Page 1121 – RTO Insider

September 21, 2018

Emergency Ops, Calm Summer Top Talk at MISO Board Week

By Amanda Durish Cook

ST. PAUL, Minn. — A systemwide emergency, market innovations and the relatively calm summer conditions on the grid topped executive discussions at MISO’s Board of Directors meetings this week.

A Sept. 18 meeting of the Markets Committee of the Board of Directors began with an initial look into MISO’s Sept. 15 declaration of emergency conditions, issued just one a day after the RTO released a forecast showing a 19% chance of such an occurrence at least once this fall. (See MISO in Conservative Ops After Emergency Declaration.)

“Our fall outlook noted the potential for tight conditions, and that has indeed … been the case since Saturday,” MISO Executive Director of Market Operations Shawn McFarlane began.

At the time of the meeting, MISO was still under conservative operations, which remained in effect until Sept. 19.

McFarlane said the emergency was the result of high temperatures and the ramping up of planned fall outages, and noted that MISO lost a “significantly large” unit on Sept. 14, followed by the loss of smaller units the next day. As a rule, MISO does not reveal which companies experience unplanned outages, although Entergy reported that its Grand Gulf Nuclear Station on the Mississippi-Louisiana border went offline Friday because of feedwater system issues.

MISO made about 600 MW of emergency energy purchases during the event and for about 15 minutes exceeded its 3,000-MW north-to-south sub-regional contract limit on the SPP line linking its North and South regions.

However, McFarlane stressed that MISO coordinated with SPP and other parties to the contract ahead of the high flows.

“We will emphasize that we communicated with SPP and others ahead of time,” he said.

MISO Executive Director of Energy Rob Benbow said the RTO made emergency purchases from both SPP and Southern Co. He said that although communications regarding the purchases were effective, some Southern operators were confused about MISO’s process and that the RTO will reach out to company staff to better clarify processes.

Markets Committee of the Board of Directors | © *RTO Insider*

Benbow also said MISO brought in extra staff ahead of the event to oversee the system.

In his chairman’s report at the Sept. 20 Board of Directors meeting, Director Michael Curran praised SPP, Southern and the Tennessee Valley Authority for assisting MISO South during the emergency.

“It was a lot of good things at the seams. We have very good neighbors,” Curran said.

He also added a warning about thin reserves and increasing outages: “It’s not going to be just a weather pattern. … This is going to be the new normal.”

‘Missed’ Forecast

McFarlane said the determining factor in the emergency conditions was a MISO forecast that missed the mark by about 7% of actual conditions.

“A lot of others had difficulty forecasting the heat. It’s not an excuse, but many underestimated the high loads. … I would put this in our top three or four forecast misses. It was a significant miss since we began forecasting in 2005,” McFarlane said.

“This is one of seven forecasts where we missed it by 5% or more,” said MISO President Clair Moeller, adding that most of the midcontinent failed to accurately predict the heat.

Because the forecast became inaccurate so quickly, many units with long lead times could not respond in time, Moeller noted. CEO John Bear added that more fast-start resources will be needed as the generation fleet evolves.

McFarlane also said demand response was difficult to access during the event because of rapid heating and the fact that load-modifying resources aren’t obligated to offer beyond the summer months.

“This is an advertisement for Resource Availability and Need,” McFarlane said, referring to MISO’s initiative to change load-modifying resource and outage coordination rules. (See MISO Moving to Combat Shifting Resource Availability.)

Moeller said MISO is also examining how it plans for system conditions in light of the emergency.

“We’re doing something you shouldn’t do. We’re using historic performance to predict future performance. The question is how to adjust our math,” Moeller said. “The worst thing you can do to a gas pipeline is not give notice and take gas, and that’s what we love to do, not give notice and take gas.”

WPPI Energy’s Valy Goepfrich took the microphone at the board meeting to urge MISO leadership to “R-E-L-A-X.” She said that MISO’s supply has exceeded load for years, and that the RTO and utilities are only experiencing bumps in learning how to effectively balance a more equalized supply-to-load ratio.

Market Innovation

Richard Doying, executive vice president of market development strategy, said MISO is currently researching new distributed resource integration models and how it can use historical data to better compute and manage transmission constraints. The RTO is also continuing ongoing research into how renewable penetration changes the operations and economics of the grid, he said. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)

Richard Doying (left) and David Patton | © *RTO Insider*

Doying said in order to truly develop MISO’s market, RTO staff need to contemplate rebuilding the current system from scratch. He said if MISO were able to revisit 2004 knowing what it knows now, the markets system would have looked very different.

“We probably would have built a very different set of operating procedures,” he said.

MISO is also expanding its overall use of market improvement pilots and simulations, where it can test a full-scale change without impacting the grid, Doying said.

Director Thomas Rainwater urged leadership not to get stuck in a single line of thinking in market innovation, reminding the room that Betamax was once cutting-edge.

Doying said MISO’s ongoing market platform replacement will be flexible enough to accommodate a wide range of future market styles. He said the RTO will release a revised market strategy document in 2019.

However, Independent Market Monitor David Patton said market development should be an “evolution, not revolution,” and told RTO leadership to focus more on the efficient pricing of energy.

Solid Summer Performance

Despite last week’s emergency conditions, MISO said it was able to manage a relatively calm summer.

“There were a few operational challenges and overall — very benign. Nothing like the last few days,” McFarlane said.

“High level summary: It was hot,” he joked.

MISO’s system peaked in late June at 121.6 GW, about a month ahead the usual summer peak, McFarlane said. The RTO had predicted a 125-GW peak. Load averaged 86.6 GW, compared to 82.7 GW during last summer.

Patton said the heat caused a jump in energy prices over last summer, with prices averaging $31.12/MWh over the season, up 8.1% from 2017.

