Page 1248 – RTO Insider

May 5, 2019January 3, 2024

Environmental Groups Divided on Cardinal-Hickory Creek Line

By Amanda Durish Cook

If politics makes strange bedfellows, then transmission policy can create equally unlikely adversaries when it cuts across the competing interests of different environmental groups inclined to agree on most issues.

An example is currently playing out in Wisconsin, where environmentalists, preservationists and renewable energy advocates are at odds with each other over the pending approval of a major MISO transmission line designed to carry wind energy to population centers. Some are seeking to advance the project as proposed, while others support substitute plans that include adoption of local renewable resources.

The $500 million, 345-kV Cardinal-Hickory Creek project would span about 120 miles from Dubuque County, Iowa, to Dane County, Wis. Costs for the joint project involving American Transmission Co., ITC Midwest and Dairyland Power Cooperative would be shared on a load-ratio basis across ratepayers in MISO.

The Wisconsin Public Service Commission will hold six public hearings on the project in June. The commission has until Sept. 30 to review the application and decide on the necessity and placement of the line. The project also still faces a regulatory review in Iowa.

The project’s opponents and supporters in Wisconsin have been filing testimony and exhibits daily, and ATC is in the process of deposing witnesses in the case (5-CE-146).

The Cardinal-Hickory Creek line is the last of 17 MISO multi-value projects (MVPs) to enter the state regulatory approval process. MISO originally expected the project — designed to supplant more than a dozen other upgrades to constrained lower-voltage transmission lines — to be operational between 2018 and 2020.

“It’s unfortunate that it’s taken as long as it has to get into the regulatory process. … There are a lot of complicated pieces. But the longer this goes on, the more it’s preventing cost-effective resources from coming online,” Clean Grid Alliance Executive Director Beth Soholt said in an interview with RTO Insider.

The nonprofit is one of a handful of clean energy organizations backing the line’s construction. Its members include energy industry participants such as Avangrid Renewables, Invenergy, NextEra Energy and Vestas, as well as groups such as Union of Concerned Scientists, Iowa Environmental Council and National Farmers Union.

Soholt pointed out that when MISO identified the project as part of the 2011 MVP study process, it concluded the line would provide multiple benefits, including reliability, facilitating an economic market and helping meet public policy goals like state renewable portfolio standards.

“When you really look at ticking off all those pieces, Cardinal-Hickory Creek is the best option. This is the appropriate project,” Soholt said, adding that about 8,000 MW of existing and proposed wind generation needs the line to deliver energy and mitigate curtailments that are occurring today.

Soholt said that even if planners decide to “upset the apple cart” and forgo the project, the area would likely need a substitute that would contain several similarities to the existing proposal.

“For this particular purpose — to move the wind and solar megawatts that are being constructed — there is no other option, particular when you need to move electrons across time and space.”

She pointed out that MISO generator interconnection studies have long assumed Cardinal-Hickory Creek will be built. If the line isn’t built, interconnection customers may have to bear expensive transmission upgrade costs themselves, rendering some generation projects uneconomic and depriving ratepayers of the additional benefits the line will bring, Soholt warned.

“This line has been embedded into the MISO transmission planning and interconnection process for years,” she said. “Not constructing Cardinal-Hickory Creek will have a domino effect and cause restudies. Once you start that domino, it will get internalized into other projects, and some simply wouldn’t go forward,” Soholt said. She pointed to the RTO’s increasingly interconnected grid, shifting resource mix and more frequent emergency conditions as evidence of the need for additional transmission in the footprint.

“I don’t think I can say strongly enough … the need for transmission is only increasing, not decreasing.”

CGA, Fresh Energy and the Minnesota Center for Environmental Advocacy testified that the project will also reduce Wisconsin’s dependence on pivotal suppliers. Grid Strategies Vice President Michael Goggin pointed out that MISO territory in Wisconsin and Michigan’s Upper Peninsula had at least one pivotal supplier about 40% of the time in 2017.

A Distributed Future?

But landowners and residents have said the project is unnecessary and will impose higher taxes and utility rates, harm property values and agriculture, and destroy portions of the Driftles s Area.

Opponents include the Driftless Area Land Conservancy and Wisconsin Wildlife Foundation, represented by Howard Learner of the Environmental Law and Policy Center. The two groups say a 627-page draft review of the line by the U.S. Department of Agriculture’s Rural Utilities Service neglected to consider alternatives that combine lower-voltage lines and investments in battery storage, solar generation and energy efficiency. The agency said each of those separate approaches was impractical, though it didn’t consider the alternatives as a package.

“There are out-of-state environmental groups supporting the line, but the in-state environmental and conservation groups in almost all cases are opposing a large transmission line that would cut a wide swath through the scenic Driftless Area,” Learner said in a phone interview with RTO Insider.

