highway fund. Those projects might include public transit or bicycle projects.

Revenue from the gas tax, which is Nevada’s largest source of transportation funding, has been decreasing on a per-mile-driven basis as vehicle fuel economy improves and more drivers switch to electric vehicles, according to an NDOT report to the working group.

Fuel tax deposits to the highway fund have dropped from 1.27 cents per mile in 2010 to 1.03 cents per mile in 2020.

At the same time, construction costs are rising and demand for transportation infrastructure investments are growing, including at the city, county and regional level, the report said.

Narrowing Options

The working group has reviewed a wide range of transportation funding options and is now narrowing down the choices.

During a meeting on March 8, consultants with CDM Smith presented three potential packages of transportation funding measures. The packages included short-term and long-term strategies, along with options that offer flexibility on how funds are spent.

Working group members then selected the funding strategies they viewed as the most promising. The options will now undergo further analysis.

One option the group supported as either a short- or long-term strategy, or a flexible funding source, was a parcel delivery fee.

A report from CDM Smith proposed a 50 cent fee for deliveries made by USPS, FedEx, UPS and Amazon, and even food-delivery services. The fee would be collected from the seller of the goods, similar to sales tax collection.

The report proposed reducing the fee to 25 cents for deliveries made by a zero-emission vehicle.

The proposal “responds to concerns that e-commerce is overburdening roadways and not paying fair share,” the report said. The fee, as proposed in the report, would raise an estimated $67 million per year.

Colorado has adopted a 27 cent fee on retail deliveries made by motor vehicle that will take effect in July. The fee was included in SB21-260, a transportation funding bill signed into law in June.

Per-mile Fees

As a longer-term strategy, the working group supported exploring a road usage charge for light-duty vehicles.

In its simplest form, the road usage charge would be a modest fee applied equally to all light-duty vehicles based on miles traveled. But the fee could also vary for electric versus gas-powered vehicles, according to speakers at the working group meeting.

Making a road usage charge a longer-term strategy would give the state more time to analyze the costs and benefits of such a system, while allowing other states to forge ahead first, “taking on the first-mover risks,” the consultant’s report to the working group said.

AB413 specifically asked the working group to analyze a road usage charge model proposed by the Natural Resources Defense Council (NRDC).

Under the NRDC model, an annual fee would be assessed on EVs based on the miles-per-gallon-equivalent rating of the model, the gas tax and the number of miles driven each year.

In a second part of the system, the gas tax would be indexed to inflation and total fuel consumption. The idea behind the two-part system is to address the erosion of transportation funding while not slapping EV owners with “unjustifiable high fees” that discourage EV ownership, NRDC explained in a blog post.

AB413 also asked the working group to look at the road usage charge program adopted in Utah.

Utah charges an alternative fuel vehicle fee for electric cars each year on top of the annual registration fee. But under the road usage charge program, drivers can opt out of the flat fee and instead pay 1.52 cents per mile. The mileage-based fee is capped at the amount of the flat fee, which is $123 this year for an EV.

Other Proposals

The working group supported several additional revenue proposals for further analysis. Those include increasing the base vehicle licensing fee or raising the governmental services tax that is assessed on vehicles based on their value.

Increases to the state fuel excise tax rate are also being eyed, including increases indexed to inflation.

Another possibility is a carbon tax, which would assess a fee on each ton of CO2 emitted. The fee could be charged to refineries and factories, to fuel distributors or to drivers. No state currently has a carbon tax, according to the consultant’s report, but several states have a cap-and-trade system.

The advisory working group’s next meeting is scheduled for April 12. More information is available on the Nevada Sustainable Transportation Funding website.

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California Port to Start OSW Upgrades

A Northern California port intended as a major staging area for offshore wind development received a $10.5 million grant Wednesday from the California Energy Commission (CEC) to begin work on upgrading its facilities.