The loss of a 500-kV line in MISO South over June 3-4 highlighted the need to develop a 30-minute reserve product, according to Patton. The line trip caused transmission violations that were priced at $4,000/MW of flow, causing the Louisiana hub price to jump to $2,500/MWh for about an hour-and-a-half late on June 3, he said.

MISO also experienced its lowest wind output in the footprint ever on July 29: 1 MW out of about 18 GW of total wind capacity in the footprint. McFarlane said the RTO and the media often call attention to maximum wind output and wind records but don’t often highlight low wind generation and wind output volatility.

“What are the lessons then?” Rainwater asked.

“We have to be prepared for almost anything. If anyone has a better answer, let me know,” McFarlane said.

September 20, 2018

PJM Monitor Holding Firm on Opportunity Cost Calculator

By Rory D. Sweeney

PJM’s Independent Market Monitor has declined to budge from its position that the RTO allow market participants to use its opportunity cost calculator, arguing that it would be consistent with other RTO verification processes.

pjm opportunity cost calculator — Bowring | © *RTO Insider*

The Monitor suggested that PJM has two options. The first is to maintain the status quo in which stakeholders are required to choose their own values using PJM’s calculators and risk being referred for disciplinary action at FERC — the situation that brought the issue to a boil in August

The Monitor’s preferred process would require market participants come to agreement with it on an opportunity cost that it verifies is competitive before submitting it for PJM approval. All parties retain the right to petition FERC if they don’t agree with the final result. That would result in a practice consistent with the process PJM already uses for verifying cost-based offers, the Monitor said.

“The IMM requests that PJM clarify its preferred review process for opportunity cost calculations,” the Monitor wrote. “The IMM recognizes that PJM can impose the first option. The IMM recommends the second option. … The IMM routinely informs market participants that if its use of the PJM calculator results in an opportunity cost greater than that calculated by the IMM that the IMM is required by the Tariff to raise the issue with FERC.”

The two parties’ yearlong standoff was brought to a head at the August 23 meeting of the Markets and Reliability and Members committees, where stakeholders threatened to advance Tariff revisions that would require PJM to accept the Monitor’s calculator. PJM had announced earlier in the month that it would only accept opportunity cost calculations using its calculator after staff realized that in “the latter part of 2016” results between the two calculators, which had produced consistent results since 2010, began to diverge substantially. (See Stakeholder Proposal Aimed at Ending PJM-IMM Dispute.)

The RTO responded Aug. 29 with a letter outlining its requirements for accepting the IMM’s calculator. (See PJM Sets Terms for Using IMM’s Cost Calculator.)

In its Sept. 16 response, the Monitor said that divergences likely began in 2011 when it “enhanced” its calculator with an “optimization solver … to correctly model rolling constraints.” The Monitor says it outlined the differences between the calculators in meetings with PJM and as part of special sessions of the Market Implementation Committee.

The Monitor’s response included its oft repeated criticism of PJM’s calculator.

“PJM’s opportunity cost calculator demonstrably does not produce accurate results over the entire range of possible scenarios faced by real units. … The IMM has discovered that market participants have made mistakes related to input assumptions that significantly affected the outcomes. … PJM does not review the inputs to its calculator used by participants,” the Monitor wrote. “PJM does not approve the results of its own calculator. Yet PJM states that PJM’s calculator is the standard for evaluating opportunity costs.”

The Monitor said it holds “detailed discussions” with market participants about opportunity cost calculation inputs and results and that it has modified its view of specific calculations considering details provided by participants.

“The IMM has made mistakes. The IMM does not claim that the IMM model is perfect,” the Monitor acknowledged. “While it is important to have a complete and accurate model, opportunity cost calculations require case-by-case analysis and are not a simple matter of just running a model.”

September 19, 2018

NY Study: Minimal Price Impact from Carbon Charge

By Michael Kuser

RENSSELAER, N.Y. — A carbon charge would only slightly impact New York’s wholesale energy prices over the coming decade, with any increase offset by benefits, a new report commissioned by NYISO says.

“If you add a carbon charge, LBMPs are going to increase, and they do,” said Sam Newell of the Brattle Group, who on Monday presented a draft stu d y of carbon pricing impacts to the state’s Integrating Public Policy Task Force (IPPTF). The analysis is based on the ISO’s straw prop o sal issued in May.

This chart shows the broad framework for analyzing the effect of a CO2 charge on the wholesale energy market. | *The Brattle Group*

“The effect of higher LBMPs on customer costs, however, is partially or fully offset by several factors,” Newell said. “Customer credits from emitting resources offset about 60% of the price increase, then you’ve got other potential benefits such as lower prices for renewable energy credits (RECs) and zero-emission credits (ZECs), increased value of transmission congestion contracts, a shift of renewable resources to regions with higher CO₂ emissions to displace and other changes to the supply mix.”

The Sept. 17 discussions were part of issue “Track 5” in the group’s five-track effort to price carbon emissions. Brattle will present the final version of its customer impact analysis to the IPPTF on Oct. 15.

Key Assumptions

The study’s base case scenarios cover 2020, 2025 and 2030, and the study projects the carbon charge will spur the highest cost early on: a 2.2% increase in 2020, followed by a 0.04% increase in 2025 and a 0.01% decline at the end of the next decade.

The base cases reflect “most likely” conditions, supply and demand conditions and existing policies, including the Clean Energy Standard and Regional Greenhouse Gas Initiative, Newell said.

The conclusions are similar to those of the first Brattle Group repo r t, released in August 2017, on pricing carbon into generation offers and reflecting it in energy clearing prices. The main difference between the two reports is that now Brattle has studied three years (2020, 2025 and 2030) and has used GE-MAPS to model the effects of carbon charges on unit commitment, dispatch, prices, settlement and emissions, Newell said.

Several stakeholders wanted to know more about the assumptions used in the report and asked if the ISO would make a more technical report available.