In an agricultural impact statement last month, the Wisconsin Department of Agriculture, Trade and Consumer Protection declined to recommend a specific route for the line, saying all proposed routes would “impact significant acres of farmland.”

U.S. Sen. Tammy Baldwin (D-Wis.) recently joined opponents in criticizing the environmental review by the RUS, calling for a “meaningful analysis” of project alternatives and different routes for the line to cross the Mississippi River.

Wisconsin State Sen. Howard Marklein (R) also questioned the need for the project and asked the PSC for a clear and public justification for the project if the commission votes to approve it.

Learner said such a large line is unnecessary and takes issue that the project was never studied in isolation by MISO.

“When the transmission line was included in the MVP package in 2011, it wasn’t studied individually; it was studied as a portfolio with the other MVPs,” Lerner said. “Secondly, the world and electricity sector has obviously changed since 2011.”

In testimony provided by the Wisconsin PSC, electrical engineer Alexander Vedvik said that while the MVP portfolio “as a whole does in fact create benefits greater than the costs of the portfolio, it is entirely possible that one or more projects included in the MVP portfolio have benefits that are lower than the costs.” Using ATC’s models, the PSC found negative economic benefits were possible in several of the hypothetical cases it studied.

Despite changes over intervening years, MISO still expects benefits from the line. According to the RTO’s 2017 triennial review of MVPs, eastern Wisconsin would see a benefit-to-cost ratio of 1.9-2.9:1, while western Wisconsin would achieve a ratio of 3.2-4.8:1.

“Wind deployment in Iowa, Minnesota, North Dakota and South Dakota has greatly exceeded the already high level that the MVP projects were designed to serve. As a result, the benefits of and need for the Cardinal-Hickory Creek project are even greater than when MISO’s MVP planning process determined the project was needed and provided large net benefits,” Goggin said.

But Learner said at the time the MVP portfolio was approved, grid planners were forecasting a 1 to 1.5% annual growth. Since then, electricity sales and demand have flattened.

Learner also said the line was first studied when “solar energy was only a blip.” Last month, the Wisconsin PSC approved about 450 MW worth of solar development. If realized, the projects will lead to an almost five-fold increase in utility-scale solar generation in the state.

“That’s how fast solar is rapidly accelerating in Wisconsin,” Learner said. “To some degree, this case is about the old energy system versus the newer, cleaner distributed grid.”

No Need, Opponents Argue

Learner said the line will cost ratepayers a total $2 billion to $3 billion locked into rates over a 40-year revenue requirement period “at precisely the time” the industry is rapidly shifting. He likened the energy industry to the telecom industry at the point when cell service was rapidly superseding landlines.

“The world is changing. There’s no credible argument that there’s a need for imported power in Wisconsin to keep the lights on. I don’t think anybody is arguing that Wisconsin needs more imports in order to ensure reliability,” Learner said.

Energy companies in Iowa, Minnesota and the Dakotas are building more wind power, Learner argued, but utilities in those states are not shutting down existing fossil fuel plants, leading to excess generation.

Learner also said the line will support an “unspecified mix” of coal, wind, nuclear and gas-fired generation, not just wind.

The smaller line upgrades that Cardinal-Hickory Creek will render unnecessary, Learner argues, should be proposed on their own if they’re needed for local reliability. “If you need to fix local lines, fix local lines. … Don’t force people to pay billions for an entire transmission line,” he said.

But Soholt maintains that even a multifaceted alternative strategy isn’t a proper substitute for the project. While she foresees growth in distributed resources, she said a major transmission line compared to a distributed solution are “apples and oranges.”

“We can’t use energy efficiency, distributed resources or other local alternatives to move megawatts in time and space across the MISO footprint. There is just no cost-effective and timely substitute for the existing and future wind and solar projects relying on this line,” Soholt said.

“Bringing in distributed resources won’t solve the problem. It doesn’t deliver the megawatts that are being bottled up right now. It doesn’t facilitate the renewable megawatts that are in MISO’s interconnection queue right now,” Soholt said. “You need a grid to be able to move those resources to where they can be used. The idea that we can do this is without high-voltage transmission is not realistic. The grid is going to become more important as we get more distributed resources.”

May 5, 2019

WECC Summit Explores Rapid Change in the West

By Hudson Sangree

SCOTTSDALE, Ariz. — The challenges facing the national and Western grids sound like the stuff of movie thrillers.

Speakers at this year’s Western Reliability Summit, hosted by the Western Electricity Coordinating Council, said massive storms caused by climate change could cut off power for days or weeks.

About 100 people attended WECC’s Western Reliability Summit in Scottsdale, Ariz., on May 1. | © *RTO Insider*

“We ain’t seen nothing yet with respect to hurricanes,” David K. Owens, retired executive vice president of the Edison Electric Institute, said in his keynote address. Owens worked to restore power to Puerto Rico after Hurricane Maria in 2017.

The most significant hurricanes in history, in terms of duration of blackouts, have occurred in the last 10 years, Owens said.