The Port of Humboldt Bay is slated to serve the 1.6 GW Humboldt Wind Energy Area. The Bureau of Ocean Energy Management designated Humboldt as one of two California coastal regions for offshore wind development; the other is in Central California near Morro Bay. Leases for both areas are expected to be auctioned this fall.

The funds will help the Humboldt Bay Harbor, Recreation and Conservation District revitalize the historic timber port on the state’s Redwood Coast, beginning with preliminary engineering and design work. The money will also be used to attract matching grants from the federal government.

Eventually, a new marine terminal will be able to handle heavy cargo vessels and floating platforms, the CEC said.

Humboldt Call Area Map (BOEM) Content.jpgHumboldt call area | BOEM

New CEC Commissioner Kourtney Vaccaro lauded the state’s “opportunity to partner with the [harbor district] in their pursuit of revitalizing their port to support the necessary infrastructure for deploying ocean-based clean energy resources that will benefit Californians.”

Humboldt Bay lacks the bridges and other impediments to developing wind ports in larger deep-water harbors, such as San Francisco and San Diego bays.

“Humboldt Bay has the optimal conditions to serve as the primary port for the offshore wind industry for the entire West Coast,” harbor district board president Greg Dale said in a CEC news release. “We are fully dedicated to prepare our port for this remarkable opportunity.”

The funding allocated by the CEC was originally approved as part of the 2021-22 state budget. Gov. Gavin Newsom has proposed allocating $45 million for investments in waterfront facilities to support offshore wind in his 2022-23 budget plan, now working its way through the state legislature.

The CEC recently started work on an offshore wind strategic plan to help the state achieve its 100% clean energy goal while maintaining a stable grid. Wind off California tends to pick up in the evening as solar power wanes, a critical time in the state’s struggle to keep the lights on during the clean energy transition.

“Offshore wind is an important part of the state’s clean electricity future, providing critical supply at night to complement our abundant solar resources,” Vaccaro said in the CEC statement.

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NERC RSTC Briefs: March 8-9, 2022

First New Member Class Joins Committee

NERC’s Reliability and Security Technical Committee (RSTC) marked a key moment of growth this week, welcoming its first new class of members since the committee’s founding two years ago.

The committee’s initial set of 22 sector representatives and 10 at-large members, plus the chair and vice chair, took their seats at their first meeting in March 2020. (See RSTC Tackles Organization Issues in First Meeting.) The plan was for the members to serve staggered terms of two years each, with half the initial slate to leave in 2022 and the rest departing in 2023.

Nominations for new sector representatives ran from October to November, while at-large nominations were received in December. Each sector selected one delegate except for Sector 7, representing electricity marketers; for this sector two representatives were needed: one for the regular term beginning this year, and the other to replace a retiring member whose term ends next year.

NERC’s Board of Trustees approved the committee’s new membership in February, except for Greg McCauley of Sector 3 (Cooperative Utilities), who was chosen in a special election earlier this month after the resignation of Marc Child of Great River Energy. McCauley, who did not attend this week’s meeting, is expected to be approved at the board’s next meeting in May.

RSTC Chair Greg Ford of Georgia System Operations thanked the incoming representatives as well as the outgoing slate, whom he called the “founding members … who have really worked very hard to bring the RSTC where we are today.”

Among the departing members is ERCOT’s Christine Hasha, a member of the RSTC’s six-person Executive Committee. Members approved the appointment of Christine Ericson of the Illinois Commerce Commission to replace Hasha.

IRPWG Elevated to Subcommittee

The RSTC’s Inverter-based Resources Performance Working Group (IRPWG) will be promoted to a subcommittee following the recommendation of the committee’s Sunset Review Team, which is mandated by the RSTC charter to review each working group every year and determine if their scope needs to be revised, expanded or ended.

The IRPWG, originally called the Inverter-based Resources Performance Task Force, was created under the Planning Committee to “explore the performance characteristics of utility-scale inverter-based resources [IBRs] … directly connected to the bulk power system.” Its remit includes researching the extent of penetration of IBRs in the bulk power system, as well as producing reliability guidelines and standard authorization requests for potential IBR-related reliability standards.