“Nothing is secret,” Newell said.

IPPTF Chair Nicole Bouchez, the ISO’s principal economist, confirmed all data, methodologies and key assumptions would be made available to stakeholders as soon as possible, with an expected availability date around the beginning of October.

Andrew Antinori, senior director of the New York PowerAuthority’s (NYPA) Market Issues Group, said it did not make sense to focus on the higher price increase listed for 2020 ($0.38/kWh) because NYISO recently concluded carbon pricing would not be implemented any earlier than the second quarter of 2021.

Antinori asked if the price would be lower if the study started with 2022, the first full year, but Newell would only say the price increase for that year would fall between those of 2020 and 2025.

NYPA Concerns

Mark Reeder, representing the Alliance for Clean Energy New York, said NYPA sales should be accounted for in the study because many of its customers pay a low non-market price. Therefore, an increase in NYISO market price doesn’t translate into a one-for-one increase in the prices paid by NYPA’s end users.

Warren Myers, DPS director of market and regulatory economics, said, “Whenever we first saw a waterfall chart, NYPA was so complicated, one of our first concerns was we wanted to see a consistent set of analyses of non-NYPA customers.”

This waterfall chart breaks down a carbon charge’s effect on wholesale energy prices. | *The Brattle Group*

The study assumes all customers are fully exposed to the LBMP, so it overstates customer costs to the extent NYPA does not, Newell said. “We didn’t include [NYPA] because it would have been quite messy to try to account for it.”

Mark Younger of Hudson Energy Economics said, “NYPA also does market-based sales for a certain amount of energy, and doing this creates a windfall for a state agency, which presumably goes to New York State residents,” possibly to be used for their benefit.

“Our analysis did not consider any special effects on NYPA,” Newell said.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said profits on market-rate sales would likely incent more such sales, not more low-cost contracts for industrial customers.

Antinori said, “It’s not fair to say ‘windfall’ when discussing NYPA revenues as if no other generator gets such a benefit from a carbon charge.”

Mager said the study might be overstating savings on REC prices: “You identified this in your original report, that it’s not one-to-one price savings.”

Newell said, “There are a number of ways to structure this so there’s no risk on suppliers and you get one-on-one benefits to renewables … We’re using load forecasts that decline by six terawatt hours every five years.”

Environment and Reliability

Tariq Niazi, ISO senior manager and Consumer Interest Liaison, was scheduled to present an ana l ysis of consumer impacts from a carbon charge but got bumped from the lineup due to the length of time spent on the Brattle study.

According to the report, to be presented at next week’s IPPTF meeting, adding a carbon charge would reduce CO₂ emissions approximately 3% by 2030 and cause only limited fuel switching; most emission reductions would result from dynamic effects such as renewable shifts, nuclear retention and price-responsive load.

The report also says pricing carbon would spur investment in renewables, supporting reliability, and the ISO intends to develop a calculation using marginal units to estimate the LBMP carbon impact.

Bouchez informed stakeholders of a revised task force sched u le, which foresees the presentation of a carbon pricing proposal and recommendations on Dec. 17. The task force next meets Sept. 24 at NYISO headquarters.

September 19, 2018

Zero-Emissions Backers Propose PJM Capacity Principles

By Rory D. Sweeney

A coalition consisting of environmental advocates, zero-emissions generators and Illinois’ consumer advocate has developed a set of principles they say will “protect the cost-effective achievement of state policy goals to the extent possible” under FERC’s ordered redesign of PJM’s capacity market.

While the document doesn’t address applicability of PJM’s minimum offer price rule (MOPR), which sets floors for subsidized units’ capacity offers consistently above clearing prices, it does argue any unit subject to the MOPR should be eligible for the resource-specific fixed resource requirement (FRR-RS) FERC suggested in its order.

The principles also call for the FRR-RS to indicate as clearly and as early as possible whether state programs would be subject to the MOPR, along with providing a transition period so states can enact any laws they deem necessary. However, the document reiterated demands the FRR-RS also preserve states’ abilities to achieve clean energy policy goals.

The Natural Resources Defense Council’s Miles Farmer said that “part of it is to push PJM in this direction as well,” pointing out PJM’s proposal has progressively moved toward the principles, and “to make sure that FERC follows through on FRR-RS.”

The signatories “were all talking to each other around these PJM meetings, and we realized it makes sense to develop these shared principles,” he said, though he declined to offer specifics about who approached whom first.

Several stakeholder groups have proposed market redesigns, which stakeholders have been examining as part of special sessions of the Markets and Reliability Committee on the issue. (See PJM Unveils Capacity Pr o posal.) While the coalition is not advocating for any specific proposal along with the principles, many of the signatories support a proposal being represented at the meetings by consultants Rob Gramlich of Grid Strategies and James Wilson of Wilson Energy Economics.

pjm ferc frr fixed resource requirement — Exelon’s Quad Cities nuclear facility, which benefits from Illinois’ zero-emissions credit program. | *Exelon*

An Exelon representative confirmed the proposal is endorsed by “a large coalition of odd bedfellows,” including the NRDC, Citizens Utility Board of Illinois, Sierra Club, Office of People’s Counsel for the District of Columbia, American Council on Renewable Energy, Exelon, Mid-Atlantic Renewable Energy Coalition, Talen Energy and Public Service Enterprise Group. All but PSEG are signatories of the principles document, which also includes the American Wind Energy Association.

Farmer said the principles have just been published and are expected to gather wider support as they become better known, adding no conclusions should be drawn from anyone who hasn’t signed on yet.

The proponents are all interested in PJM giving states capacity credit for units they subsidize to achieve state policy goals, such as procuring renewable and zero-emissions resources, and declare as a principle the credits should be applicable on a one-for-one basis.