“The grid has got to be hardened,” Owens said. “The grid has got to be smarter.”

Others worried about cyberattacks from overseas.

“A guy in Nigeria can potentially take out your network and every one of your systems,” Michael Lettman, a cybersecurity adviser with the U.S. Department of Homeland Security, told the utility executives and regulators in the audience.

And some envisioned a science fiction future when millions of electric vehicles and rooftop solar arrays will help power the West — and potentially contribute to reliability problems.

“We’re going to see a much more dynamic supply and demand profile on our distribution grid” going forward, said Chris Campbell, senior director of grid modernization for Arizona’s Salt River Project.

WECC CEO Melanie Frye said the once staid business of providing electricity is getting more tangled.

“I am in awe of the ever-increasing complexity of the world in which we’re trying to deliver safe, reliable and secure electricity to our customers,” Frye said in her concluding remarks.

WECC, charged by NERC and FERC with ensuring the reliability and security of the Western Interconnection, holds its yearly summit to let industry leaders air their thoughts.

This year’s summit consisted of four panels that focused on cyber threats, transformational technology, the future of utilities, and changing norms and expectations among consumers and providers of electricity.

‘Waiting for the Cyber 9/11’

In the panel on cybersecurity, speakers urged utilities to prepare for computer shutdowns by practicing their skills with pen and paper. “We’ve got to have ways to fall back manually,” Lettman said.

Cybersecurity needs to be as commonplace as physical security for utilities. “Shaking hands with the FBI when you’re under attack is a bad idea,” he said.

Threats can come in the form of email attachments sent to employees. Workers need to be trained not to open files containing malicious software, he said. (See Expert Sees ‘Extreme Uptick’ in Cyber Attacks on Utilities.)

From left to right: David Foose, Emerson Automation Solutions; Peyton Price, Idaho National Laboratory; Michael Lettman, Department of Homeland Security; and moderator David Godfrey, WECC, weighed the threat of cyber attacks. | © *RTO Insider*

Moderator David Godfrey, vice president of reliability and security oversight with WECC, asked panelists what they saw as the biggest cybersecurity concern in the next five years.

Lettman said attackers could hack into a secure network through an online device such as a baby monitor or a driverless car.

“Cyber Armageddon” had already occurred during the attacks on Ukrainian government ministries, banks and electric utilities in June 2017, he said. Lettman also cited the 2014 hack of Sony Pictures that U.S. officials blamed on North Korea.

Utilities should assume they will be the next target, he said. “We are all now security people whether we like it or not.”

Peyton Price, a Navy fellow with the Idaho National Laboratory, said it’s important to understand that numerous smaller cyberattacks could damage the grid as much as one major attack.

“I think we’re all waiting for the cyber 9/11 … [instead of] death by 1,000 cuts,” he said.

Transformational Technology

In a panel titled “What is the Next Transformational Technology?” SRP’s Campbell also recommended keeping up on “manual processes” in case of computer failure.

“As we depend more on technology, we need to be able to fall back when it’s not working properly,” he said.

He said he saw solar power and EVs as the major transformative technologies in Arizona and other parts of the West.

Utility-scale and rooftop solar will grow in importance in states flooded with sunlight, he said. The number of EVs is expected to increase exponentially, he said.

A panel on transformational technology included (left to right), Chris Campbell, Salt River Project; Chris Schroeder, Smart Electric Power Alliance; Kiran Kumaraswamy, Fluence Energy; Mahesh Morjaria, First Solar; and moderator Branden Sudduth, WECC. | © *RTO Insider*

Mahesh Morjaria, vice president of development with First Solar, said he too believed solar would become a major force. It’s mainstream and inexpensive now, 65 years after Bell Labs invented the first solar cell, he said.

Chris Schroeder, with the nonprofit Smart Electric Power Alliance, said he sees the ability to aggregate rooftop solar and home batteries as transformational. Newer subdivisions can be built with both components, and utilities can call on those resources during short periods of under- or oversupply hundreds of times per year, Schroeder said.

Storage will be the biggest driver of change in coming years, said Kiran Kumaraswamy, vice president of market applications at Fluence Energy. It can siphon excess solar energy from the grid in times of surplus and inject it back into the grid at times of peak demand, he said. It can also be a local resource in areas with supply constraints, he said. (See Calif. Needs Far More Storage to Decarbonize, Panelists Say.)

“With all of these things we see an incredible promise,” Kumaraswamy said.

Changing Norms

Three utility regulators from California, Oregon and Washington talked about reliability concerns as renewable energy becomes a bigger part of the supply mix and community choice aggregators multiply.

Ann Rendahl, a commissioner with the Washington Utilities and Transportation Commission, said her state was on the verge of adopting a 100% clean energy mandate, as California, Nevada and other states have already done. (See Washington, Nevada Join 100% Clean Energy Movement.)

