Page 1193 – RTO Insider

September 23, 2019March 13, 2025

Overheard at Raab Associates’ PJM Energy Policy Roundtable

WASHINGTON — More than 100 stakeholders gathered at the law offices of Morgan, Lewis & Bockius for Raab Associates’ Energy Policy Roundtable in the PJM Footprint. Panelists discussed the potential for storage resources in the RTO’s markets and the state of climate change politics in the U.S.

| © RTO Insider

10 Hours of Providing Energy in PJM as Storage

Scott Baker, senior business analyst for PJM, had to fend off criticism from some of his fellow panelists of the RTO’s compliance filing for FERC Order 841, particularly its requirement that storage offering capacity would have to be capable of continuously supplying electricity for 10 hours.

Scott Baker, PJM | © RTO Insider

At first, panelists were careful about what they said about the proceeding to avoid making ex parte comments, as a FERC staff member was in attendance. Once that staffer left the room, however, their consternation over the requirement became apparent.

“We see the 10-hour qualification requirement in PJM, regardless of the foundation, doesn’t correspond with what we see the [resource adequacy] contribution being,” said Jason Burwen, vice president of policy for the Energy Storage Association. “I think that’s the question: Do we have a rule that actually accords with the reliability contribution of the assets?”

Burwen acknowledged that “PJM has been in the lead on a lot of energy storage issues for quite some time” but that the 10-hour requirement, if approved, “is going to certainly delay the entry of energy storage into capacity markets in PJM.” He said Order 841 “sought to give storage incredible flexibility to be able to do the operations that it can to be the most valuable.”

Jason Burwen, ESA | © RTO Insider

“The 10-hour restriction makes it extremely difficult for small storage assets that we’re aggregating,” said Anne Hoskins, chief policy officer for Sunrun and a former Maryland Public Service Commissioner. “And it wasn’t found to be necessary in” ISO-NE, which proposed a two-hour requirement for storage participating in its capacity market. She touted her company’s Brightbox battery, which she said has helped manage California’s infamous duck curve by storing excess residential distributed solar and flattening load during the evening hours. “These resources can be aggregated and used very effectively … in places like PJM that has some high summer peaks at times.”

Acknowledging that PJM was an “outlier” among the RTOs/ISOs with regards to Order 841, Baker responded, “Simply put, our position has always been that dispatchable resources have a 10-hour requirement, and we operate a capacity market that has a single product today. … In order for resources to compete, to provide the same level of service in that market, there’s a single product that has a single set of requirements. … I would assume that if we were to have some sort of lesser-duration requirement for one resource type, we’d have to evaluate all resource types.”

Hoskins also lamented the stakeholder process in all RTOs, not just PJM. “All of these RTO processes are so complicated and time-consuming and expensive that you’re not going to hear these ideas,” she said. She advised PJM to “keep in mind that many competitive providers, they don’t have recovery from ratepayers for the costs that they spend on this, and this whole issue of governance with RTOs is really, really important right now so that you can actually get all these voices at the table and … have those in-depth conversations about 10 versus eight versus four versus what we can do.”

Left to right: Scott Baker, PJM; Anne Hoskins, SunRun; and Mason Emnett, Exelon vice president of competitive market policy | © RTO Insider

GOP Beginning to Shift on Climate Change

A second panel featured representatives of two D.C.-based think tanks — one from each side of the political spectrum — to explore the common ground Republicans and Democrats can find on clean energy policy.

Josh Freed, senior vice president for clean energy at the center-left Third Way, and Jeremy Harrell, managing director for policy at the conservative ClearPath, talked about each of their organizations’ preferred policies to reduce emissions and prevent the dreaded 2-degree Celsius increase in average global temperatures.

Josh Freed, Third Way | © RTO Insider

Freed said Third Way would like to see the federal government set clear emissions targets across all sectors for states and industry and then provide funding to help meet them. Harrell said ClearPath focuses on policies related to the power sector that would reduce the costs of building clean energy resources, such as carbon capture and energy storage, and increase R&D funding for the public and private sectors.

But they also expressed openness to other policies in service to the ultimate goal.

“We have our preferred approach at Third Way, but there are multiple approaches being debated right now that we’d be happy with,” Freed said. “We are skeptical that a carbon tax is a feasible pathway over the next four or five years, but if somehow magic happened and that was able to pass through Congress and get signed into law, great, we’d be thrilled.”

“In the end, both of our organizations want to see deep emission reductions,” Harrell said. “We want to see a clean American grid and ultimately a cleaner global electricity footprint.”

They also strongly agreed on the importance of advanced nuclear technologies.

Besides the implications for the climate, Freed said the U.S. has “a competitive and economic imperative to invest in” advanced nuclear. “There is [also] a safety and security imperative. Because on nuclear, if we don’t do it, the Russians and the Chinese will, and we don’t have faith that they will follow the same safety, security and proliferation protocols there.”

Jeremy Harrell, ClearPath | © RTO Insider

Harrell said ClearPath spends a third of its time each on nuclear, carbon capture, and renewables and storage. But “I would be lying to you if I didn’t say that, as an organization that works with Republican members of Congress, it’s easier to work with Republicans on advanced nuclear and carbon capture technologies. It just happens to have a significant climate imperative as well.”