For a unit to be eligible for FRR-RS election, it would need to be removed from the auction with a corresponding amount of load. The principle calls for making election at least four months prior to a Base Residual Auction and would need to be confirmed by a load-serving entity or state power authority at least 30 days before the auction.

Owners could also elect portions of units to be FRR-RS, and there would be no minimum length of time the unit would need to remain elected. Those units would continue to be Capacity Performance resources subject to PJM’s performance requirements and financial consequences.

“I take FERC at its word that it’s going to implement FRR-RS, but it still needs to do so in a way that’s workable so all the FRR-RS capacity is actually credited because setting this all up is not trivial and needs to be done with care,” Farmer said.

September 19, 2018

FERC Grants CFE International Access to U.S. Markets

By Tom Kleckner

FERC on Tuesday granted Mexican wholesale marketer CFE International’s request to sell energy, capacity and ancillary services at market-based rates, clearing the way for the company to compete in U.S. power markets (ER18-1778).

The commission noted CFE International would place itself under FERC’s jurisdiction as a public utility and accepted its market-based rate authority, effective July 1. It also agreed with the company’s request for certain waivers and blanket authorizations commonly granted to market-based rate sellers.

Houston-based CFE International was formed in 2015 to market energy commodities. Its only member is Comisión Federal de Electricidad (CFE), the Mexican government-owned electric utility.

FERC ruled CFE International, as it requested, meets the criteria to be a Category 2 seller in the Southwest region (primarily California, Arizona and New Mexico) and a Category 1 seller in the Central, Southeast, SPP, Northeast and Northwest regions.

FERC will review Category 2 market-based rate sellers using the above regions every three years according to a rotating schedule. | *FERC*

FERC created the two categories in 2007 with Order 697. Category 1 sellers are wholesale power marketers or producers that own or control 500 MW or less of generation capacity in aggregate per region; do not own, operate or control transmission facilities, other than interconnection facilities; are not affiliated with transmission owners in the same region as the seller’s generation assets; are not affiliated with a franchised public utility in the same region as the seller’s generation assets; and do not raise other vertical market power issues.

Category 2 sellers are those that don’t fit into Category 1 and are required to file updated market power analyses.

CFE International had to clear FERC screens for horizontal and vertical market power. The commission agreed with the company’s claim that neither it nor its affiliate owns, operates or controls generation capacity in the United States but that CFE owns or contracts with capacity in Mexico. The company said its affiliated generation in Mexico could transfer up to 800 MW to the United States via two interties connected to CAISO, making that market the appropriate one to analyze its horizontal market power.

To pass the vertical power screen, CFE International had to show it had an open-access transmission tariff (OATT) on file or a FERC-approved waiver. Because CFE owns, controls or operates transmission facilities in Mexico that can be used by competitors to reach U.S. markets, CFE International had to prove its affiliate had a tariff or offered “comparable, non-discriminatory access” to its facilities.

The company noted CFE does not control or assign access to its facilities or Mexico’s transmission system, arguing all market participants receive access to the system because of their participation in the energy and ancillary services markets managed by the National Energy Control Center (CENACE) ISO. CFE International said participants could provide transmission service over the interties if CENACE cleared their bids in the day-ahead market.

FERC agreed with CFE International that network service in Mexico is comparable to the services provided under the pro forma tariff (OATT) in the United States.

There are three other interties between Mexico and the United States, all through ERCOT. Texas’ Public Utility Commission, which has jurisdiction over ERCOT, said it saw no issue with the order, pointing to a July ruling by FERC easing concerns over potential federal oversight. (See FERC OKs DC Tie Operations Between Texas, Mexico.)

An SPP spokesperson said the ruling won’t have an effect on its markets. He said, technically, CFE International could have already been making offers into the markets.

September 18, 2018

Overheard at IPPNY 2018 Fall Conference

SARATOGA SPRINGS, N.Y. — The evolving challenges of grid resilience and the past and future of New York’s Reforming the Energy Vision took center stage at the Independent Power Producers of New York’s Annual Fall Conference on Friday.

IPPNY grid resilience REV — IPPNY held their 33rd annual fall meeting in Saratoga Springs on Sept. 14 | © *RTO Insider*

Here’s some of what we heard.

Since its 2014 launch, REV has fostered cultural change at both utilities and the Public Service Commission, said James Gallagher, executive director of the Smart Grid Consortium, a nonprofit group promoting the use of new technologies in New York’s electric power system. “There’s much more flexibility, more openness to change and more collaborating to partner with outside organizations.”

The issue of resilience remains central, but letting go of command and control has not been easy for the utilities as they struggle to incorporate increasing amounts of distributed energy resources, he said.

“The commission invited utilities to come in with what they call ‘Platform Service Revenue Incentives,’ where they would get rewarded for facilitating local markets,” Gallagher said. “No utility has yet to come forward with an incentive proposal.”

Gallagher met former PSC Chair Audrey Zibelman in Australia and asked her what one thing she would change about how the commission handled REV under her leadership.

“Her one regret was that she permitted and encouraged each utility to have their own [Distributed System Platform],” he said. “She would now make one uniform DSP across the state.”

IPPNY CEO Gavin J. Donohue said a key challenge in public clean energy policy is to continue prohibiting utilities from owning generation, for example, in New York’s Energy Storage Roadmap now nearing final approval by the PSC.

On Sept. 10, IPPNY filed comments with the commission regarding energy storage, asserting that “private investors have a greater incentive to lower costs than utilities under cost-of-service regulation,” and that transmission and distribution should be separated from generation to eliminate the potential for generation-owning utilities to exercise vertical market power “to the detriment of wholesale competitive electricity markets and consumers.”

fuel security REV IPPNY — Mahnovski | © *RTO Insider*

Sergej Mahnovski, director of growth and innovation for California-based Edison International, said customer demand, as well as regulation, has driven renewable energy growth.