Keeping the grid reliable and ensuring resource adequacy at times of high demand in the West could prove problematic under those mandates, she said. “Washington is not an island.”

In California, 19 CCAs now serve load, including the Los Angeles-area Clean Power Alliance with 1 million customers.

In 2016, investor-owned utilities served 90% of peak capacity load in California, state Public Utilities Commissioner Liane Randolph said. In 2019, IOUs will serve 66% of peak capacity load and CCAs will serve 25%, she said.

It remains uncertain if the CCAs, many of which are startups, can procure enough carbon-free energy to meet legal requirements and peak load, she said. (See Calif. Lawmakers Reveal Growing Divisions Over CCAs.)

Wildfires, which devastated areas of California in the past two years, are the state’s biggest challenge to reliability, she said. (See RC Transition, California Wildfires Will Occupy 2019.)

Utility of the Future

In a panel moderated by WECC’s Frye, utility executives and an independent consultant were asked, “What does the utility of the future look like?”

Jeff Guldner, president of Arizona Public Service, said customers will expect utilities to provide the clean energy they demand without wanting to understand the complexity of providing it — while keeping the lights on. Gluts of solar energy without sufficient storage will make that difficult, he said.

Utilities will have to become more customer-oriented, “like Amazon,” Guldner said. “Customers think about their utility like almost nothing.”

From left to right: Colin Cushnie, vice president of Southern California Edison; Jeff Guldner, president of Arizona Public Service; and Gregory Guthridge, an indpendent consultant, discussed the utility of the future with WECC CEO Melanie Frye. | © *RTO Insider*

Independent consultant Gregory Guthridge said the relationship between utilities and their customers is bound to become “increasingly complex.”

Southern California Edison is working to meet California’s aggressive clean energy mandates, but meeting those goals while incorporating millions of EVs and rooftop solar arrays will be challenging, said Colin Cushnie, the utility’s vice president of power supply. (See Calif. Gov. Signs Clean Energy Act Before Climate Summit.)

Cushnie said he worries California will have to deal with future resource deficiencies.

“That would be the thing that would keep me up at night — how to make all this stuff work.”

May 5, 2019

NRG to Bring Back Gas Plant for Summer 2019

NRG Energy said last week it expects to return to service an inactive Texas gas plant in time for summer, giving ERCOT additional capacity to play with.

ERCOT enters summer with a historically low reserve margin of 7.4%. The 385-MW Gregory plant will give the grid operator much needed extra capacity.

Gregory, located just outside Corpus Christi, was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. It is expected to return to service as a combined cycle facility in early June.

NRG CEO Mauricio Gutierrez | © *RTO Insider*

In a statement released after NRG’s first-quarter earnings call Thursday, CEO Mauricio Gutierrez said the Texas Public Utility Commission’s recent actions to strengthen the ERCOT market “reinforced our decision to return Gregory to service ahead of summer.” (See related story, NRG Energy Earnings Drop on ERCOT Hedges.)

The PUC in recent months has worked to improve coordination between electric utilities and pipeline companies and ordered tweaks to ERCOT’s operating reserve demand curve price adder.

ERCOT will release its final resource adequacy assessment for the summer on Wednesday.

— Tom Kleckner

May 5, 2019

HITT Shares Draft Report with SPP Stakeholders

By Tom Kleckner

TULSA, Okla. — SPP’s Holistic Integrated Tariff Team (HITT) last week shared with stakeholders the result of a year’s worth of work: a draft report of high-level recommendations addressing the footprint’s many challenges.

Now comes the hard part: taking action on the recommendations.

“There’s a heck of a lot of work that’s left,” HITT Chair Tom Kent said during SPP’s April 29 joint quarterly stakeholder briefing. “The working groups will have a lot of effort to put these [recommendations] into actual action.”

Kent, COO for Nebraska Public Power District, said the HITT report makes 21 recommendations in four categories: reliability, marketplace, planning and cost allocation, and strategy. Thirteen of the recommendations, some of which are already in progress, are planned for implementation; the other eight require further study.

Stakeholders prepare for SPP’s quarterly briefing session. | © *RTO Insider*

The big-ticket cost-allocation recommendations include decoupling Schedule 9 and Schedule 11 transmission pricing zones and allowing the creation of larger Schedule 11 pricing zones and/or Schedule 9 sub-zones. The HITT proposes that if the Regional State Committee adopts a policy to reallocate existing costs within the new pricing zones, it should be done over a five- to 10-year transition period to mitigate cost shifts.

The HITT is also recommending SPP determine whether transmission projects below 300 kV can be fully allocated on a regionwide basis; use incremental long-term congestion rights instead of Attachment Z2 credits as compensation for new sponsored upgrade projects; and evaluate whether it can establish cost allocation and rates under the Tariff for energy storage resources.