Robert Reinmuller of Hydro One, in his presentation on the Sunset Review Team’s recommendations, said that given the accelerating transition of the grid to renewable energy sources and the “quite considerable” work planned by the IRPWG, raising the profile of the group by making it a full subcommittee would help it meet its goals.

“The next several years will be critical in the adoption and integration of these resources and making sure that we’re tracking performance [and] we have proper guidelines, standards and so on,” Reinmuller said.

The RSTC’s other working groups will continue in their current form, per the team’s recommendation.

New Guidelines Approved

Other approvals in this week’s meeting included two reliability guidelines, which unlike reliability standards are nonbinding and strictly voluntary. The first, submitted by the Resources Subcommittee, concerns accounting practices to address inadvertent interchange and “provide a method for isolating and eliminating the source(s) of accounting errors.” A draft version of the guideline is already present on NERC’s Reliability and Security Guidelines webpage; the new version adds language regarding the development of metrics.

The second guideline, “DER Forecasting Practices and Relationship to DER Modeling for BPS Planning Studies,” was submitted by the System Planning Impacts of Distributed Energy Resources (SPIDER) Working Group. Like the subcommittee’s guideline, SPIDER’s document modifies the draft version on NERC’s website to add new metrics for use by industry.

Both guidelines have been through the industry commenting process; the revisions are based on the comments received. Having received the RSTC’s approval, they will now be posted to NERC’s website.

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Midwest Experts Say Tx, Market Changes Key to Reliability

Transmission construction and MISO market facelifts can help the Midwest reliably adjust to a new resource reality, panelists said Tuesday during an Energy Bar Association (EBA) teleconference. 

“This is a time that is really a seismic shift in the industry,” Ameren Director of RTO Policy Jeff Dodd said during a discussion hosted by EBA’s Midwest chapter.

MISO counsel Michael Kessler said the grid operator is besieged by declining reserve margins as aging baseload units are replaced with renewables. He said even a growing natural gas fleet might not be able to procure enough fuel to keep the grid reliable at times. 

Scott Wright, the RTO’s executive director of market strategy, said the changing resource fleet has placed MISO at the doorstep of reliability problems. 

“This is not a far and distant problem. This is here now,” he said. 

Wright said, “excess reserve margins are a thing of the past” and the grid operator now navigates challenging conditions carefully and with little capacity to spare. 

He said MISO must build long-range transmission to bring an additional 120 to 330 GW of additional capacity online by 2040. Those figures are necessary to meet members’ carbon-reduction goals or bring the footprint to net-zero carbon emissions, Wright said.

The RTO recently revealed a potential multistage long-range planning portfolio. (See MISO Long-range Tx Plan Overlaps with SPP Study.)

“It used to be a moderated pace of change. To me, it’s [now] a rush,” Wright said. He also called environmental and social governance awareness “the new kid on the block” that stands to hasten fleet change.

Wright said natural gas generation used to be viewed as a bridge to clean energy. “Now, they’re burning the bridge,” he said, referencing utilities focusing on renewables over needed centralized power.

Wright questioned whether “storage has come along enough” to meet instantaneous load. He said the RTO’s operations will become much more complex in the coming years by optimizing load and managing decentralized resources.

“There’s a lot of different ‘minding of the store’ that’s going to need to happen here,” Wright said. He added that he didn’t mean to sound “defeatist” or “sensational” and said MISO has a solid, well-functioning market in place today that simply requires adaptation. 

Dodd said distribution companies, transmission planners and state regulators must engage in a level of coordination that wasn’t necessary a few years ago. 

“A lot of utilities are starting to understand we need all these groups in the same room,” he said.

Organization of MISO States President Sarah Freeman, an Indiana Utility Regulatory commissioner, called the path to net-zero emissions a “juggling of the chainsaws.” She said that just as MISO’s geography and resources are diverse, “cultures among governing bodies” are also diverse within the footprint. 