Mahnovski, who used to work in New York, also said utilities initially dismissed REV as overly complicated, but “I always felt that if 10% of REV worked, it would make a contribution.”

Questionable Benefits

Couch White attorney Kevin M. Lang said he doesn’t think the utilities have changed much under REV, and referred to the second set of Distribution System Implementation Plans filed in June this year.

“All Con Edison reported was what they did the past two years, no cost allocation, no looking forward,” Lang said. “REV was about avoiding $30 billion in infrastructure spending, but now it’s about everything. We’re seeing tens and hundreds of millions of dollars spent for questionable benefits.”

Con Ed’s Brooklyn-Queens Demand Management project was meant to avoid the expense of building a new substation, he said, but some analysts estimate that over its 50-year lifespan, the project might cost $4 billion more than just constructing the substation.

“Consumers will use less electricity, but the reason is because they can’t afford it,” Lang said. “Reducing carbon in the atmosphere is a laudable goal, but we need a sense of balance.”

Industrial companies are leaving New York because they can buy power for a fraction of the price in other states, he said.

Laurence M. Downes, chairman and CEO of New Jersey Resources, a natural gas distributor and developer of clean energy projects, shared his positive take on decades of working with state regulators. New Jersey Gov. Phil Murphy earlier this year appointed Downes as chairman of the state’s Economic Development Authority.

“Since the 1980s, New Jersey has launched a host of public policy initiatives related to environmental stewardship … and as a mainly downstream company, we have come away stronger after every one of those,” Downes said. “If it were not for those public policy initiatives, we would not be serving customers literally in every state in the union right now, being in the solar business and being the leader in energy efficiency.”

Critical National Resource

Electricity is treated as a commodity, but it’s a critical national resource, said Sherrell Greene, president of Advanced Technology Insights.

Greene served as director of nuclear materials programs at Oak Ridge National Laboratory, where he worked for 33 years before founding ATI in 2012.

“Grid resiliency is a classic case of a tragedy of the commons; everybody’s a stakeholder but nobody owns it, nobody controls it,” Greene said. “And resilience does not apply across the board. You may be resilient to a cyberattack, but not to an electromagnetic pulse event.” (See FERC Orders Expanded Cybersecurity Reporting.)

The electric power grid is one of the largest machines ever created, so changing it is a challenge, said Arunkumar Vedhathiri, director of New Energy Solutions at National Grid.

“All of a sudden I have a swimming pool pump that can talk to the grid,” Vedhathiri said. “Consumers are not sure what they want from an energy company, but if you put an interface in front of them, they suddenly have a whole different relationship to their utility.”

He recounted how while on a beach in India last month he got a text message from a colleague telling him to cut energy use on a high peak day. Vedhathiri logged into his thermostat account, changed the setting, and “saved the grid from halfway around the globe.”

NYISO Executive Vice President Richard J. Dewey said New York is home to the oldest power grid in the world, and therefore “has some of the oldest electric infrastructure, which is something to keep in mind as we try to modernize the grid.”

Many New York generating plants also are nearing the end of their design life, he said.

The ISO is “working to establish market rules to appropriately price and value the benefits that renewable resources bring to the grid,” and favors a market approach to achieve whatever resilience characteristics are needed, such as dual-fuel capability, Dewey said. (See NY Debates CO2 Charge for ‘Beneficial’ Load.)

Foundational Fuel Security

Marc Chupka of the Brattle Group recounted the U.S. Department of Energy issued a lauded study of the grid in August 2017, only to be followed in September by a Notice of Proposed Rulemaking to support coal and nuclear plants, which FERC rejected 5-0 in January.

Whether or not the scenario of natural gas curtailments was raised as a “stalking horse” by coal supporters, the controversy did begin the perception of fuel security as a resource attribute, Chupka said.

Fuel security is a New England winter peak issue, said Rob Gramlich, founder and president of energy consultancy Grid Strategies.

“Here we are with another hurricane and the issue is power — not generation, but the distribution and transmission infrastructure,” Gramlich said. “People need to plan for that. Old reliability contingencies don’t include climate change threats.” (See NEPOOL Debates Fuel Security, Cost Allocation.)

Todd Snitchler, director of market development at the American Petroleum Institute, said his group disputes the notion of natural gas being a dirty fuel.

“Brattle helped us with analysis that showed natural gas scoring very well on efficiency attributes, and natural gas is the enabling fuel for many renewable energy resources,” Snitchler said. “Natural gas is not so much a bridge fuel as a foundational fuel.”

— Michael Kuser

September 18, 2018

Overheard at Transmission Summit West

SAN DIEGO — Struggling with a changing landscape of rooftop solar, electric vehicles and Western regionalization, transmission planners voiced their thoughts about an increasingly decentralized grid at Infocast’s 10th Annual Transmission Summit West last week.

“We’re conducting a paradigm shift here. It is not easy to perform transmission planning anymore,” said Bhaskar Ray, a distribution expert with Burns & McDonnell in San Francisco.

Ray sat on one of a dozen panels at the three-day summit, with about 100 in attendance. Speakers addressed topics such as the impacts of community choice aggregation, non-wires alternatives (NWAs) and distributed energy resources.

The overarching theme was a changing market driven by millions of rooftop solar panels and a dramatic increase in the use of EVs, especially in California. The state’s efforts to use 100% clean energy, to create a Western RTO and to spread its energy policies across the West were high on the list of concerns.

“It causes us small heart attacks” when we hear Californians say they are exporting their energy policies, said Kristine Raper, a member of the Idaho Public Utilities Commission, who was part of a panel of state policymakers.

California’s recent passage of SB 100, requiring the state to get all its energy from renewable and carbon-free sources by 2045, and the failure of AB 813, which would have begun the transition of CAISO into an RTO, received a large share of attention. (See California Gov. Signs Clean Energy Act Before Climate Summit.)

Here’s more of what we heard.