The team also recommends SPP continue to improve the Integrated Marketplace by including fast-start resource logic, ramping capability and a multiday, longer-term market product, and to continue developing a market mechanism to hedge load against congestion charges.

Kent said the report is a “tribute to the team working hard and working together, and coming to a strong consensus on the recommendations.”

A proposed action plan assigns the recommendations to various stakeholder groups. A timeline anticipates the work being completed by mid-2021.

Larry Altenbaumer, chair of SPP’s Board of Directors, called the HITT’s work “an example of the very best of SPP.”

“We fully recognize 85% of the work is in front of us,” he said. “It’s an exciting beginning of a very important next step for us. I think HITT’s going to be a good thing for us.”

“The industry is changing as rapidly as many of us who’ve been around for a long time have seen it change,” said HITT member Dennis Grennan, a commissioner with the Nebraska Power Review Board. “We must prepare for major changes coming in the next five to 10 years. It’s a real challenge, but it needs to be done so that our consumers back home truly benefit from belonging to SPP and all that comes with it.”

Kent promised a final report by the end of June and said that a final product will be brought to the July stakeholder meetings. He said it will be discussed in detail with the Strategic Planning Committee during its May 9 planning retreat.

SPP — HITT Chair Tom Kent (left) confers with his vice chair, Dogwood Energy’s Rob Janssen. | © *RTO Insider*

The RSC has scheduled in-person meetings with the HITT on May 30 and June 24, and Altenbaumer asked for a workshop to be scheduled where stakeholders can participate in a “top-to-bottom” discussion of the report.

The SPP board charged the HITT with developing recommendations for holistic improvements within the system. The team is composed of 15 board members, state regulators and SPP members. (See SPP’s Tariff Team Begins Carving up the Elephant.)

May 5, 2019

FERC Takes Second Look at Entergy Arkansas ROE

FERC is re-evaluating how its 2018 decision on transmission owners’ return on equity might affect Entergy Arkansas’ unit power sales tariff from 2013.

The commission April 30 said it could determine a new ROE for Entergy Arkansas and issued an order directing submission of briefs and additional written evidence (ER13-1508-001).

The issue dates back six years, when Entergy Arkansas decided to leave the Entergy System Agreement and join MISO. As a result, Entergy Arkansas created a unit power sales tariff that passed through MISO’s ancillary and uplift charges and credits, along with the RTO’s 11% ROE for TOs. Both the Louisiana Public Service Commission and the city of New Orleans protested Entergy Arkansas’ use of the rate. Using the 2014 Opinion 531 that set the ROE for transmission owners in New England, an administrative law judge in 2015 found that 9.01% was reasonable in Entergy Arkansas’ case.

But with Opinion 531 vacated in 2017 and no longer serving as precedent, FERC wants a fresh look at Entergy Arkansas’ ROE. As of last year, the commission said it will no longer rely only on the discounted cash flow (DCF) model, instead using a combination of DCF and the capital asset pricing, expected earnings and risk premium models. (See FERC Changing ROE Rules; Higher Rates Likely.)

“Accordingly, we direct the participants to this proceeding to submit briefs regarding the proposed new methodology for determining just and reasonable ROEs … and whether and how to apply it to the unit power sales tariff,” FERC said.

The commission added that participants in the case “are free to present evidence supporting the proposed new methodology or supporting a different or revised new methodology.” Briefs are due in two months.

– Amanda Durish Cook

May 5, 2019

NYISO Grid at ‘Inflection Point,’ Report says

By Michael Kuser

NYISO’s electricity markets have reached an “inflection point” as new technologies and “ambitious” public policy goals require the ISO to develop measures to manage the grid’s “next evolution,” according to the ISO’s annual Power Trends report released Thursday.

Last year’s report covered the implications of state policies calling for 50% of the electricity consumed by New Yorkers to come from renewable sources by 2030.

“A year later, however, policymakers seek even more aggressive goals of 70% renewable energy by 2030 and 100% clean energy sources by 2040,” NYISO Executive Vice President Rich Dewey said in a press briefing to discuss this year’s report. The report noted that the ISO is working with stakeholders and policymakers to finish a plan to price CO₂ into wholesale markets to support the state’s goal of reducing emissions. (See More Details Divulged on New NYISO Carbon Pricing Study.)

Annual electric energy usage trends in New York from 2000 to 2018 | *NYISO*

Dewey also highlighted a February proposal by the state’s Department of Environmental Conservation to require peaking units to reduce their emissions of smog-forming pollutants.

“The proposed new rule, which calls for phasing in compliance obligations between 2023 and 2025, could impact approximately 3,300 MW of simple cycle turbines in New York City and Long Island,” he said.

The ISO is engaged in the rule development process and will work to inform policymakers, market participants and investors of the rule’s implications for bulk and local system reliability, but it had no plans to testify at a Tuesday DEC hearing on the subject in Albany, Dewey said.