“I say Indiana is a red state going green,” she said. 

Dodd said in Ameren’s experience, customer preference, not state policy, is driving the clean energy conversion. The company has a 2050 net-zero emissions goal, but Dodd said that target could be accelerated. He also noted Ameren Illinois must cease all fossil generation in the state no later than 2045, according to state law. 

Dodd called transmission “a facilitator” in the transition to a cleaner generation portfolio. 

“MISO has success with this scenario planning,” Dodd said of the three 20-year planning futures used to justify transmission projects. He said the 2011 Multi-Value Project (MVP) portfolio continues to deliver benefits well in excess of the $6.5 billion cost. 

The MVP portfolio had a “Field of Dreams: if you build it, they will come” approach, Dodd said. With MISO’s long-range planning, there’s now little doubt that new lines will be useful, he said. 

“Those lines were fully subscribed as soon as they were built,” he said of the MVP’s success. “I think MVPs laid the groundwork for the long-range transmission plan.” 

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ERCOT Board of Directors Briefs: March 7-8, 2022

Governance Changes for TAC, Stakeholder Process Remain Unclear

ERCOT’s Board of Directors left the grid operator’s top stakeholder committee, the Technical Advisory Committee, in a bit of limbo this week as it continued to debate governance and stakeholder coordination.

The directors on Tuesday first deferred confirmation of the TAC’s leadership, normally a routine matter, until the board’s April 27-28 meeting. That meeting was rescheduled from April 12 and would have conflicted with a TAC meeting. However, the committee moved its April 27 meeting up to April 13 to help push an urgent protocol revision request through the stakeholder process.

The directors then approved the creation of a board-level meeting committee to oversee ERCOT’s core functions. As proposed by staff, the Reliability and Markets Committee would focus on markets, planning, reliability and resilience. The scope would also include information technology and project delivery.

Both actions followed an extensive executive session that began Monday and ended Tuesday.

TAC Chair Clif Lange, with South Texas Electric Cooperative, said the delayed vote on his confirmation caught him by surprise and wasn’t telegraphed by ERCOT staff. He said he only became aware of the board’s actions when he started receiving texts from TAC members Tuesday morning.

“We didn’t see that coming,” Lange told RTO Insider. “Nothing had been communicated to us.”

He said nothing in the meeting materials indicated to him that the TAC would answer directly to the board and said that further modifications to the committee could be in the offing.

The board, which has met with all 11 members just twice since December, has been vocal in its previous meetings about the time it takes protocol revisions to clear the stakeholder process. The TAC is responsible for vetting and endorsing protocol revisions that come up from the working groups, while market participants’ heavy involvement in ERCOT’s governance has drawn attention since the February 2021 winter storm.

The TAC, for its part, has discussed the potential changes to the stakeholder process several times in recent months. (See “TAC Members Look for Direction on Governance Structure, Stakeholder Process,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)

“I know we on the TAC are a little concerned that not engaging stakeholders and shutting them out will result in suboptimal products for ERCOT,” said Lange, who added that he plans to take his concerns to interim CEO Brad Jones.

ERCOT officials say the eight new independent board directors are grappling with their new responsibilities.

Chris Ekoh, interim CEO of the Office of Public Utility Counsel (OPUC) and the only non-independent voting board member, read a memo into the record that expressed his concerns for the stakeholder process and with the new board committee. He asked whether the TAC will be disbanded or made “subservient” to the new board committee.

“It is not clear to OPUC how the creation of the new Reliability and Markets Committee will impact or coexist with the current stakeholder process,” he said. “How will the proposed Reliability and Markets Committee interact with TAC? How does the committee and TAC work together, if at all? How does it impact the protocol revision process?”

Ekoh also asked whether there were compliance concerns for ERCOT if the revision process is modified.

“Those are questions everybody has about how TAC is going to interact with the board,” Lange said.

There was no public discussion of Ekoh’s comments among the board members.