And while they both agreed that there has been progress among the GOP in accepting the science of climate change, Freed said the Trump administration is the biggest obstacle, at least in the short term, to large-scale emissions reductions. He ticked off the list of environmental regulations the administration has rolled back, starting with the then-impending revocation of California’s authority to set auto emissions rules that are stricter than federal standards.

He lauded, however, the Department of Energy, “which has been fantastically able to continue on support of the innovation goals that we support and others support.” But “the broader, more comprehensive goals that we need to see set by the federal government that drive demand for clean energy … are being hacked away very quickly and aggressively.”

Harrell was more optimistic and did not directly dispute Freed’s criticism of the administration. But he did say a long-term challenge is the “piecemeal system in place across the country”: different state regulations, different wholesale market structures and different utility goals. “Our regulatory structures are not really well-suited to make those happen, and it’s tough to have a cohesive policy in place even if there was a political environment where we could do a major climate bill,” he said. “I think there will be some type of major federal legislation in the next decade or so, but how do we put forth a policy that makes sense in all these different segmented areas? It’s kind of the beauty and the struggle of federalism.”

– Michael Brooks

September 23, 2019February 12, 2025

NEPOOL Markets Committee Briefs: Sept. 18, 2019

The New England Power Pool Markets Committee voted Wednesday to amend Market Rule 1 to limit the retention of resources needed for fuel security to a two-year maximum.

One abstention from the Transmission sector was recorded.

ISO-NE’s director of NEPOOL relations, Allison DiGrande, delivered a memo arguing that “the change will better align the fuel-security retention rules with the ISO’s goal for reliability concerns to be addressed through competitive solutions, as it will appropriately limit the time and scope of resources retained for fuel security.”

The RTO requested that the change become effective prior to the issuance of the Order 1000 request for proposals targeted for this December. In a presentation in August, the RTO said the change “will help prevent uncertainty … in the development of transmission to meet the Greater Boston Needs Assessment.”

Price-responsive Demand Clean-up Changes

NEPOOL — Henry Yoshimura, ISO-NE | *ISO-NE*

The MC voted to approve clean-up revisions to Market Rule 1 that were identified during the price-responsive demand (PRD) implementation process. One opposition from the Generation sector was recorded.

The RTO’s director of demand resource strategy, Henry Yoshimura, presented two sets of Tariff changes that:

Clarify the energy market offer requirements of demand response resources that participate in the Forward Capacity Market; and
Eliminate the requirement that ISO-NE publish the quantity of demand capacity resources at the end-of-round price for each capacity zone as the FCA is being conducted.

Yoshimura said the energy market offer change was amended slightly from the version presented on Sept. 4 to address a concern that the original proposal could be interpreted to require a market participant with a capacity supply obligation to submit demand reduction offers into the energy market that include avoided transmission and distribution losses for the non-net supply portion of the offer.

Yoshimura, who said that such a requirement would conflict with another section of the Tariff, said the proposal was amended to avoid any misinterpretation.

Order 841 Manual Changes

The MC also voted to recommend Participants Committee support for implementation of manual provisions to encourage electric storage participation in the New England wholesale markets.

One opposition vote from the Generation sector and one abstention from the Supplier sector were recorded.

An RTO development analyst, Catherine McDonough, presented the proposed manual revisions, which also include changes to address a stakeholder concern with how the maximum discharge limit of an electric storage facility is set when it has less than one hour of available energy.

The changes to manuals M-11, M-20, M-35, M-REG, M-RPA and M-36 also include clean-up changes to improve clarity and consistency.

The manual changes pertaining to enhanced storage participation would become effective upon PC approval; the committee’s next meeting is Oct. 4. Changes related to FERC Order 841 compliance would take effect in December 2019 while those that address concerns about discharge limit would be effective in two phases in December 2019 and March 2020.

Assessing EE Resource Performance

The MC discussed the Demand Resources Working Group (DRWG) report issued in July on the measurement and verification of off-peak hour performance of energy efficiency resources. The RTO currently calculates only on-peak hour performance for EERs, passive, non-dispatchable measures.

Yoshimura presented an analysis of five options the working group considered, including calculating a single average hourly demand reduction value for all off-peak hours. Another proposal would shape on-peak savings estimates to all hours based on the relationship between estimated performance under on-peak system conditions (reference load) and all other performance hour system conditions.

Shaping Option A, which would estimate hourly EER performance as a function of established on-peak EER savings and system load levels, received the most support of the options discussed, Yoshimura said, noting that savings and load levels are generally correlated. He said Shaping Option A also was identified as the option requiring the least time and expense to implement.

The other options required obtaining data not previously captured, additional analysis that would increase the cost and require more time to implement or might “not meet current precision and confidence interval requirements,” he said.

Yoshimura said the working group’s report did not represent a consensus behind Shaping Option A, however, noting concerns of some that it could overstate performance.

More Analysis on ESI Impacts

Todd Schatzki of Analysis Group, with ISO-NE economist Christopher Geissler, present ed an evaluation of the impacts of implementing Energy Security Improvements (ESI) to increase generator incentives to secure energy inventory.