NYISO has initiated the second phase of its 2018/19 Comprehensive Reliability Plan, which includes a study scenario evaluating the reliability impacts of a potential retirement of all 3,300 MW of peaking units impacted by the DEC’s proposal.

Changing Grid and Goals

“Another trend is the recognition of the need to pay attention to the power transmission infrastructure within New York, both from a transmission and from a generation standpoint, which is aging and needs to be reinvested in to ensure we maintain reliable operation of the system,” Dewey said.

He also highlighted the need to maintain a resilient grid “in light of an uptick in severe storms” and other issues related to climate change.

The Power Trends report also points to a 10-year trend of declining electricity demand in New York, partly because of economic changes, but also increased energy efficiency. The ISO sees demand continuing to decline on EE and behind-the-meter resources, predominantly solar, Dewey said.

“When we look at peak demand, the impact of energy efficiency and behind-the-meter solar will continue to flatten and slightly decrease the need for peak as we move forward into the future,” he said.

Dewey also pointed to the opportunity for storage to become a valuable resource for grid management. The Public Service Commission in December doubled New York’s storage goal to 3,000 MW by 2030 and required the state’s utilities to reduce building energy use by an additional 31 TBtu to meet an EE target of 185 TBtu by 2025. (See NYPSC Expands Storage, Energy Efficiency Programs.)

Forcast electric vehicle energy and peak impacts | *NYISO*

A countertrend to EE is the increasing adoption of electric vehicles, which will put upward pressure on peaks, with a greater impact in winter than in summer because the peak occurs in the evening, which coincides with consumer EV charging habits, Dewey said. The new report takes its load data from the 2019 Gold Book, NYISO’s annual load and capacity forecast, which this year shows EV usage driving a 66% increase in New York’s projected baseline peak demand growth rate over the next two decades. (See NYISO Draft Gold Book Shows EVs Driving Load Growth.)

The report emphasized the ISO’s faith in competitive markets to provide incentives for investment in renewable resources and finance a more robust transmission system to move power to load.

Absent such infrastructure upgrades, investment in upstate New York renewables could yield diminishing returns for the state’s effort to boost renewable energy output and reduce carbon emissions, Dewey said.

“The NYISO believes that competitive wholesale electricity markets remain central to facilitating the accelerated changes policymakers have proposed in a way that will support system reliability and economic efficiency,” the report said.

May 3, 2019

Monitor: PJM Simulation Underestimates ORDC Impact

By Christen Smith

PJM’s Independent Market Monitor said the RTO’s updated simulation results for energy price formation understimate the impact of its operating reserve demand curve (ORDC).

In its own analysis released Friday, the Monitor said PJM’s decision to rely on dispatch conditions that allow the software to decommit resources otherwise required for reliability “presents a significant departure from reality” and results in understated market impacts.

At an April 10 Market Implementation Committee meeting, PJM’s Adam Keech said changing unit commitment based on real-time instead of day-ahead market runs — otherwise known as “Case C” in simulations — increased LMPs, boosted energy revenues and cut uplift by more than 80% compared with the status quo, which staff referred to as “Case A” in simulations. (See “ORDCs Shrink in Updated Energy Price Formation Simulation,” PJM MIC Briefs: April 10, 2019.)

By applying PJM’s proposed ORDC and 30-minute reserve market to conditions set in “Case B,” the simulation increased LMPs by an average of 46 cents/MWh, assigned an additional 1,350 MWh of synchronized reserves and 3,337 MWh of secondary reserves, and generated $550 million more in total energy and reserve market revenues, Keech said.

“If it is the case, and PJM implies that it is, that the ORDC would replace manual operator commitments with market commitments, the relevant comparison is Case A to Case C, because Case A contains the steam unit commitments made by operators,” the Monitor said. “Case B removes all uneconomic operator commitments.”

PJM — Summary results for the five simulation cases | *Monitoring Analytics*

The Monitor’s simulation compared Case C to Case A — defined as PJM’s optimal dispatch conditions — to get what it considers a better measure of real-life market impacts. The comparison shows less uplift, higher LMPs and revenues, with larger impacts than PJM’s Case B to Case C comparison.

The Monitor further cautioned that even Case A conditions do not represent the “actual status quo,” and using it as a benchmark still underestimates real-world costs of PJM’s proposed ORDC approach.

The Monitor’s simulation of an ORDC based on 15-minute forecast errors, compared to PJM’s 30 minutes, resulted in lower price and revenue differences.

“The Market Monitor disagrees with PJM’s conclusion that a 30-minute time horizon is appropriate for the 10-minute reserve products,” the Monitor said. “Case C 15-minute presents a case where the ORDC is shifted inward using a 15-minute forecast time horizon for the synchronized and primary reserve demand curves.”

On Monday, PJM spokesperson Jeff Shields said the RTO stands by its filing and disagrees with the Monitor’s opinion.