Upward Pressure on Admin Fee

CFO Sean Taylor told the directors that ERCOT’s costs are projected to continue to grow at a rate faster than shown in its current 2022-2023 budget, which was approved last year. He said additional demands placed on staff as a result of last year’s winter storm include new regulatory requirements, protocol and planning revisions, and increased IT support costs for new or improved services that were not expected.

“There is upward pressure on the 2023 budgeted system administration fee rate,” Taylor said. “That fee will not be as adequate as previously thought.”

ERCOT has maintained a system admin fee of 55.5 cents/MWh since 2016. It had projected increasing the fee to 66.5 cents/MWh in the 2024-2025 budget.

Staff reported a preliminary negative net variance of $25.5 million for 2021, with system admin fees coming in $10.9 million under expectations because of less energy sold. The grid operator had projected 413.1 TWh of energy sales in 2021, only to see 393.3 TWh of energy sold.

Expenditures were $14.4 million overbudget, primarily because of outside legal services, hardware and software support and maintenance, higher insurance premiums, and professional consulting.

ERCOT has operated with a biennial budget since 2014, at the Public Utility Commission’s request. Its filed budget includes four additional years of forecasted numbers.

Board Approves Firm Fuel Product

The board approved three revision requests that cleared the TAC with dissenting votes, including a nodal protocol revision request (NPRR1120) that creates a firm fuel supply service (FFSS) designed to provide additional grid reliability and resilience during extreme cold weather. The NPRR also compensates generators that meet a higher resilience standard in the face of a natural gas curtailment or other fuel supply disruption.

The PUC has directed that the standalone, auction-based product be procured similarly to ERCOT’s black start program and serve as a stopgap should weatherization not be incorporated into a load-serving entity’s obligation.

      • OBDRR039: removes FFSS-deployed resources’ high sustained limits from the ORDC’s reserve calculation.
      • PGRR095: establishes minimum deliverability criteria over the entire real power capability range of each ERCOT resource whose output is primarily within the grid operator’s control through dispatch instructions.

The directors also approved eight additional NPRRs, a Nodal Operating Guide revision (NOGRR), three more OBDRRs, single changes to the Planning Guide (PGRR) and the Retail Market Guide (RMGRR), and three system change requests (SCRs).

      • NPRR1095: contains revisions that the Texas Standard Electronic Transaction (Texas SET) Working Group has determined are necessary to support the Texas SET V5.0 improvement list.
      • NPRR1097: creates reports posted three days after each operating day that document forced outages, maintenance outages and forced derates of generation and energy storage resources.
      • NPRR1098: establishes reactive power capability requirements for new DC ties interconnecting to the ERCOT system and existing DC ties replaced after Jan. 1.
      • NPRR1099: grants ERCOT greater authority to move a resource node in the network operations model when deemed necessary to properly reflect point-of-interconnection (POI) changes or resource retirements.
      • NPRR1102: allows ERCOT to adjust back-casted non-interval data recorder load profiles.
      • NPRR1111: expands the use of the security-constrained economic dispatch (SCED) base point below the high dispatch limit flag to signify that ERCOT has instructed an intermittent renewable resource (IRR) or DC-coupled resources not to exceed its base point.
      • NPRR1113: adjusts the real-time ancillary service imbalance payment/charge’s definitions to prohibit double-counting of the regulation-up schedule when calculating capacity in the imbalance settlement for controllable load resources available to SCED.
      • NPRR1114: establishes processes to assess and collect securitization uplift charges to qualified scheduling entities representing LSEs pursuant to one of the PUC’s two debt obligation orders (52322).
      • NOGRR234: revises the guide to be consistent with NPRR1098’s reactive power capability requirements for DC ties, specifying DC tie operator responsibilities related to real-time operational voltage control.
      • OBDRR034: allows ERCOT to move network operations model resource nodes for POI changes or resource retirements.
      • OBDRR037: caps the power balance penalty curve at $5,001/MWh (the HCAP plus $1/MWh), effectively setting the curve’s price at its maximum value when violations are above 100 MW. The measure also reduces the generic transmission constraint shadow-price cap for base case voltage violations from $9,251/MW to $5,251/MW. Gray box language describes how the curve will work with the new HCAP upon real-time co-optimization’s implementation.
      • OBDRR038: updates the ORDC’s minimum contingency level to 3,000 MW within the relevant methodology document.
      • PGRR099: provides that an entity will not be eligible to begin or maintain a generator interconnection or modification (GIM) if it or any other owner of the project meets any of the company ownership (including affiliations) or headquarters criteria listed in the state’s Lone Star Infrastructure Protection Act. Any entity that seeks to initiate a GIM will be required to submit an attestation confirming that it does not meet the statutory criteria.
      • RMGRR169: updates the Texas SET’s continuous service agreement (CSA) bypass validations at ERCOT; allows for rejection of move out (MVO) transactions if the CSA owner and MVO competitive retailer (CR) do not match; allows ERCOT to issue a move in transaction for the appropriate CSA CR when an MVO is submitted; and revises the inadvertent gain process to align with SCR817’s proposed MarkeTrak enhancements.
      • SCR816: unlocks congestion revenue right bid credit on the same day auction results are posted.
      • SCR817: adds validations/requirements to existing MarkeTrak subtypes, revises existing workflows and suggests new subtypes to align with current market practices for more efficient issue resolution.
      • SCR819: improves dispatch of base points to resources to account for ramping un-curtailed IRRs.
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Green Hydrogen Bill Passes Wash. Legislature