The analysis compares the cost and benefits to individual resources that take steps to improve fuel security under various scenarios.

The analysis evaluated inventory decisions by oil-fired resources and forward LNG contracts by gas-only resources. Benefits were identified as the “direct incentives” (revenues) created by ESI through forecast energy requirement (FER) payments and day-ahead energy options. Costs included contractual costs and holding costs for maintaining additional inventory. Analysis Group concluded that ESI would increase incentives for procuring incremental fuel compared to current market rules.

Under the “frequent stressed conditions” scenario, it found that increased revenues from FER payments and day-ahead energy options would exceed additional fuel holding costs for all categories of oil-fired resources. The results were similar under the “extended stress” case.

Under the “infrequent stressed conditions” case, all plants except those with large tanks would have increased incentives for energy inventory.

For oil-fired generators, “ESI unambiguously increases incentives for energy inventory,” Schatzki’s presentation said.

Schatzki also said ESI will provide incentives for gas-only plants to enter into forward LNG contracts compared with the incentives under current market rules. “FER payments increase the value of holding energy inventory by over $2,000/MW in two of three cases,” he said.

— Michael Kuser

September 23, 2019

NYPSC OKs $400 Million Debt for Upstate Tx Project

By Michael Kuser

New York regulators on Thursday agreed to allow the New York Transco consortium of utilities to borrow up to $400 million to upgrade transmission lines running across the state (19-E-0352).

Composed of transmission subsidiaries of Avangrid, Consolidated Edison, National Grid, and Central Hudson Electric and Gas, NY Transco was created to plan, develop and own high-voltage electric transmission facilities in New York. In May, it petitioned the commission to issue up to $400 million in new long-term debt securities to develop and build an electric transmission line referred to as the New York Energy Solutions (NYES) transmission project. Working with National Grid, NY Transco proposed the project through the competitive NYISO Public Policy Transmission Planning process. The project won the endorsement of the ISO’s board in April. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

The NYPSC held its regular monthly session in Albany on Sept. 19.

The first phase of the project includes a new 54-mile, 345-kV line that begins at a new Knickerbocker switching station in Schodack, Rensselaer County, and ends at the substation in Pleasant Valley, Dutchess County. NY Transco said it expects to submit its siting application to the commission in the near future. The project is slated to be operational by the end of 2023.

“Our energy system needs smart transmission projects to move clean power, lower electricity costs, grow the green economy and reduce emissions,” Public Service Commission Chair John B. Rhodes said. “Improvements such as these will benefit all New Yorkers.”

The upgraded high-voltage transmission lines will reduce grid congestion and allow lower-cost electricity and renewable electricity being produced in upstate New York to flow to millions of downstate customers, the commission said.

PSEG Long Island Project Approved

The commission also granted PSEG Long Island, on behalf of the Long Island Power Authority, authority to build and operate the 7-mile Western Nassau transmission project (Case 17-T-0752).

The entire project will be located underground except for portions located at the East Garden City and Valley Stream substations.

“This process is a reminder of what good negotiation with parties looks like,” Rhodes said. “This is a project that’s going to genuinely provide grid and engineering value to the system, and it comes with appropriate and widely endorsed conditions to accommodate community and environmental needs and health considerations.”

PSEG, the state Department of Public Service, the Department of Environmental Conservation, and the villages of Lynbrook and Rockville Centre all supported the joint proposal.

The project in the town of Hempstead, Nassau County, will cross the villages of Garden City, Malverne and Lynbrook, and will mainly be built within the public roadway rights of way with conventional trenching and, where required, horizontal directional drilling.

The project design standards will comply with storm-hardening requirements to withstand a Category 3 hurricane.

September 23, 2019

Entergy Scoops up Miss. Plant to Meet Zone 10 Demand

By Amanda Durish Cook

An Entergy subsidiary will purchase a financially struggling natural gas plant to satiate a need for additional capacity in MISO’s Mississippi territory.

Entergy Mississippi gained FERC approval on Thursday to purchase the 810-MW Choctaw Generating Station near French Camp, Miss., for $314 million from NRG Wholesale Generation (EC19-63).

FERC said the transaction was unlikely to adversely impact rates or competition and would not create a regulatory gap or raise cross-subsidization issues.

The plant, located on the border of the Entergy Mississippi and Tennessee Valley Authority transmission systems, will move from the TVA balancing authority into MISO’s.

The plant will also cease to be operated as merchant generation under Entergy’s ownership. Entergy said it will spend $401.4 million to purchase and upgrade the plant. The company said the amount was “significantly less than the cost to build a comparable facility and eliminates construction time and risks associated with building a new plant, providing more immediate benefits and savings for customers.”

Choctaw was developed as a merchant generating facility, but Entergy and NRG said the plant has been in financial straits since being placed in-service in 2003. The plant was mothballed for about three years from 2004 to 2007, and one of its three combustion turbines was quieted for seven years from 2010 to 2017.

“Choctaw has been and continues to be uneconomic as a merchant facility, and will continue to be uneconomic as a merchant facility for the foreseeable future,” FERC wrote.