Policymakers Debate Regionalization

Energy leaders from Idaho, Utah and other Interior Western states said they’d only be interested in joining an RTO if it served their constituents’ best interests, especially with regard to costs, and if Californians didn’t control it.

“The governance is the piece that causes the most consternation,” Raper said.

AB 813 failed to make it out of the Senate Rules Committee in August, largely because California Democrats weren’t pleased with the idea of their state’s ISO being governed by outsiders from coal-burning states. The bill would have allowed CAISO’s governing body to include out-of-state members.

It was the third time in three years that a regionalization effort in California has failed to move forward. (See Western RTO Proponents Vow To Keep Trying.)

Several panelists at the summit said they didn’t see why it was necessary to have a single RTO in the West, while others were skeptical that any RTO was necessary.

“I don’t think it would be in my state’s best interests to jump two feet into a large-scale RTO,” said Cynthia Hall, vice chair of the New Mexico Public Regulation Commission.

Hall said she’d like to first see the effects of expanding the Western Energy Imbalance Market, possibly to a day-ahead market, which is a more incremental step requiring less commitment on the part of member entities. Public Service Company of New Mexico, for example, applied to join the EIM last month. (See PNM Seeks to Join Energy Imbalance Market.)

California leaders and interest groups had expressed similar sentiments after AB 813 stalled in committee.

In a separate panel on regionalization, Laura Nelson, with the Utah governor’s office, said the pros and cons of a Western RTO have yet to be determined. Market efficiencies could be offset by problems with policy and governance, she said.

“We are concerned about what those costs and risks might be, and we don’t fully understand the benefits,” Nelson said.

DERs Will Prove More Challenging

The increasing role of DERs arose in several panel discussions.

“We see them moving forward aggressively,” said Neil Millar, CAISO executive director of infrastructure development.

The ISO predicts the generating capacity of residential solar panels and other behind-the-meter DERs will grow from about 8,000 MW today to 17,000 MW in the near future, Millar said. That will put a strain on systems that were meant to distribute energy from central power plants, not to gather it from rooftops.

“We have to look at a much broader range of assumptions, scenarios and operating conditions,” he said.

Patrick Damiano, the president and CEO of ColumbiaGrid, agreed.

“DERs are invariably coming to the system,” he said. Utilities will lose control of generation and information, while consumers will gain it, he said.

What’s needed for planning purposes is greater transparency of DER usage and a way to model the effects of so many scattered generation sites, Damiano said. The amount of data that needs to be collected is daunting, he said.

“In some ways that integrative-resources process has become more disintegrated,” he said. “It’s not a statement that it’s a good thing or a bad thing. It’s just reality.”

Non-Wires Alternatives Gaining Ground

The rapid growth of DERs occupied much of the discussion on NWAs, which also include battery storage and other changes to the grid that don’t necessarily involve large-scale infrastructure projects, such as new transmission lines.

Left to right: Seth Hilton of Stoel Rives introduces a panel at Infocast’s Transmission Summit West that included Jennifer Rouda, 7Skyline LLC; Louis Ting, LADWP; Curtis Kirkeby, Avista Utilities; and Aram Shumavon, Kevala | © *RTO Insider*

The inclusion of more NWAs is creating a challenging atmosphere for planners.

Louis Ting, director of planning and development for the Los Angeles Department of Water and Power, said the department is experimenting with numerous pilot projects to serve its 1.5 million customers in the 500 square miles of the city.

“On the non-wires alternatives, it’s been a very interesting journey to say the least,” Ting said. With little room to build new infrastructure, LADWP has been working to optimize its resources, including by leasing rooftops for solar power and talking with EV owners about drawing energy from the vehicles’ batteries, he said.

In the Pacific Northwest, Avista Utilities still mainly relies on traditional modes of generation such as natural gas, but the company is seeing increased interest from its customers in alternatives that allow them to produce their own power, Avista engineer Curtis Kirkeby told the summit audience.

“Our biggest customers are asking how they can play,” including by putting generating assets on their structures, he said. “We’re getting a lot of pressure to have alternatives for them.”

The utility has been working hard to figure how best to incorporate DERs and to become more proactive with planning, he said.

“Transmission planning has been done a certain way forever,” Kirkeby said. Now, he said, “it changes every single day.”

— Hudson Sangree

September 18, 2018

PJM, Generators Debate Injection Rights for Exempted Capacity

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM and some stakeholders are at odds over whether access to the transmission grid is a right generators purchase through interconnection upgrades or an opportunity granted by load to serve its needs. The philosophical difference is playing out in efforts to streamline the process for capacity resources seeking exceptions to offering into Base Residual Auctions.

PJM has proposed allowing generators to request exceptions from multiple auctions at once and allow timing as an acceptable reason for an exception. It also would clarify the documentation required by the RTO and its Independent Market Monitor for being removed from capacity resource status.

pjm capacity injection rights cirs — Lowman Step Up Substation | *Central Alabama Electric Cooperative*

Exelon, which initiated discussion of the issue, offered a proposal that differs from PJM’s only in not requiring a status change for units that are continually approved for an exemption and don’t offer into a BRA after three consecutive delivery years.

That is potentially the difference between whether the unit must relinquish its capacity interconnection rights (CIRs), which grant access to inject generation into the transmission system. If not enough CIRs are available, generators must pay for system upgrades to address their needs or risk not being allowed to sell all the power they can produce. Excess CIRs can have value and be sold.

At last week’s Market Implementation Committee meeting, Gary Greiner with Public Service Electric and Gas supported Exelon’s position, arguing that because generators spend millions of dollars for the upgrades the CIRs are the companies’ property.

Monitor Joe Bowring and ODEC’s Mike Cocco defended PJM’s proposal, arguing that load has spent billions to develop the transmission system that makes the rights possible. Bowring said the CIRs are for units that want to provide capacity for load and that “hoarding” them without committing to provide capacity is “effectively blocking” new units that do want to make that commitment.