“PJM’s simulation analysis was intended to reflect and isolate the impacts of implementing the enhanced ORDCs,” he said. “While PJM acknowledges that there will also be benefits in the form of more optimal commitment and dispatch solutions, PJM does not agree that the entire difference between Cases A and C in the IMM report reflect the anticipated impact of the changes PJM filed on March 29.”

(Updated to reflect that the Monitor’s analysis compared Case A to Case C and found PJM’s simulation underestimates ORDC impact. A previous version of this story said the simulation results were overestimated.)

(Updated to include PJM’s statement.)

May 3, 2019

FERC Upholds PJM Monitor’s Right to Protest Fuel-cost Policies

By Christen Smith

FERC said Monday that the Independent Market Monitor’s filing of complaints regarding PJM’s fuel-cost policies doesn’t violate Tariff conditions or commission rulings, ending — for now, at least — a long-simmering debate over the extent of the IMM’s authority (ER16-372).

Joe Bowring, PJM’s Independent Market Monitor | © *RTO Insider*

The commission denied the RTO’s request for clarification regarding the Monitor’s ability to file complaints regarding issues besides market seller offers in capacity auctions.

The Monitor had protested PJM’s August 2016 proposed Tariff revision regarding the fuel-cost policies that generators submit showing how they calculated their cost-based offers. It said the RTO was trying to usurp its authority to regulate the policies. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)

FERC ultimately sided with PJM in February 2017, saying the changes didn’t alter the fundamental roles of the RTO and the Monitor, “but rather [they] codify the role of the IMM in advising and providing input to PJM in its determination of whether to approve a fuel-cost policy submitted by a market seller.”

But FERC also rejected PJM’s proposal that any disputes between PJM and the Monitor be referred to the commission’s Office of Enforcement, saying that was the province of its administrative law judges.

When the RTO filed further changes on compliance in March, it also filed the clarification request, questioning whether the commission intended “to enable the IMM to initiate a complaint against PJM” when they disagreed over the policies.

“Although PJM is correct that its Tariff explicitly delineates one instance in which the IMM has the right to file a complaint with the commission, the inclusion of an express right to bring a complaint does not necessarily foreclose an entity’s general right to file complaints under Section 206 of the [Federal Power Act],” the commission said. “In any case, we need not reach that issue here because we are unpersuaded by PJM’s narrow reading of Attachment M” of its Tariff.

FERC accepted PJM’s March 2017 compliance filing in the same order. (See FERC Seeks More Details on PJM’s Fuel-Cost Policy Proposal.) The commission accepted the RTO’s clarifications on several issues, including:

Clearly specifying when a penalty for noncompliance with a fuel-cost policy would be terminated by PJM.

Allowing a new resource a 90-day time period before it submits its fuel-cost policy.

Specifying that a market seller may only update its minimum run time for the uncommitted hours in real time and that a market seller’s make-whole payment be based on the minimum run time specified at the time of commitment.

The Tariff and Operating Agreement revisions for the penalty structure became effective May 15, 2017, and the rest of the provisions Nov. 1, 2017.

May 3, 2019

NPCC Sees Lower Summer Peak for 2019

By Rich Heidorn Jr.

The Northeast Power Coordinating Council (NPCC) is projecting a summer peak demand of 103,548 MW in the week of July 28, a 0.6% reduction (589 MW) from last year, despite growth in Ontario.

“This continues an almost decade-long trend of overall flat or declining peak demand forecast due to energy efficiency and conservation initiatives, as well as the significantly increasing role of behind-the-meter PV resources in New England and New York,” NPCC CEO Edward Schwerdt said in a May 2 press release announcing the summer Reliability A ssessment.

With the addition of 2,855 MW of net new capacity since summer 2018, NPCC forecasts a minimum operable capacity margin (spare operable capacity less transfer capability limitations) of 12,545 MW (12.2%) for the summer.

NPCC is the NERC regional entity for New England, New York, Ontario, Québec, New Brunswick and Nova Scotia. The U.S. represents 46% of NPCC’s net energy for load with Canada accounting for 54%. NPCC represents about 70% of Canada’s electric demand.

While New England and New York often hit their summer peaks together because of the proximity of their load centers, “there is some potential” for Ontario’s summer peak to occur at the same time, the report said. “Ambient weather conditions remain the most important variable in forecasting peak demand during the summer months,” it said.