Entergy said it has long identified a need for new capacity in MISO’s Local Resource Zone 10. The acquisition will eliminate the utility’s need to build a new combined cycle gas turbine facility to replace retiring generation to meet MISO planning reserve requirements. The subsidiary has been planning since 2016 to build a new plant by 2027, but it bumped up the construction target to 2023 last year. The utility reported that it has recently retired about 700 MW in older generation.

Simplifying matters is the fact that Choctaw is already interconnected with both TVA’s French Camp Substation and Entergy’s Wolf Creek substation in MISO.

The commission also said that if Entergy wants to recover the cost of the transaction in its rates, it must make a separate filing.

Entergy expects the transaction to close by the end of 2019.

The case also revived questions as to whether FERC should examine the entire MISO footprint or simply the MISO South region as the relevant geographic market in acquisitions. While FERC considered the entire MISO footprint for the Choctaw impact analysis, FERC examined just MISO South as the relevant market when approving Cleco’s $1 billion acquisition of eight NRG Energy generation assets there last year. (See FERC Clears Cleco to Buy NRG Generation in South.) Entergy asked about the discrepancy in an additional filing to the Cleco transaction, which FERC also clarified Thursday (EC18-63).

Since the Cleco transaction, MISO South is no longer a submarket onto itself, FERC said, and cited “new evidence based on changing circumstances.”

MISO’s North-South transmission transfer limit is binding less frequently than it used to, the commission explained, adding that in 2018, the constraint only bound in 2% of day-ahead hours and 1.5% of real-time hours. FERC also said the trend of fewer binding hours will continue as new generation is brought online in MISO South.

The “commission will continue this practice of evaluating the definition of a relevant geographic market on a case-by-case basis,” FERC said.

September 23, 2019March 13, 2025

Task Team: Boost Member Role in MISO Board Selection

By Amanda Durish Cook

ST. PAUL, Minn. — A special task team is suggesting that MISO revise its Board of Directors selection rules to give stakeholders a more consequential voice in board makeup.

Exelon’s David Bloom takes notes while Clean Grid Alliance’s Beth Soholt listens. | © RTO Insider

The Board Qualification Task Team (BQTT), composed of MISO stakeholders, last week released a draft of recommendations, including that the RTO double the number of stakeholder representatives on the Nominating Committee that selects board candidates and rotate the sectors from which committee participants are drawn. (See Task Team Zeroes in on MISO Board Recommendations.)

The recommendation would establish four stakeholder seats on the Nominating Committee, outnumbering the three seats reserved for MISO directors. The BQTT also raised the possibility of reserving one of the stakeholder seats for a representative of the Organization of MISO States.

Task team lead David Bloom, of the Power Marketers and Brokers sector, put the recommendations before Advisory Committee members at their meeting Wednesday. The list is still open to suggestions from the committee, which also extended the life of the BQTT through the end of the year to allow it to tweak the recommendations. The AC will vote individually on them at either its Oct. 23 or Dec. 11 meeting.

Also on the list is a recommendation to require state and federal regulators to observe a yearlong “cooling-off” period before becoming eligible for nomination to the board, a policy that currently applies only to those coming out of the industry. However, the change wasn’t labeled a must-have, as the task team also said it would accept if AC members ultimately don’t see a need to extend the moratorium to regulators.

MISO originally required board members with financial ties to the RTO footprint to observe two-year pre- and post-service restrictions, but it reduced those requirements to a one-year pre-service restriction in 2016.

Finally, the task team also presented options for MISO to either designate one of the nine director seats for those with experience representing utility customer interests or create a new process where RTO sectors could describe what qualifications they’re seeking in new board members. The Nominating Committee selects board member candidates in closed deliberations, assisted by management firm Russell Reynolds.

Reaction to the recommendations was mixed, with some AC members asking why the BQTT preferred a stakeholder majority on the Nominating Committee and others asking why all MISO sectors couldn’t be represented on the Nominating Committee at the same time.

Environmental and Other Stakeholder Groups representative Beth Soholt wondered if MISO’s cooling-off period unnecessarily limits the slate of board candidates. In meetings, the BQTT had mulled eliminating the period altogether.

“We note that [former FERC Commissioner Cheryl] LaFleur was appointed to the ISO-NE board without any cooling-off period. In fact, she’s probably red hot,” Soholt joked. (See LaFleur Elected to ISO-NE Board.)

September 23, 2019

Scant Support for 11th MISO Sector

By Amanda Durish Cook

ST. PAUL, Minn. — MISO stakeholders last week signaled that they’re not yet ready to embrace creating an 11th sector in the RTO’s Advisory Committee to accommodate hard-to-pin-down members.

But discussion on the matter will continue as MISO fields a growing number of membership applications from entities that don’t have goals that clearly align with any of the RTO’s 10 existing sectors — the “others” current housed within the increasingly crowded Environmental and Other Stakeholder Groups sector.

By the end of the AC meeting Wednesday, MISO’s Power Marketers and Brokers sector had offered to absorb the “others” into its fold for a yearlong trial period.