A bill is headed to Washington Gov. Jay Inslee to create a new state office to support development of green hydrogen and other alternative fuels.

The state Senate unanimously approved Senate Bill 5910 on Wednesday, after the House passed it Monday 96-2 with some minor tweaks.

“Renewable hydrogen is an exciting part of our future,” bill sponsor Sen. Reuven Carlyle (D) said prior to Wednesday’s floor vote.

The bill appears to boost Washington’s prospects to receive money from the federal Infrastructure Investment and Jobs Act to create one of four regional hydrogen hubs in the nation. (See Fast-moving Bill Seeks to Win Hydrogen Hub for Wash.)

The proposed Office of Renewable Fuels in the Washington Department of Commerce would collaborate with other state agencies to accelerate market development of renewable fuel and electrolytic hydrogen projects along their full life cycle, in part by supporting research and development around production, distribution and end uses. It would also identify ways to best deploy the fuels to support the state’s climate change mitigation and adaptation efforts.

The new office is also expected to help boost job creation while partnering with “overburdened” communities to ensure they benefit from clean fuels development. It would also review the state’s existing renewable fuels and hydrogen initiatives and support public-private opportunities that encourage adoption of clean fuels. The office is expected to coordinate its efforts with local state and federal governments, the private sector and universities.

The bill would also allow proposed hydrogen production projects the choice of applying for permits from the state Energy Facility Site Evaluation Council, rather than local governments. (See Bill to Expand Powers of Wash. Siting Council Passes Senate.) It would also authorize municipal utilities and public utility districts to produce, use, sell and distribute hydrogen and other renewable fuels.

The legislation could help Washington land one of the four hydrogen hubs outlined in the IIJA, enacted last year. The federal law allocates $8 billion for the creation of at least four hydrogen hubs across the country, as well as $1 billion for the domestic manufacture of the electrolyzers needed to convert water to green hydrogen. The U.S. Department of Energy will solicit proposals for the hubs until May 15 and select the four sites a year later.

Washington has one hydrogen production plant under construction near East Wenatchee, which will use Columbia River water as its source. The plant, to be operated by Douglas County Public Utility District near the Wells Dam, is scheduled to go online late this year. A hydrogen fueling station is on the drawing board for near East Wanatchee, and another is in the works for public transit buses in Lewis County, about 25 miles south of Olympia.