The report included regional snapshots of the changes in generation since summer 2018 and the projected peaks for this year:

New York added a net 127 MW, including 158 MW of wind, with 167 MW of coal generation retirements and 446 MW restored with the withdrawal of Selkirk 1 and 2’s mothball notice. NYISO projects a peak of 32,382 MW, a 522-MW drop from the summer 2018 forecast, because of state energy efficiency programs and the growth of BTM, including retail PV, combined heat and power, anaerobic digester gas, fuel cells and energy storage.
New England added a net of 568 MW, including the dual-fuel Bridgeport Harbor expansion (510 MW), Canal 3 (333 MW) and Medway Peaker (208 MW). Wind and solar generation increased by 135 MW. Entergy’s Pilgrim nuclear plant (680 MW), Massachusetts’ only nuclear unit, is expected to retire by June 1. ISO-NE’s forecast peak is 25,323 MW, 406 MW below last year’s projection. The RTO cited demand reductions from energy efficiency, load management, passive demand response, distributed generation and BTM PV.
Ontario’s generation increased by a net of 1,418 MW, including the Napanee gas-fired generator (985 MW), wind (375 MW), solar (98 MW) and hydro (16.4 MW). About 56 MW of gas-fired generation is retiring. Ontario’s Independent Electricity System Operator forecast a 103-MW increase in peak demand, to 22,105 MW. Conservation savings and distribution-connected generation are expected to partially offset increased demand from economic and population growth.
Québec and the Maritimes, both winter-peaking areas, will see a slight increase, with Québec adding 38 MW of biomass and losing 8 MW of other generation for a net change of 30 MW. Québec is forecasting a 471-MW increase in the peak, to 21,005 MW. The Maritimes expect a peak of 3,255 MW, up 20 MW from last summer.
Entergy’s 680-MW Pilgrim nuclear plant will shut down by June 1. | Entergy

Transmission, Pipelines

Although NPCC expects spare operable capacity (capacity above reserve requirements) of 19,884 MW during its coincident peak the week of July 28, limited transfer capability from Québec and the Maritimes will reduce the amount available to the rest of its territory to 14,954 MW.

Since last summer, NYISO has added the Cricket Valley 345-kV substation — on the Pleasant Valley-Long Mountain 345-kV tie line with New England — to serve the new Cricket Valley combined cycle generating station expected to begin operation after the summer.

Unlike in winter, ISO-NE does not expect natural gas deliverability issues to affect generation. The RTO also can call on 340 MW of active demand resources on the peak.

The RE said it foresees “no significant likelihood” of implementing operating procedures for resource shortages (voltage reductions, and reductions of 10- and 30-minute reserves) during the summer for the expected peak load, a forecast based on the probability-weighted average of seven load levels simulated.

NPCC said operating procedures are available if needed to maintain reliability during severe system conditions and extreme heat simultaneously. The assessment also considered scenarios with extended unit maintenance; reductions in DR; reductions in the ability to import power from neighboring regions; transmission constraints; and widespread and prolonged heat waves with high humidity.

Geomagnetic Disturbances

The RE, which has had operating procedures since 1989 to respond to geomagnetically induced currents (GICs) from solar storms, said it expects “quiet levels” of solar activity for the summer.

“The solar coronal regions are stabilizing as the next solar minimum approaches, with fewer coronal holes and fewer extensions to lower solar latitudes that can sweep higher velocity solar winds toward the Earth,” NPCC said, while acknowledging that sunspot formations are difficult to predict.

While “these rogue events can and do occur,” the report said, “the odds of such an event during any particular week of the coming summer are very low.”

May 3, 2019

Rainwater Exit Leaves Open Seat on MISO Board

By Amanda Durish Cook

MISO’s Board of Directors will hold a special vote to fill the seat of former Director Thomas Rainwater, who left last month to serve on the board of a for-profit energy company outside the RTO’s footprint.

Rainwater was re-elected to the MISO board late last year after having served since early 2015. His new term was set to expire at the end of 2020.

Reached by telephone, Rainwater said he preferred not to reveal the name of the New England waste-to-energy company where he will assume his new role. MISO viewed the two board positions as possibly conflicting.

“Because this opportunity is in a similar or related industry, he is precluded from also continuing as a MISO board member,” the RTO said in a release. It has removed Rainwater’s entry from its leadership webpage.

MISO bylaws stipulate that the board must hold a special vote to fill a vacancy stemming from a director departing before their term expires. Directors will evaluate a pool of candidates provided by an outside executive search firm. Candidates must have the same type of qualifications as the departing board member, and the selected candidate will serve out the remainder of their predecessor’s term.

The special board vote has not yet been scheduled.

Rainwater has 30 years of experience in both the electricity and natural gas sectors and has chaired the board’s Corporate Governance and Strategic Planning Committee and the Audit and Finance Committee.

“Tom has been very generous in sharing his broad experience with the board, MISO staff and our stakeholders over the last four years,” Chair Phyllis Currie said.

Rainwater said he enjoyed his time on the on the board and was leaving with “nothing but praise” for MISO and its work.

Rainwater’s exit comes as a special Advisory Committee task team is re-examining the RTO’s board qualifications, including the possibility of requiring departing directors to observe a “cooling-off” period before joining a MISO-related organization. (See related story, Task Team Begins Look at MISO Board Rules.) Directors drawn from MISO-related companies are already subject to a yearlong industry moratorium before taking a seat on the board.