Committee Chair Audrey Penner said MISO could use the time as a period of “discovery” to determine the need for a new sector. “This will be an exploratory year, and I’m very interested in who will line up to join our dysfunctional group,” she joked.

The committee last month considered creating a miscellaneous, 11th sector in order to give its Environmental sector a more singular voice. The committee was weighing whether to spin off the “other” contingent from the sector in response to member requests that entities with miscellaneous interests be separated from those with an environmental focus. (See Advisory Committee Considers 11th MISO Sector.)

The move came with many possible AC voting implications, chief among them how to mete out the Environmental sector’s existing two votes. AC leaders proposed several options, including splitting them; allowing the Environmental sector to retain its votes without giving the new sector a vote; or upping the number of committee votes to allow the new sector to participate in voting.

But a poll released last month revealed a majority of sectors preferred no change at all.

MISO — Alcoa’s DeWayne Todd, of the Eligible End-User Customers sector | © *RTO Insider*

Eligible End-User Customers sector representative DeWayne Todd said he wasn’t convinced about the need for a new sector. He cautioned that, because any undefined entity could join, establishing a unified opinion for AC voting matters could prove “cumbersome.”

“We didn’t see a compelling reason to make a change at this point. We created the [Competitive Transmission Developer] sector when there was a need,” Todd said. The Environmental/Other sector housed some competitive transmission developers briefly before the creation of the CTD sector in 2014. The Sustainable FERC Project’s John Moore recalled conversations within the sector during that time as being stifled.

The Independent Power Producers and Exempt Wholesale Generators sector’s Adam Sokolski said he would have appreciated more conversation on exactly what entities would join a catch-all sector.

As a rule, MISO does not reveal the names of companies that approach it for membership until public approval by the Board of Directors. All members must belong to one of the 10 sectors.

However, it’s no secret that multiple “miscellaneous” companies are clamoring for membership.

“We know that there are companies that are approaching MISO that don’t have a home. What that number is, we don’t know,” Penner said. She reminded the sectors that it’s incumbent upon the stakeholder community to be as inclusive as possible. She also said removing hurdles to membership can further FERC’s goal of RTO transparency.

“I’m going to recharacterize this as an opportunity, not a problem, because more around the table is a good thing as far as I’m concerned,” Penner said. “We need a home for entities to join MISO, but it’s clear the Environmental sector is not a good fit.”

The Environmental sector itself voted to drop the “Other Stakeholder Groups” descriptor, retain its two votes and take no action to create a new sector.

“We would hope there would be a way to give someone a voice without creating a new sector,” Clean Grid Alliance’s Beth Soholt said.

David Bloom of the Power Marketers sector offered to draw up a plan to for “others” to join his sector in time for the committee’s Oct. 23 meeting. He said the switch is dependent on existing members’ agreement.

Director Barbara Krumsiek predicted there will be many more “others” in MISO’s future as the RTO’s energy landscape “remains so fluid.”

September 23, 2019

MISO Members Dissect Implications of Grid Change

By Amanda Durish Cook

ST. PAUL, Minn. — The rate of MISO’s grid transformation is at once distressingly slow and unbelievably quick, RTO members said last week in a session directed at guiding future market decisions.

And no one yet knows how high prices could go when renewables have the lion’s share of the market.

Stakeholders selected a rather broad topic for MISO’s quarterly “Hot Topic” discussion, choosing to focus on the pace of change and new directions in the markets and grid strategy during an Advisory Committee meeting Wednesday.

“This isn’t Festivus. This isn’t the airing of grievances,” moderator Kevin Gunn, an energy attorney and former chairman of the Missouri Public Service Commission, joked as he opened the discussion.

Gunn instead urged the committee to advise MISO on big-picture ways it could transform markets.

John Moore, representing the Environmental and Other Stakeholder Groups sector, called for “more active” cooperation between MISO and its participating states, saying that while the RTO appears ready to roll out more market services and products to meet demand, resource adequacy is ultimately the proprietary role of states.

“When you have high levels of renewable energy on the grid, you’re going to want to make sure you can meet the need, and folks on the distribution side of the grid will play a big role in meeting that need,” Moore said.

Arkansas Public Service Commission attorney Christina Baker reminded MISO and members that public service commissions have jurisdiction over utilities but not the data collection companies that could provide visibility into distributed resource participation.

“It’s a wider range sitting at the table than has been before,” she said.

Municipals, Cooperatives, and Transmission Dependent Utilities sector representative Chris Norton agreed that it was going to take much more communication between MISO and distribution facilities to manage supply.

The Independent Power Producers and Exempt Wholesale Generators’ Travis Stewart pointed to the poor financial outlook for merchant suppliers in MISO. He said the harsh winter in the northern footprint reinforced the need for suppliers outside the usual regulated utilities.

“Consumers really needed those electrons on the system to maintain their quality of life and safety,” Stewart said.

“One of the themes … is how fast this needs to happen,” MISO Director Nancy Lange observed, asking for members’ opinions on the necessary rate of market change.

“We need the price signals that will encourage us to build. And we’d like to see those sooner rather than later, because we’re on a 15-year planning horizon for storage builds,” Advisory Committee Chair Audrey Penner said.