“Imagine if [companies] had a benefit to restricting access to other competitors. … That does not make sense,” Bowring said. “If you can’t provide the capacity, it doesn’t make sense to block others who can. … You don’t own the right in perpetuity to inject power into the system because you paid for” necessary upgrades.

“It’s not a ‘forever’ property right. Many of these capacity injection rights were assigned to generators without them incurring any interconnection costs. They have an obligation to clear the capacity market within a three-year time frame or they lose these rights,” Cocco said.

David “Scarp” Scarpignato searched for middle ground.

“I agree with Joe,” he said. “There is a potential hoarding issue here. But there’s also on the other side, people pay for some rights.”

He explained that units that have received exceptions would become uncommitted capacity resources rather than energy-only resources and would keep their CIRs if they pass PJM’s annual deliverability tests.

Exelon’s Jason Barker noted that generators maintain CIRs only until one year after deactivation of the unit, so it “doesn’t exist in perpetuity.”

“The question is whether you’re meeting the requirements of the [Capacity Performance] paradigm, which changes on a regular basis,” he said.

He pointed out that generators’ interconnection service agreements would also need to change and there would be a “necessary discussion” if PJM made a proposal to change them.

Roy Shanker, an economist who often represents individual generators, said the key is determining whether a generator has no intention to offer into the auction or is simply delayed in doing so.

“If you aren’t trying to make progress toward [becoming a CP-compliant unit within three years], it is a form of withholding,” he said. “If you identify a market power issue, you fix it. … All this other stuff is irrelevant.”

September 18, 2018

NERC Circulating Study on ‘Accelerated’ Retirements

By Rory D. Sweeney

VALLEY FORGE, Pa. — Generation reserve margins might drop and fuel-assurance risks could increase if coal and nuclear units retire sooner than anticipated, according to the preliminary findings of a NERC study focused on PJM and ERCOT.

PJM staff confirmed at the RTO’s Planning Committee meeting on Thursday that NERC had discussed the study at its own Planning Committee meeting earlier last week. The draft report has been sent out to members of NERC’s PC for comment, with the reliability overseer planning to present the final version to its Board of Trustees at its meeting on Nov. 6-7.

NERC spokesperson Kimberly Mielcarek said the target for public release is “before the end of the year.”

She declined to provide details before the study is final but pointed to the PC agenda, which outlines the study’s history.

NERC began soliciting policy input in May 2017 from stakeholders, proposing to conduct “an assessment of the potential impacts on Bulk Power System (BPS) reliability that could be caused by accelerated retirements of traditional baseload generator resources … to understand and address reliability challenges associated with the changing resource mix.”

nerc accelerated retirements generation reserve margins — NERC’s report would address accelerated closures of units like the Oyster Creek nuclear plant (shown in 1998), which shut down on Monday.

NERC staff analyzed aggregated supply and demand projections for the study, along with engineering studies on specific retirement scenarios. They also reviewed regional processes for managing plant deactivations.

According to the agenda’s description, the study found that “when generation retirements exceed or outpace needed replacement resources, the BPS is less capable of withstanding contingencies, unplanned facility outages and extreme conditions.”

It added that “replacing retiring coal-fired and nuclear generation with natural gas-fired generation provides essential reliability services but can result in near-term stress on the natural gas infrastructure and create challenges to fuel deliverability in extreme winter conditions and major natural gas contingencies.”

Managing those issues will require “continued adherence to rigorous resource adequacy assessment and transmission planning processes” as “large amounts of generator retirements can result in extensive network upgrade requirements” and “potentially the increased use of out-of-market solutions such as reliability-must-run (RMR) designation to address resource adequacy issues,” NERC said.

September 18, 2018

PJM PC/TEAC Briefs: Sept. 13, 2018

VALLEY FORGE, Pa. — PJM has scheduled a two-day workshop on enabling distributed energy resources to “ride through” frequency fluctuations but postponed action on a task force on the issue in the face of stakeholder concerns.

pjm ride through frequency fluctuations — Bernabeu | © *RTO Insider*

PJM’s Emanuel Bernabeu told the Planning Committee last week that the workshop is the first step in developing a guidance document for how DERs should implement a ride-through standard and presented a problem statement and issue charge to create a DER Ride Through Task Force. The proposal met with immediate concern from representatives of transmission owners, who felt it focused on jurisdictional issues rather than safety and reliability.

“That gives us pause,” FirstEnergy’s Jon Schneider said. “The spirit of this initiative is really to find the right balance … so it can support the bulk transmission system and the distribution system. … What’s resonating is jurisdiction rather than safety.”

“Absolutely what we want to do is what you described,” Bernabeu said.

Duquesne Light’s Tonja Wicks also voiced concerns, including that a focus on interverter-based technologies that was in previous versions of the proposal had been removed. That focus was challenged as not being technology-neutral during the proposal’s first read at last month’s PC meeting, but Wicks said the scope could be overly broad without it.

The reticence threw a wrench in PJM’s plan to receive approval for the task force in advance of the two-day workshop, which has already been scheduled for Oct. 1-2. Bernabeu received no concerns with his explanation of the issue at the monthly Operating Committee meeting earlier last week. There, he highlighted three disturbances within the past 12 years that were triggered by large amounts of renewable generation disconnecting from the grid in response to frequency fluctuations. A 2006 outage in Europe — which Bernabeu called “one of my favorite blackouts” — identified the threat from many small generators collectively tripping in what’s been termed the “50.2-Hz Problem.”

“Basically, they did not have this concept of ride-through,” Bernabeu said, adding that similar issues occurred in two subsequent incidents in Southern California and Australia in 2016. “You would think we would have solved this.”