Multiple members said the resource mix is changing much faster than MISO’s current transmission planning can accommodate. The IPPs’ Adam Sokolski said more transmission development is needed now.

“Markets, pricing can adapt a lot faster than transmission planning,” Sokolski said “It’s that transmission side, where we’re going to have to speed up that transmission regulatory review and execution.”

Legacy Costs

But Baker pointed out that customers all over the footprint are still paying for coal plant construction, even though coal plants are now generally deemed obsolete.

“We have to be able to balance that rates are still in the past,” Baker said. “Shiny new things are great,” she said, but she urged utilities and MISO to be mindful of the cost of new builds.

Norton agreed that “shiny new toys” saddle customers with legacy costs over multiple decades. Multiple stakeholders also said that while market pricing is very low today, rates in comparison are high because transmission and generation assets are bundled in.

Several stakeholders asked for fair market prices and incentives across all resources.

The Union of Concerned Scientists’ Sam Gomberg said that he perceived tax credits as a means for renewable resources to play catch-up with other heavily subsidized traditional resources. However, he warned MISO that absolute recovery across all resources is unattainable.

“You can’t ask a nuclear plant to follow load; you can’t ask a wind farm to be available next July 15 at 3 p.m.,” he said.

‘Catch-up’ to Corporate America

Transmission Owners sector representative Jeff Dodd said MISO and transmission owners must find a way to accelerate the study of projects in the interconnection queue.

“Everybody sees these corporate renewable goals and these companies saying, ‘We’re going to get there with or without you,’” Dodd said.

“The biggest buyer of renewable energy is Corporate America, not utilities,” Eligible End-User Customers sector representative Kevin Murray pointed out. “So, the train has left the station — we’re playing catch-up.”

Murray also noted that, the very next day, MISO’s board would decide whether to admit Google as a member in the End-User sector, which it ultimately did. (See related story, “MISO, Meet Google,” MISO Board of Directors Briefs: Sept. 18, 2019.)

To the Disruptors, Goes the … Bill?

Baker said that if utilities pivot to catering to industrial customers with renewable appetites, then rates will have to shift so that companies shoulder more costs of sometimes expensive technologies.

“Why are 60% of costs being borne by residential customers?” she asked rhetorically.

Wisconsin Public Service Commissioner Mike Huebsch added a caveat to what he dubbed a “transformative shift on the side of the angels.” He said a transformation must be tempered so reliability doesn’t suffer. He wondered aloud if “Corporate America” is as ready to accept unintended consequences of 100% renewable energy as it is willing to drive the change.

“It’s not going to be an inner-city townhouse in Milwaukee that loses heat; it should be Google that shuts down for an hour,” he said.

“The pace of change is never going to be fast enough for the threat of climate change,” Gomberg added.

TDU sector representative Kevin Van Oirschot said the conversation reminded him of an oft-repeated line of a colleague at Consumers Energy: “The rate of change will never be this fast again, and it will never be this slow again,” he said to laughter. “I think that perfectly captures this moment.”

“‘With all deli b erate speed.’ Got it,” Gunn summed up the members’ conversation, quoting the infamously vague phrase in the Supreme Court’s Brown v. Board of Education decision.

A day after the talk at the board meeting, Board of Directors Chair Phyllis Currie thanked members for at least the consensus that new measures are necessary.

“We all agree that change is coming. We’ve had some deniers in the past,” she said.

September 23, 2019

An End to Carbon-based Spinning Reserves?

By John Funk

MINNEAPOLIS — A frequency response study that NERC engineers began more than two years ago to model the potential impact on the Eastern Interconnection of replacing old coal power plants with wind and solar resources has reached a tentative conclusion that may present market issues to the developers of renewable energy.

The study has concluded that wind and solar generators, which precisely synchronize their power flows into the transmission system with electronic inverters, can respond to frequency disruptions far more quickly than a traditional synchronous machine response, which is based on the speed of governor action on the steam turbines and generators in conventional power plants.

But the catch would be that wind and solar developers would have to set aside some percentage of a wind or solar farm’s generation potential. In other words, the current rules that require transmission organizations to take all of the output of wind and solar whenever it is available would have to be changed.

“It sounds sacrilegious,” explained Robert Cummings, NERC’s senior director of engineering and reliability, who designed the study with his colleague Olushola Lutalo, lead engineer of power system analysis.

“If you really want to make the [transmission] system perform, you can curtail, you can spill wind and spill sun, in order to get a non-carbon-based reserve margin that can outperform anything else you’ve got out there,” he told members of NERC’s Planning Committee.

“If I can curtail solar or wind by 5% instead of reserving very large amounts of head room with synchronous machines, I can outperform the synchronous machines. That is the bottom line,” Cummings said.

Having sufficient backup reserves is a question that electric utilities have had to deal with since the birth of the industry a century ago. For decades, the answer was “spinning reserves,” the practice of keeping certain boilers hot enough to quickly produce power to deal with the failure of other boilers operating to generate power continuously.

“You’ve pointed out very clearly that IBRs [inverter-based resources] can respond faster and perhaps eliminate the need for carbon-based spinning reserves,” consultant Gary Brownfield said. “That’s a huge game changer and paradigm shift for the industry.”