A challenge in PJM’s territory, he said, is that the vast majority of DERs aren’t under PJM’s authority and instead follow state and local regulations. Staff hope the task force will settle on a standard that can then be provided to state and local regulators as guidance. The issue charge calls for developing a PJM-wide “profile consisting of an abnormal voltage and frequency performance category and specified trip settings, if adjusted from the defaults.” As an alternative, the rule could specify minimum ride-through and trip times and defer to distribution utilities on implementation details, the issue charge said.

The topic isn’t “overly complex,” Bernabeu said, but will require a broad group for input.

“We can’t ignore the fact that it’s the vast majority of DER sources. … What we want to establish is consensus across the footprint on specific standards,” he said. “If we succeed, everyone will embrace it.”

Staff agreed to postpone requesting a vote on the proposal to address TOs’ concerns, but they also asked if there was any issue with holding the workshop as scheduled on an “ad hoc” basis. No one opposed.

Vote Delayed on Capability Testing

Staff had also agreed prior to the meeting to postpone a vote planned on revisions to Manual 21 that would change some of the procedures for generators’ annual capability testing. The proposal has created concern because it could reduce units’ capacity injection rights. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)

PJM’s Patricio Rocha-Garrido also presented an analysis of the effective load carrying capability (ELCC) for wind units. The study calculated ELCC values for each year from 2009 through 2017 using the 12,540 MW of wind units projected to be operating in 2021. It found that the mean ELCC is 11.5% of the nameplate capacity and the median is 10.2%. The numbers backed up PJM’s argument for using median capacity factors for wind rather than mean. The median of capacity factor values PJM calculated for wind output from 2015 to 2017 was 7.9%, while the mean was more than twice as high at 16.7%.

Some stakeholders were critical of the analysis, saying it didn’t account for geographic differences and that using historical numbers for expectations of future performance ignores technology improvements.

“I don’t think we should be using any assumptions on the future, because what do we assume?” Rocha-Garrido said in response. He added that while GEMARS, PJM’s hourly loss-of-load-expectation tool, is capable of more detailed analyses, the study was in relation to the installed reserve margin, which is calculated at the RTO level, so “it’s immaterial to me where [the units] are located.” He acknowledged that units could receive a higher value if they were able to increase their output during the hours tested but said he doesn’t “see a significant difference” between PJM’s methodology and alternatives suggested by stakeholders.

Dave Mabry, representing the PJM Industrial Customer Coalition, said he was still trying to understand the differences between the RTO’s study and a similar study by General Electric that came to different conclusions. He suggested that perhaps ELCC is the metric that should be used for measuring wind capacity.

Rob Gramlich, representing the American Wind Energy Association, criticized what he felt was a low amount of data provided and said he appreciated PJM tabling the vote for further discussion.

“We still have a lot of concerns,” he said.

IRM, FPR Reduced

PJM is recommending a 15.7% IRM and a 1.0887 forecast pool requirement (FPR) for next year’s Base Residual Auction, both of which are slight reductions from last year. The IRM recommendation fell 0.1% and the FPR — which reflects the reserve margin to account for peak loads and generator outages — dropped 0.0011, both based on the 2018 capacity model.

Update on Integrating Cost-containment Guarantees

PJM’s Mark Sims outlined staff’s work on integrating cost-containment guarantees in its analysis of developers’ proposed transmission projects. The five-step process will standardize the cost-containment measures offered in each proposal, present them in a visual way, compare them and allow staff to choose the “most economically efficient” proposal. Sims said it will all be implemented into a comparative matrix and that stakeholders should expect to see more details about each of the five “boxes” in the coming months.

“You would expect to see this as part of the overall decision-making process,” he said. “This is our high-level concept. We are into the weeds with the [Independent Market Monitor] on several of these boxes.”

He said “the most challenging pieces right now are” figuring out how to standardize the proposals and then crunching the numbers to evaluate them. Staff sought input from a “large corporate lender” and are not anticipating lender risk being “a huge factor” in evaluation, he said.

LS Power’s Sharon Segner, who led the effort to incorporate cost guarantees into PJM’s evaluations, voiced her approval of the progress. (See “Delay Approved for Cost Containment Comparisons,” PJM MRC/MC Briefs: Aug. 23, 2018.)

“This is all sounds very good,” she said. “It is a hard assignment, and we very much appreciate what you’re doing. But this is an important discipline to establish.”

First M-3 Experience

Dominion Energy’s Ronnie Bailey briefed stakeholders on 13 violations of its system planning criteria his company plans to correct— implementing for the first time the TOs’ new process for supplemental projects, which is detailed in Tariff Attachment M-3. (See AMP Offers ‘Best We Can Do’ on PJM Tx Planning.)

In accordance with the M-3 processes, Dominion will follow up at a subsequent meeting with how it plans to address the issues.

FERC Orders on Tx in Calif.

PJM and American Municipal Power have agreed to revise their proposals for developing transmission-replacement processes to reflect FERC’s Aug. 31 rulings that Order 890’s transparency provisions do not apply to “asset management” projects that provide only “incidental” increases in transmission capacity.

The orders (EL17-45 and ER18-370, AD18-12), which rejected complaints by California regulators and others, were discussed at a special session of PJM’s Markets and Reliability Committee that met briefly after the Transmission Expansion Advisory Committee meeting. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)

PJM’s Chris O’Hara said the focus during the RTO’s stakeholder process hasn’t included maintenance.

The RTO and AMP will revise their proposals so they can be presented at an Oct. 16 meeting on the issue and prepared for consideration at the Oct. 25 MRC meeting.

“I think the goal from PJM’s perspective is we have an ongoing process and in that process, we want to provide the appropriate level of process and transparency while avoiding any unproductive litigation that may come from it,” O’Hara said.

AMP’s Lisa McAlister said including maintenance has “never been AMP’s goal.”

— Rory D. Sweeney