Cummings said he’s been asked, “Are you ever going to get to an all renewables” grid?

“Well, we might get to all renewables, but you’re not going to retire Grand Coulee or Hoover Dam. … And so, you’re still going to have synchronous machines. There might come a time when it makes sense to couple them electronically.”

John Moura, director of reliability assessment and technical committees, said the research has major implications for system planners. “In the future, your largest contingency might not be the huge nuclear units tripping offline. It might be a cloud cover [affecting a large solar farm] in South Carolina.”

Planning Committee members had a lot of questions and comments about the study’s findings. The immediate question was how the sun or wind could be curtailed without paying a solar or wind developer for what in effect would be spinning reserves.

“We are not trying to address the economics or the market issues here,” Cummings said in response to questions that zeroed in on the regulatory implications of such a change. “We are just talking about what you can do with these devices.

“It’s not the mechanics. It’s the politics,” he added when pressed for more detail. “Right now, we are in a mindset of ‘you are going to take all the sun, you are going to take all the wind and you are going to swallow it.’

“You can’t. California is a good example of that with the duck curve. This [situation] is the freshman class trying to drink all the beer in the Ohio State University stadium. You keep on filling the stadium and the class cannot drink that much.”

Cummings, who is a member of the Department of Energy’s E lectricity A dvisory C ommittee, added that he will present the modeling conclusions to the committee next month.

Cummings said NERC’s Inverter-Based Resource Performance Task Force (IRPTF) has been talking with inverter manufacturers to understand the capabilities of inverters as part of the IEEE P2800 project to develop a performance capability standard for IBRs connecting to the bulk power system.

“The [original equipment manufacturers], they’re listening,” Cummings said. “We’re asking them, ‘Can you do this?’ They say, ‘Yeah, we can do that.’ … So, we’re being effective without the standard even yet being in place, because we’re not going to ask them to do something they can’t do. … We’re working really hard to make this a real solution as opposed to an argument. That’s the beauty of the IRPTF.”

Rich Heidorn Jr. contributed to this article.

September 22, 2019

CAISO Takes Step Toward EIM Day-ahead Market

By Hudson Sangree

The effort to expand CAISO’s Western Energy Imbalance Market from a real-time trading platform to a day-ahead market took a significant step forward Wednesday, when members of the ISO’s Board of Governors and the EIM’s Governing Body said they supported launching a stakeholder process in October.

The first step will be an issue paper. Then the stakeholder process is expected to continue well into next year, said Keith Casey, CAISO’s vice president of market and infrastructure development. It will address issues such as resource sufficiency in a tightening Western market and interstate transmission challenges, ISO staff said.

Board Chair David Olsen and EIM Governing Body Chair Carl Linvill gave their verbal support to the stakeholder process; there was no formal vote. The occasion was a briefing on the results of an eight-month feasibility study of the extended day-ahead market (EDAM).

Fourteen current and future EIM entities, in addition to CAISO, participated in the assessment.

The non-CAISO entities wrote a join t letter to ISO and EIM leaders emphasizing they have not committed to the EDAM and want to make sure it addresses a number of concerns, including the continued independence of the Governing Body and the representation of a range of interests from across the West.

A continuing worry among EIM participants is that California politicians and CAISO might try to dominate the regional market. CAISO’s bid to form a Western RTO stalled in part because CAISO’s governors are appointed by the governor and approved by the State Senate.

“The issues to be resolved to make EDAM a reality should not be underestimated,” the entities wrote. Those that signed the letter included Arizona Public Service, Idaho Power and PacifiCorp.

“Governance structures must be considered that reflect the new market design and the legitimate interests that all within the broader market footprint will have in the operation and rules of the day-ahead market,” it said. “In addition, it is likely EDAM will need to include a test to ensure that all participating balancing authorities are not leaning on neighbors to meet their continued reliability obligations.”

Estimated Benefits

A goal of the feasibility study was to estimate the financial benefits to EIM participants to gauge their potential level of interest, Mark Rothleder, CAISO vice president of market quality, told the board and Governing Body.

The EIM has continued to add new members, but some entities from the interior West have cited the economic bonuses as their primary motivation while lamenting the tie to California. The uneasy political alliance is part of the reason SPP recently launched its own Western Energy Imbalance Service. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)

Rothleder said the study group and its consultants, E3 and Brattle Group, had projected the operational benefits of a day-ahead market at $119 million to $227 million annually, which he called a conservative estimate. (In their letter, the EIM entities pointed out that the estimate doesn’t consider how “benefits may be reduced should only a limited number of EIM entities elect to participate in EDAM.”)

The expected financial benefits will come partly through more efficient day-ahead hourly trading and better use of available transmission in an organized market, according to Rothleder’s presentation.

The EIM says its real-time market has saved participants more than $736 million since it began in 2014.

A day-ahead market could limit the curtailment of excess renewable resources by up to 2 GWh a year, sending energy where it’s needed and producing tens of millions of dollars in additional revenue for generators, Rothleder said.

Environmentalists have generally supported regional markets as a way to maximize the sharing of renewable resources, for example, by sending wind energy from New Mexico to California and solar power from California to the Pacific Northwest.

Jennifer Gardner, senior staff attorney with Western Resource Advocates and a member of the committee that nominates Governing Body members, praised the move in a news release. Adding a day-ahead market to the EIM would “allow utilities to better plan for and optimize renewable energy use on the grid through more efficient unit commitment and more effective integration of variable energy resources across a larger footprint,” Gardner said.

Sarah Edmonds, transmission director at Portland General Electric, and Jim Shetler, general manager of the Balancing Area of Northern California, were part of the assessment team. They spoke at Wednesday’s meeting and acknowledged the challenges and effects of a day-ahead market that stretches across the Western Interconnection.

“This is going to be significant and complex,” Edmonds said. “It could have consequences for the Western market as a whole.”

EIM Governance Review

The board and Governing Body also named 10 members of a committee to review the governance structure of the EIM, as required by the market’s original charter. (See CAISO OKs EIM Governance Review.)

The charter recognized that the EIM would evolve over time, and the expansion to a day-ahead market could necessitate governance changes, said Stacey Crowley, CAISO vice president of external affairs.

Members named to the Governance Review Committee (GRC) included Gardner; Therese Hampton, chair of the EIM’s Regional Issues Forum and executive director of the Public Generating Pool in the Pacific Northwest; and Eric Eisenman, PG&E’s director of ISO and FERC relations.

Their colleagues nominated Governing Body member Valerie Fong and CAISO Governor Angelina Galiteva as representatives to the GRC.

Board Chair Olsen said he’s hoping to add another member from the EIM’s investor-owned utilities because he felt the committee was light on IOU representation.

The committee will eventually include 11 to 13 members, said Peter Colussy, CAISO manager of regional affairs.

September 22, 2019

Affected-system Rules Unclear, FERC Says

By Christen Smith

FERC told MISO, PJM and SPP last week that their joint operating agreements don’t provide enough clarity on how the RTOs’ handle generator interconnections along their seams (EL18-26).

The commission agreed in part with EDF Renewable Energy and ordered the RTOs to update their JOAs and Tariffs to make the queue priority process more transparent within 60 days of its ruling Thursday. The commission declined the company’s related request (AD18-8) to expand the review of affected-system coordination in the generation interconnection process beyond MISO, PJM and SPP, however.

“Because the queue priority processes are not described in their tariffs or JOAs, we find that there is a lack of transparency in MISO, SPP and PJM that makes it difficult for interconnection customers to understand how affected-system network upgrade costs are being allocated to them,” FERC wrote. “Requiring the RTOs to detail this information in their JOAs will provide additional transparency to interconnection customers on their potential responsibility for affected system network upgrade costs, thereby reducing uncertainty that may hinder interconnection development.”

FERC advised three RTOs that their Joint Operating Agreements were unclear — | *EDF Renewable Energy*

The order comes nearly 18 months after FERC staff held a technical conference with the RTOs to address the issues raised in EDF’s October 2017 complaint that their governing documents, particularly the JOAs, lack details about the timing of affected-system analyses, the standards applied to determine impacts from proposed interconnections and how network upgrade costs are assigned. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)

FERC Order 2003 requires a transmission provider to coordinate interconnection studies and planning meetings with affected systems — electric systems other than the host transmission provider that may be affected by a proposed interconnection.

EDF argued that the lack of clarity regarding the RTOs’ delivery requirements and modeling standards violates the commission’s requirement for transparent, open-access interconnection service.

FERC said that despite insistence from the RTOs to the contrary, their existing documents lack transparency and cause “harm due to uncertainty” for EDF and other interconnection customers who struggle with decisions about whether to remain in the queue for fear of incurring unknown costs.

“Cost uncertainty presents a significant obstacle to the development of new resources, as some interconnection customers are less able to absorb unexpected and potentially higher costs for interconnection facilities and network upgrades that may occur once affected-system study results are considered,” FERC wrote. “This lack of transparency in the current affected-systems coordination process between MISO, SPP and PJM has the potential to hinder the timely development of new resources and thereby to stifle competition in the wholesale markets, resulting in rates that are not just and reasonable or are unduly discriminatory or preferential.”

The commission, however, rejected EDF’s request that the RTOs unify their modeling systems and study timelines, deeming neither necessary for providing greater transparency.

The RTOs’ compliance filings must include:

Current affected-system coordination processes, including the provision of clear references to where affected-system study information can be found in their business practice manuals;
A description of the modeling standard (external resource interconnection service or network resource interconnection service) they use to study, as the affected RTO, interconnection customers that request ERIS in the host RTO and interconnection customers that request NRIS in the host RTO;
The location in their manuals or other coordination documents where interconnection customers can find the modeling details that they use when studying a project as ERIS or NRIS for interconnection requests on their own systems;
For MISO and SPP specifically, a description of how they study the impacts on the affected RTO and clarify that the each RTO’s study criteria apply to its own facilities;
How the three RTOs monitor each other’s systems during the course of each of their interconnection studies;
PJM’s process for monitoring neighboring systems for affected-system impacts; and
PJM’s timeline provided to interconnection customers to review affected-system study results.